10-K 1 paceth_10k-123107.htm PACIFIC ETHANOL, INC. paceth_10k-123107.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, 2007

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: Common Stock, $0.001 par value

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

Indicate by check mark whether 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 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. x

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  x
Non-accelerated filer  ¨ (Do not check if a smaller reporting company)
Smaller reporting company  ¨

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 $475.0 million as of June 29, 2007, 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 24, 2008 was 40,674,464.
 
DOCUMENTS INCORPORATED BY REFERENCE:
 
Part III incorporates by reference certain information from the registrant’s proxy statement (the “Proxy Statement”) for the 2008 Annual Meeting of Stockholders to be filed on or before April 30, 2008.


TABLE OF CONTENTS
   
Page
PART I
     
Item 1.
Business
1
Item 1A.
Risk Factors.
13
Item 1B.
Unresolved Staff Comments.
23
Item 2.
Properties.
24
Item 3.
Legal Proceedings.
24
Item 4.
Submission of Matters to a Vote of Security Holders.
26
 
PART II
     
Item 5.
Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
26
Item 6.
Selected Financial Data.
29
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
30
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
34
Item 8.
Financial Statements and Supplementary Data.
51
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
51
Item 9A.
Controls and Procedures
51
Item 9A(T)
Controls and Procedures
57
Item 9B.
Other Information.
38
 
PART III
     
Item 10.
Directors, Executive Officers and Corporate Governance
57
Item 11.
Executive Compensation
57
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
57
Item 13.
Certain Relationships and Related Transactions, and Director Independence
57
Item 14.
Principal Accounting Fees and Services
57
 
PART IV
     
Item 15.
Exhibits, Financial Statement Schedules
57
   
Index to 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
 
Business.
 
Overview
 
Our primary goal is to be the leading marketer and producer of low carbon renewable fuels in the Western United States.
 
We produce and sell ethanol and its co-products 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 and Idaho. 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 our own ethanol production facilities 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.
 
We own and operate two ethanol production facilities located in Madera, California and Boardman, Oregon. Our Madera facility has an annual production capacity of up to 40 million gallons and has been in operation since October 2006. Our Boardman facility has an annual production capacity of up to 40 million gallons and has been in operation since September 2007. In addition, we own a 42% interest in Front Range Energy, LLC, or Front Range, which owns and operates an ethanol production facility with annual production capacity of up to 50 million gallons in Windsor, Colorado. We have two additional ethanol production facilities under construction, in Burley, Idaho and Stockton, California, which are expected to commence operations in the second and third quarters of 2008, respectively. We also intend to either construct or acquire additional ethanol production facilities as financial resources and business prospects make the construction or acquisition of these facilities advisable. See “—Production Facilities.”
 
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Total annual gasoline consumption in the United States is approximately 140 billion gallons. Total annual ethanol consumption represented less than 5% of this amount in 2007. We believe that the domestic ethanol industry has substantial potential for growth to initially reach what we estimate is an achievable level of 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 under the new national Renewable Fuel Standards, or RFS, by 2022. See “—Governmental Regulation.”
 
We intend to reach our goal to be 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, by expanding our relationships with animal feed distributors and end users to build local markets for wet distillers grains, or WDG, the primary co-product of our ethanol production, 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. In addition, we intend to expand our annual production capacity to 220 million gallons in 2008, upon completion of our facilities in Burley, Idaho and Stockton, California, and to 420 million gallons of annual production capacity in 2010, through new construction or acquisition of additional ethanol production facilities. We also intend 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.
 
Company History
 
We are a Delaware corporation formed in February 2005. In March 2005, we completed a share exchange transaction, or Share Exchange Transaction, with the shareholders of Pacific Ethanol, Inc., a California corporation, or PEI California, and the holders of the membership interests of each of Kinergy, LLC, or Kinergy, and ReEnergy, LLC, or ReEnergy. Upon completion of the Share Exchange Transaction, we acquired all of the issued and outstanding shares of capital stock of PEI California and all of the outstanding membership interests of each of Kinergy and ReEnergy. Immediately prior to the consummation of the Share Exchange Transaction, our predecessor, Accessity Corp., a New York corporation, or Accessity, reincorporated in the State of Delaware under the name Pacific Ethanol, Inc.
 
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 these reports are electronically filed with, or furnished to, the SEC. Our common stock trades on the Nasdaq Global Market under the symbol PEIX. The inclusion of our website address in this Report does not include or incorporate by reference into this Report any information contained on our website.
 
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.
 
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· 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.
 
· 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 modern technologies. Our existing production facilities 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. We expect to implement these technologies in new production facilities currently under development and other planned production facilities.
 
· 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 the 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, energy, construction and feed 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.
 
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 market as well as ethanol that we produce.
 
Business and Growth Strategy
 
Our primary goal is to be the leading marketer and producer of low carbon renewable fuels in the Western United States. Key elements of our business and growth strategy to achieve this objective include:
 
· Expand ethanol marketing revenues, ethanol markets and distribution infrastructure. We plan to increase our ethanol marketing revenues by expanding our relationships with third-party ethanol producers to market higher volumes of ethanol throughout the Western United States. In addition, we plan to expand relationships with animal feed distributors and dairy operators to build local markets for WDG. We also plan to expand 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 ultimately as a primary transportation fuel. 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.
 
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· Add production capacity to meet expected future demand for ethanol. We are developing additional ethanol production facilities to meet the expected future demand for ethanol. We are also exploring opportunities to add production capacity through strategic acquisitions of existing or pending ethanol production facilities that meet our cost and location criteria. We intend to expand our annual production capacity to 220 million gallons in 2008, upon completion of our facilities under construction in Burley and Stockton and to 420 million gallons of annual production capacity in 2010 through new construction or acquisition of additional ethanol production facilities.
 
· Focus on cost efficiencies. We plan to develop or acquire 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. 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 enjoy timing and logistical advantages over competing locations which require ethanol to be shipped over much longer distances.
 
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 plan to incorporate advanced design elements into our new production facilities to take advantage of state-of-the-art technical and operational efficiencies.
 
· 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. In addition, we are exploring the feasibility of using different and potentially abundant and cost-effective feedstocks, such as cellulosic plant biomass, to supplement corn as the basic raw material used in the production of ethanol. On January 29, 2008, the Department of Energy included us in a matching award of $24.3 million to build the first cellulosic ethanol demonstration plant in the Northwest United States.
 
· Employ risk mitigation strategies. We seek to mitigate our exposure to commodity price fluctuations by purchasing forward a portion of our corn and natural gas requirements through fixed-price contracts with our suppliers, as well as, entering into derivative instruments to fix or establish a range of 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 associated with index-price contracts by selling exchange-traded unleaded gasoline futures contracts. Proper execution of these risk mitigation strategies can reduce the volatility of our gross profit margins.
 
· 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.
 
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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 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.
 
· 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 RFS designed 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. Furthermore, conditions in Brazil, where ethanol accounts for 40% of all vehicle fuels and is sold in blends with gasoline ranging from 25% to 100%, suggest that ethanol could capture a much greater portion of the United States market in the future.
 
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 $0.51 per gallon tax credit for each gallon of ethanol used in the mixture. Federal law also requires the sale of oxygenated fuels in certain 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 prior national RFS mandated the use of 5.4 billion gallons of renewable fuels in 2008, which was to rise incrementally and peak at 7.5 billion gallons by 2012. The new national RFS significantly increases the mandated use of renewable fuels to 9.0 billion gallons in 2008, which is to rise incrementally and peak at 36.0 billion gallons by 2022. The new national RFS mandates for renewable fuel use increase each year, with corn-based or “conventional” ethanol reaching a peak of 15.0 billion gallons by 2015. Beginning in 2016, increases in the new national RFS targets must be met with advanced biofuels, defined as cellulosic ethanol and other biofuels derived from feedstock other than corn starch. We believe that these increases will bolster demand for ethanol.
 
In January 2007, California’s Governor signed an executive order directing the California Air Resource Board to implement a 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 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.
 
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We believe that the domestic ethanol industry produced approximately 6.5 billion gallons of ethanol in 2007, an increase of approximately 33% from the approximately 4.9 billion gallons of ethanol produced in 2006. We believe that the ethanol market in California alone consumed approximately 1.0 billion gallons in 2007, representing approximately 15% of the national market. However, the Western United States has relatively few ethanol plants 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 cannot be 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 95% of the ethanol produced in the United States is made in the Midwest from corn. According to the United States Department of Energy, 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. Compared to gasoline, ethanol is generally considered to be less expensive and 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.
 
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.
 
Total annual gasoline consumption in the United States is approximately 140 billion gallons and total annual ethanol consumption represented less than 5% of this amount in 2007. We believe that the domestic ethanol industry has substantial potential for growth to initially reach what we estimate is an achievable level of 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 new national RFS by 2022.
 
While we believe that the overall national market for ethanol will grow, we believe that the market for ethanol in certain geographic areas such as California could experience either increases or decreases in demand depending on 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 in the ethanol and 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 such as 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.
 
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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.
 
Overview of Distillers Grains Market
 
According to the National Corn Growers Association, approximately 8.9 million tons of dried distillers grains were produced during the 2005 and 2006 crop year. Dairy cows and beef cattle are the primary consumers of distillers grains. According to Rincker and Berger, in their 2003 article entitled Optimizing the Use of Distiller Grain for Dairy-Beef Production, a dairy cow can consume 12-15 pounds of WDG per day in a balanced diet. At this rate, the WDG output of an ethanol facility that produces 35 million gallons of ethanol per year can feed approximately 105,000-130,000 dairy cows.
 
Successful and profitable delivery of DDGS from the Midwest faces a number of challenges, including product inconsistency, handling difficulty and lower feed values. All of these challenges are mitigated with a consistent supply of WDG from a local plant. DDGS delivered via rail from the Midwest undergoes an intense drying process and exposure to extreme heat at the production facility and in the railcars, during which various nutrients are burned off which reduces the nutritional composition of the final product. In addition, DDGS shipped via rail can take as long as two weeks to be delivered to the Western United States, and scheduling errors or rail yard mishaps can extend delivery time even further. DDGS tends to solidify and set in place as it sits in a rail car and thus expedient delivery is important. After solidifying and setting in place, DDGS becomes very difficult and thus expensive to unload. During the summer, rail cars typically take a full day to unload but can take longer. Also, DDGS shipped from the Midwest can be inconsistent because some Midwest producers use a variety of feedstocks depending on the availability and price of competing crops. Corn, milo sorghum, barley and wheat are all common feedstocks used for the production of ethanol but lead to significant variability in the nutritional composition of distillers grains. Dairies depend on rations that are calculated with precision and a subtle difference in the makeup of a key ingredient can significantly affect bovine milk production. By not drying the distillers grains and by shipping WDG locally, we believe that we will be able to preserve the feed integrity of these grains.
 
Historically, the market price for distillers grains has been stable in comparison to the market price for ethanol. 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. We also believe that nationwide, the market price of distillers grains historically has been influenced by producers of distilled spirits and more recently by the large corn dry-millers that operate fuel ethanol plants. The market price of distillers grains is also often influenced by nutritional models that calculate the feed value of distillers grains by nutritional content.
 
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Customers
 
We produce and also purchase from 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. Our revenue is obtained primarily from sales of ethanol to large oil companies. We began producing ethanol in the fourth quarter of 2006.
 
During 2007, 2006 and 2005, we produced or purchased from third parties and resold an aggregate of approximately 191 million, 102 million and 67 million gallons of fuel-grade ethanol to approximately 61 customers, 60 customers and 27 customers, respectively. Sales to our two largest customers in 2007 represented approximately 32% of our net sales. Sales to our two largest customers in 2006 represented approximately 25% of our net sales. Sales to our three largest customers in 2005 represented approximately 39% of our net sales. Customers who accounted for 10% or more of our net sales in 2007 were Chevron Products USA and Valero Marketing. Customers who accounted for 10% or more of our net sales in 2006 were New West Petroleum and Chevron Products USA. Customers who accounted for 10% or more of our net sales in 2005 were New West Petroleum, Chevron Products USA and Southern Counties Oil Co. Sales to each of our other customers represented less than 10% of our net sales in each of 2007, 2006 and 2005.
 
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, which has resulted in increased sales and higher margins. 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 such as 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 expect to be 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 our ethanol production facilities.
 
Suppliers
 
Our marketing operations are dependent upon various producers of fuel-grade ethanol for our ethanol supplies. 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. We also transport ethanol with our own fleet of railcars, which we intend to expand to support the continuing growth of our business.
 
During 2007, 2006 and 2005, we purchased an aggregate of approximately 99 million, 88 million and 67 million gallons of fuel-grade ethanol from approximately 33 suppliers, 22 suppliers and 15 suppliers, respectively. Purchases from our four largest ethanol suppliers in 2007 represented approximately 68% of our total ethanol purchases. Purchases from our three largest ethanol suppliers in 2006 represented approximately 50% of our total ethanol purchases. Purchases from our three largest ethanol suppliers in 2005 represented approximately 59% of our total ethanol purchases. Purchases from each of our other suppliers represented less than 10% of total ethanol purchases in 2007, 2006 and 2005.
 
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Our ethanol production operations 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 plant 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 and planned grain receiving facilities at our current and planned ethanol plants are or will be some of the most efficient grain receiving facilities in the United States. We source corn using standard contracts, such as spot purchases, forward purchases and basis contracts. We seek to limit our exposure to raw material price fluctuations by purchasing forward a portion of our corn requirements on a fixed price basis and by purchasing corn and other raw materials futures contracts. In addition, to help protect against supply disruptions, we typically maintain inventories of corn at each of our facilities.
 
Production Facilities
 
The table below provides an overview of our existing ethanol production facilities and our facilities under construction.
 
 
Madera
Facility
 
 
Front Range
Facility(1)
 
 
Boardman
Facility
 
 
Magic
Valley
Facility(2)
 
 
Stockton
Facility(2)
Location
Madera, CA
 
Windsor, CO
 
Boardman, OR
 
Burley, ID
 
Stockton, CA
Quarter/Year completed or scheduled to be completed
4th Qtr., 2006
 
2nd Qtr., 2006
 
3rd Qtr., 2007
 
2nd Qtr., 2008
 
3rd Qtr., 2008
Annual design basis ethanol production capacity (in millions of gallons)
35
 
40
 
35
 
50
 
50
Approximate maximum annual ethanol production capacity (in millions of gallons)
40
 
50
 
40
 
60
 
60
Ownership
100%
 
42%
 
100%
 
100%
 
100%
Primary energy source
Natural Gas
 
Natural Gas
 
Natural Gas
 
Natural Gas
 
Natural Gas
Estimated annual WDG production capacity (in thousands of tons)
293
 
335
 
293
 
418
 
418
———————
(1)                 We own 42% of Front Range, the entity that owns the facility located in Windsor, Colorado.
(2)                 Data is estimated as of completion of construction.
 
Site Location Criteria
 
Our site location criteria encompass many factors, including proximity of feedstock, fuel blending facilities and major rail lines, good road access, water and utility availability and adequate space for equipment and truck movement. One of our primary business and growth strategies is to develop or acquire 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. Therefore, it is critical that our production sites are located near fuel blending facilities in the Western United States because many of our competitors ship ethanol over long distances from the Midwest. Also, because our planned facilities are expected to be located in the Western United States, close proximity to major rail lines to receive corn shipments from Midwest producers is critical.
 
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Potential Future Facilities and Expansions
 
We intend to expand our production capacity to 220 million gallons of annual production capacity in 2008 upon completion of our facilities in Burley and Stockton and to 420 million gallons of annual production capacity in 2010, through new construction or acquisition of additional ethanol production facilities. In 2007, we began development of an ethanol production facility in the Imperial Valley near Calipatria, California; however, construction has been suspended until market conditions improve and we are able to obtain adequate financing. We will determine whether additional sites are suitable for construction of ethanol production facilities in the future. We intend to evaluate and pursue opportunities to acquire additional ethanol production, storage and distribution facilities and related infrastructure currently in operation 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. We are also investigating the feasibility of expanding one or more existing facilities to significantly increase production capacity. Such an expansion would entail constructing additional structures and systems adjacent to an existing facility and integrating certain processes.
 
Marketing Arrangements
 
We have exclusive agreements with third-party ethanol producers, including Phoenix Bio-Industries, LLC, a subsidiary of Altra Inc., and Front Range, the latter of which we are a minority owner, to market and sell their entire ethanol production volumes. Phoenix Bio-Industries, LLC owns and operates an ethanol production facility in Goshen, California with annual nameplate production capacity of 25 million gallons. Front Range owns and operates an ethanol production facility in Windsor, Colorado with annual production capacity of up to 50 million gallons. We also have an exclusive agreement to market and sell WDG produced at the facility owned by Front Range. 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 producer in the United States is ADM, with wet and dry mill plants in the Midwest and a total production capacity of about 1.1 billion gallons per year, or approximately 17% of total United States ethanol production in 2007. According to the RFA, there are approximately 134 ethanol plants currently operating with a combined annual production capacity of approximately 7.2 billion gallons. In addition, we believe that approximately 50 new ethanol plants or expansions of existing plants are currently under construction with an estimated combined future annual production capacity of approximately 4.4 billion gallons. We believe that most of the growth in ethanol production over the last ten years has been by farmer-owned cooperatives that have commenced or expanded ethanol production as a strategy for enhancing demand for corn and adding value through processing. We believe that many smaller ethanol plants rely on marketing groups such as Ethanol Products, Aventine Renewable Energy, Inc. and Renewable Products Marketing Group LLC to move their product to market. We believe that, because ethanol is a commodity, many of the Midwest ethanol producers can target the Western United States, though ethanol producers further west in states such as Nebraska and Kansas often enjoy delivery cost advantages.
 
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.
 
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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, such as corn, which generally must be transported from the Midwest. If the costs of producing and shipping ethanol and its co-products over short distances is 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 extensive and frequently changing federal, state and local laws and regulations relating to the protection of the environment. 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:

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restrictions on our existing and proposed business operations and/or the need to install enhanced or additional controls;
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the need to obtain and comply with permits and authorizations;
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liability for exceeding applicable permit limits or legal requirements, in certain 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
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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
 
Ethanol blends have been either wholly or partially exempt from the federal excise tax on gasoline since 1978. The exemption has ranged from $0.04 to $0.06 per gallon of gasoline during that 25-year period. 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 $0.51 per gallon tax credit for each gallon of ethanol used in the mixture. The federal excise tax exemption was revised and its expiration date was extended for the sixth time since its inception as part of the American Jobs Creation Act of 2004. The new expiration date of the federal excise tax exemption is December 31, 2010. We believe that it is highly likely that this tax incentive will be extended beyond 2010 if Congress deems it necessary for the continued growth and prosperity of the ethanol industry.
 
Clean Air Act Amendments of 1990
 
In November 1990, a comprehensive amendment to the Clean Air Act of 1977 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.
 
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Oxygenated Fuels Program
 
Federal law requires the sale of oxygenated fuels in certain 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 in subsequent years may also be included in the program. The Environmental Protection Agency, or 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 our Madera facility, 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 all of the Northeast and middle Atlantic areas from Washington, D.C. to Boston not under the federal mandate have “opted into” the federal standards.
 
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 prior national RFS mandated the use of 5.4 billion gallons of renewable fuels in 2008, which was to rise incrementally and peak at 7.5 billion gallons by 2012. The new national RFS significantly increases the mandated use of renewable fuels to 9.0 billion gallons in 2008, which is to rise incrementally and peak at 36.0 billion gallons by 2022. The new national RFS mandates for renewable fuel use increase each year, with corn-based or “conventional” ethanol reaching a peak of 15.0 billion gallons by 2015. Beginning in 2016, increases in the new national RFS targets must be met with advanced biofuels, defined as cellulosic ethanol and other biofuels derived from feedstock other than corn starch.
 
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. We believe other states may also enact their own renewable fuel standards.
 
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In January 2007, California’s Governor signed an executive order directing the California Air Resource Board to implement a 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 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.
 
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 California Air Quality Management District, 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 24, 2008, we employed approximately 220 persons on a full-time basis, including through our subsidiaries. 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 who 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.
 
Risk Factors.
 
Risks Related to our Business
 
We have incurred significant losses and negative operating cash flow in the past and we may incur significant losses and negative operating cash flow in the future. Continued losses and negative operating cash flow may hamper our operations and prevent us from expanding our business.
 
We have incurred significant losses and negative operating cash flow in the past. For the years ended December 31, 2007, 2006 and 2005, we incurred net losses of approximately $14.4 million, $142,000 and $9.9 million, respectively. For the year ended December 31, 2006, we incurred negative operating cash flow of approximately $8.1 million. We expect to rely on cash on hand, cash, if any, generated from our operations and cash, if any, generated from our future financing activities to fund all of the cash requirements of our business. Continued losses and negative operating cash flow may hamper our operations and prevent 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 satisfactory terms.
 
Various factors could result in inadequate working capital to fully fund our operations or meet our capital expenditure requirements, or both.
 
If ethanol production margins deteriorate from current levels, if we experience additional cost overruns at our ethanol production facilities under construction, if our capital requirements or cash flows otherwise vary materially and adversely from our current projections, or if other adverse unforeseen circumstances occur, our working capital may be inadequate to fully fund our operations or meet our capital expenditure requirements, or both, which may have a material adverse effect on our results of operations, liquidity and cash flows and may restrict our growth and hinder our ability to compete.
 
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We are seeking additional financing and may be unable to obtain this financing on a timely basis, in sufficient amounts, on terms acceptable to us or at all. Any financing we are able to obtain may require us to accept financing on burdensome terms that may cause significant dilution to our stockholders and impose onerous financial restrictions on our business.
 
We are seeking substantial additional financing. Deteriorating global economic and debt and equity market conditions may cause prolonged declines in lender and investor confidence in and accessibility to capital markets. Future financing may not be available on a timely basis, in sufficient amounts, on terms acceptable to us or at all. Any equity financing may cause significant dilution to existing stockholders. Any debt financing or other financing of securities senior to our common stock will likely include financial and other covenants that will restrict our flexibility. At a minimum, we expect these covenants to include restrictions on our ability to pay dividends on our common stock. Any failure to comply with these covenants could have a material adverse effect on our business, prospects, financial condition and results of operations because we could lose any then-existing sources of financing and our ability to secure new financing may be impaired. In addition, any prospective debt or equity financing transaction will be subject to the negotiation of definitive documents and any closing under those documents will be subject to the satisfaction of numerous conditions, many of which could be beyond our control. We may be unable to obtain additional financing from one or more lenders or equity investors, or if funding is available, it may be available only on burdensome terms that may cause significant dilution to our stockholders and impose onerous financial restrictions on our business.
 
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 1.7 billion gallons per year in January 1999 to 7.2 billion gallons per year according to the RFA. In addition, we believe that a significant amount of ethanol production capacity—approximately 4.4 billion gallons per year—is currently under construction. This production capacity is being added to address anticipated increases in demand, including from increased volume requirements under the Energy Independence and Security Act of 2007. 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 could occur as a result of increased gasoline or oil prices. Increased ethanol production could also have other adverse effects. For example, increased ethanol production could lead to increased supplies of co-products generated from ethanol production, such as WDG. Those increased supplies could lead to lower prices for those co-products. Also, increased ethanol production could result in increased demand for corn. Increased demand for corn could cause higher corn prices, resulting in higher ethanol production costs and lower profit margins. We believe that significantly higher corn prices and lower profit margins throughout 2007 were predominantly caused by increased demand for corn resulting from increased ethanol production. Accordingly, 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.
 
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The raw materials and energy necessary to produce ethanol may be unavailable or may increase in price, adversely affecting our business, results of operations and financial condition.
 
The principal raw material we use to produce ethanol and its co-products is corn. Changes in the price of corn can significantly affect our business. In general, rising corn prices result in lower profit margins and, therefore, represent unfavorable market conditions. This is especially true since market conditions generally do not allow us to pass along increased corn prices to our customers because the price of ethanol is primarily determined by other factors, such as the supply of ethanol and the price of oil and gasoline. At certain levels, corn prices may even make ethanol production uneconomical depending on the prevailing price of ethanol.
 
The price of corn is influenced by general economic, market and regulatory factors. These factors include weather conditions, crop conditions and yields, farmer planting decisions, government policies and subsidies with respect to agriculture and international trade and global supply and demand. The significance and relative impact of these factors on the price of corn is difficult to predict. Any event that tends to negatively impact the supply of corn will tend to increase prices and potentially harm our business. Average corn prices as measured by the Chicago Board of Trade increased 44% from 2006 to 2007. The United States Department of Agriculture’s December 2007 crop report estimated that corn bought by ethanol plants will represent approximately 22% of the 2007/2008 crop year’s total corn supply, up from 17% in the prior crop year. We believe that significantly higher corn costs and lower profit margins throughout 2007 were substantially caused by increased demand for corn resulting from increased ethanol production. Additional increases in ethanol production could further boost demand for corn and result in further increases in corn prices.
 
Our business also depends on the continuing availability of rail, road, port, storage and distribution infrastructure. In particular, due to limited storage capacity at our production facilities and other considerations related to production efficiencies, we 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 our facilities will need or may not be able to supply those resources on acceptable terms. Any disruptions in the ethanol production infrastructure network, 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 us to halt production which could have a material adverse effect on our business, results of operations and financial condition.
 
Numerous factors may prevent us from implementing our planned expansion strategy.
 
Our strategy envisions a period of rapid growth. We plan to grow our business by investing in new facilities and/or acquiring existing facilities or sites under development as well as pursuing other business opportunities such as the production of other renewable fuels to the extent we deem those opportunities advisable. We believe that there is increasing competition for suitable production sites. We may not find suitable additional sites for construction of new facilities, suitable acquisition candidates or other suitable expansion opportunities.
 
We will need substantial additional financing to achieve our business objectives and we may not have access to the funding required for the expansion of our business or funding may not be available to us on acceptable terms. We plan to fund the expansion of our business with additional debt and equity financing. We could face financial risks associated with incurring additional indebtedness, such as reducing our liquidity and access to financial markets and increasing the amount of cash flow required to service such indebtedness, or associated with issuing additional stock, such as dilution of ownership and earnings. In addition, we are planning the financing of our expansion strategy and we are initially using our existing cash to implement this strategy based on the belief that we can secure additional debt and equity financing in the future in order to complete our expansion. If we are unable to secure this debt and equity financing, we may suffer from an acute lack of capital resources, our planned expansion strategy may be less successful than if we had planned solely on using our existing cash to finance our expansion, and our business and prospects may be materially and adversely affected.
 
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We must also obtain numerous regulatory approvals and permits in order to construct and operate additional or expanded production facilities. These requirements may not be satisfied in a timely manner or at all. Federal and state governmental requirements may substantially increase our costs, which could have a material adverse effect on our results of operations and financial condition. Our expansion plans may also result in other unanticipated adverse consequences, such as the diversion of management’s attention from our existing operations.
 
Our construction costs may also increase to levels that would make a new production facility too expensive to complete or unprofitable to operate. We do not have any fixed-price construction contracts and we have experienced significant cost-overruns in the past and may experience additional cost-overruns in the future. Contractors, engineering firms, construction firms and equipment suppliers also receive requests and orders from other ethanol companies and, therefore, we may not be able to secure their services or products on a timely basis or on acceptable financial terms. We may suffer significant delays or cost overruns as a result of a variety of factors, such as shortages of workers or materials, transportation constraints, adverse weather, unforeseen difficulties or labor issues, any of which could prevent us from commencing operations at our facilities as expected.
 
Rapid growth may impose a significant burden on our administrative and operational resources. Our ability to effectively manage our growth will require us to substantially expand the capabilities of our administrative and operational resources and to attract, train, manage and retain qualified management, technicians and other personnel. We may be unable to do so.
 
We 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, we often enter into contracts to supply a portion of our ethanol production or purchase a portion of our corn or natural gas requirements on a forward basis. In addition, we 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 we have futures contracts. We also engage in hedging transactions involving interest rate swaps related to our debt financing activities, the financial statement impact of which is dependent upon, among other things, fluctuations in prevailing interest rates. 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. Hedging activities can themselves result in losses when a position is purchased in a declining market or a position is sold in a rising market. A hedge position for a physical commodity is often settled in the same time frame as the physical commodity is either purchased or sold. Certain hedging losses may be offset by a decreased cash price for corn and natural gas and an increased cash price for ethanol. We also vary the amount of hedging or other risk mitigation strategies we undertake, and from time to time we may choose not to engage in hedging transactions at all. As a result, our results of operations and financial position may be adversely affected by fluctuations in the price of corn, natural gas, ethanol, unleaded gasoline and prevailing interest rates.
 
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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 in 2007 declined by approximately 6% from our 2006 average sales price per gallon, but increased 37% in 2006 from our 2005 average sales price per gallon. Fluctuations in the market price of ethanol may cause our profitability or losses to fluctuate significantly.
 
We have identified two material weaknesses in our internal control over financial reporting and cannot assure you that additional material weaknesses will not be identified in the future. If our internal control over financial reporting or disclosure controls and procedures are not effective, there may be errors in our financial statements that could require a restatement or our filings may not be timely and investors may lose confidence in our reported financial information, which could lead to a decline in our stock price.
 
Section 404 of the Sarbanes-Oxley Act of 2002 requires us to evaluate the effectiveness of our internal control over financial reporting as of the end of each year, and to include a management report assessing the effectiveness of our internal control over financial reporting in each Annual Report on Form 10-K. Section 404 also requires our independent registered public accounting firm to attest to, and report on, management’s assessment of our internal control over financial reporting. We have identified the following two material weaknesses in our internal control over financial reporting that existed as of December 31, 2007:  (i) we did not have adequate internal control over our accrual of construction-related costs for our ethanol production facilities; and (ii) we did not exercise oversight of our personnel or their actions in a manner reasonably calculated to ensure compliance under the Credit Agreement governing our credit facility. See “Controls and Procedures.”
 
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal control over financial reporting will prevent all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be 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. Controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. Over time, controls may become inadequate because changes in conditions or deterioration in the degree of compliance with policies or procedures may occur. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.
 
As a result, we cannot assure you that significant deficiencies or material weaknesses in our internal control over financial reporting will not be identified in the future. Any failure to maintain or implement required new or improved controls, or any difficulties we encounter in their implementation, could result in significant deficiencies or material weaknesses, cause us to fail to timely meet our periodic reporting obligations, or result in material misstatements in our financial statements. Any such failure could also adversely affect the results of periodic management evaluations and annual auditor attestation reports regarding disclosure controls and the effectiveness of our internal control over financial reporting required under Section 404 of the Sarbanes-Oxley Act of 2002 and the rules promulgated thereunder. The existence of a material weakness could result in errors in our financial statements that could result in a restatement of financial statements, cause us to fail to timely meet our reporting obligations and cause investors to lose confidence in our reported financial information, leading to a decline in our stock price.
 
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Operational difficulties at our production facilities could negatively impact our sales volumes and could cause us to incur substantial losses.
 
Our operations are subject to labor disruptions, unscheduled downtime and other operational hazards inherent in our industry, such as 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. Our insurance may not be adequate to fully cover the potential operational hazards described above or we may not be able to renew this insurance on commercially reasonable terms or at all.
 
Moreover, our plants may not operate as planned or expected. All of our plants are designed to operate at or above a certain production capacity. The operation of our plants is and will be, however, subject to various uncertainties. As a result, our plants may not produce ethanol and WDG at the levels we expect. In the event any of our plants do not run at their expected capacity levels, our business, results of operations and financial condition may be materially and adversely affected.
 
The United States ethanol industry is highly dependent upon a myriad of federal and state legislation and regulation and any changes in such legislation or regulation could have a material adverse effect on our results of operations and financial condition.
 
The elimination or significant reduction in the Federal Excise Tax Credit could have a material adverse effect on our results of operations.
 
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, 2010, 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 $0.51 per gallon tax credit for each gallon of ethanol used in the mixture. The federal excise tax incentive program may not be renewed prior to its expiration in 2010, 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 have a material adverse effect on our results of operations.
 
Waivers or repeal of the national RFS minimum levels of renewable fuels included in gasoline could have a material adverse affect 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 new national RFS on commodity prices. While no action was taken by the sub-committee towards repeal of the new national RFS, any attempt by Congress to re-visit, repeal or grant waivers of the new national RFS could adversely affect demand for ethanol and could have a material adverse effect on our results of operations and financial condition.
 
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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.
 
The ethanol production and marketing industry is extremely competitive. Many of our significant competitors have greater production and financial resources than we do and one or more of these competitors could use their greater resources to gain market share at our expense. In addition, certain of our suppliers may circumvent our marketing services, causing our sales and profitability to decline.
 
The ethanol production and marketing industry is extremely competitive. Many of our significant competitors in the ethanol production and marketing industry, such as ADM, Cargill, Inc., VeraSun Energy Corporation, Aventine Renewable Energy, Inc. and Abengoa Bioenergy Corp., have substantially greater production and 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 we could. Successful competition will require a continued high level of investment in marketing and customer service and support. Our lack of resources relative to many of our significant competitors may cause us to fail to anticipate or respond adequately to new developments and other competitive pressures. This failure could reduce our competitiveness and cause a decline in our market share, sales and profitability. Even if sufficient funds are available, we may not be able to make the modifications and improvements necessary to successfully compete.
 
We 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 ours. Any increase in domestic or foreign competition could cause us to reduce our prices and take other steps to compete effectively, which could adversely affect our results of operations and financial condition.
 
In addition, some of 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.
 
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We produce and sell our own ethanol but also depend on a small number of third-party suppliers for a significant portion of the 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.
 
We produce and sell our own ethanol but also depend on a small number of third-party suppliers for a significant portion of the ethanol that we sell. Our largest third-party ethanol suppliers, each of whom accounted for 10% or more of total ethanol purchases, represented approximately 68% and 50% of the total ethanol we purchased during 2007 and 2006, respectively. We expect to continue to depend for the foreseeable future upon a small number of third-party suppliers for a significant portion 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 may be adversely affected by environmental, health and safety laws, regulations and liabilities.
 
We 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. In addition, some of these laws and regulations require our facilities 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 have made, and expect to make, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits.
 
We may be liable for the investigation and cleanup of environmental contamination at each of the properties that we own or operate and at off-site locations where we 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.
 
In addition, new laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require us to make additional significant expenditures. Continued government and public emphasis on environmental issues can be expected to result in increased future investments for environmental controls at our production facilities. Present and future environmental laws and regulations (and interpretations thereof) applicable to 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.
 
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The hazards and risks associated with producing and transporting our products (such as 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.
 
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 2007, sales to our two largest customers, each of whom accounted for 10% or more of total net sales, represented an aggregate of approximately 32% of our total net sales. During 2006, sales to our two largest customers, each of whom accounted for 10% or more of total net sales, represented an aggregate of approximately 25% of our total net sales. 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.
 
We are a minority member of Front Range with limited control over that entity’s business decisions. We are therefore dependent upon the business judgment and conduct of the manager and majority member of that entity. As a result, our interests may not be as well served as if we were in control of Front Range, which could adversely affect its contribution to our results of operations and our business prospects related to that entity.
 
Front Range operates an ethanol production facility located in Windsor, Colorado. We own approximately 42% of Front Range, which represents a minority interest in that entity. The manager and majority member of Front Range owns approximately 54% of that entity and has control of that entity’s business decisions, including those related to day-to-day operations. The manager and majority member of Front Range has the right to set the manager’s compensation, determine cash distributions, decide whether or not to expand the ethanol production facility and make most other business decisions on behalf of that entity. We are therefore largely dependent upon the business judgment and conduct of the manager and majority member of Front Range. As a result, our interests may not be as well served as if we were in control of Front Range. Accordingly, the contribution by Front Range to our results of operations and our business prospectus related to that entity may be adversely affected by our lack of control over that entity.
 
21

 
Risks Related to our Common Stock
 
Our common stock has a small public float and shares of our common stock eligible for public sale could cause the market price of our stock to drop, even if our business is doing well, and make it difficult for us to raise additional capital through sales of equity securities.
 
As of March 24, 2008, we had outstanding approximately 40.7 million shares of our common stock. Approximately 7.1 million of these shares were restricted under the Securities Act of 1933, or Securities Act, including approximately 4.7 million shares owned, in the aggregate, by our executive officers, directors and 10% stockholders. Accordingly, our common stock has a relatively small public float of approximately 33.6 million shares.
 
We have registered for resale a substantial number of shares of our common stock, including approximately 10.6 million shares of our common stock underlying our Series A Preferred Stock. The holder of these shares is permitted, subject to few limitations, to freely sell these shares of common stock. As a result of our relatively small public float, sales of substantial amounts of common stock, or in anticipation that such sales could occur, may materially and adversely affect prevailing market prices for our common stock. In addition, any adverse effect on the market price of our common stock could make it difficult for us to raise additional capital through sales of equity securities at a time and at a price that we deem appropriate.
 
As a result of our issuance of shares of Series A Preferred Stock to Cascade Investment, L.L.C. and our issuance of Series B Preferred Stock to Lyles United, LLC, 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 preferred stock.

As a result of our issuance of shares of Series A Preferred Stock to Cascade Investment, L.L.C. and our issuance of Series B Preferred Stock to Lyles United, LLC, our common stockholders may experience numerous negative effects, including dilution from dividends paid in preferred stock and certain antidilution adjustments. In addition, rights in favor of the holders of our preferred stock include: seniority in liquidation and dividend preferences; substantial voting rights; numerous protective provisions; as to the holder of our Series A Preferred Stock, the right to appoint two persons to our board of directors and periodically nominate two persons for election by our stockholders to our board of directors; preemptive rights; and redemption rights. Also, our outstanding preferred stock could have the effect of delaying, deferring and discouraging another party from acquiring control of Pacific Ethanol. In addition, based on our current number of shares of common stock outstanding, Cascade Investment, L.L.C. has approximately 19% and Lyles United, LLC has approximately 13% of all outstanding voting power as compared to approximately 8% of all outstanding voting power held in aggregate by our current executive officers and directors. Also, in the event that we are profitable, our preferred stock would likewise result in a decrease in our diluted earnings per share by an aggregate of approximately 31%, without taking into account cash or stock payable as dividends on our preferred stock. Any of the above factors may materially and adversely affect our common stockholders and the values of their investments in our common stock.
 
22

 
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:

·    
changing conditions in the ethanol and fuel markets as well as other commodity markets such as corn;
·    
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;
·    
regulatory developments or increased enforcement;
·    
fluctuations in our quarterly or annual operating results;
·    
additions or departures of key personnel;
·    
our inability to obtain construction, acquisition, capital equipment and/or working capital 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 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 also the price of our common stock.
 
Item 1B.     Unresolved Staff Comments.
 
None.
 
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Item 2.     Properties.
 
Our corporate headquarters, located in Sacramento, California, consists of a 10,000 square foot office leased for approximately five years. We also rent, under a two-year lease, an office in Fresno, California, consisting of 2,000 square feet and, under a five-year lease, an office in Portland, Oregon, consisting of 3,500 square feet.
 
Our completed ethanol production facilities are located in Madera, California, at which a 137 acre facility is located, Boardman, Oregon, at which a 25 acre facility is located and Windsor, Colorado, at which a 40 acre facility is located. We are a minority owner of the entity that owns the Windsor, Colorado facility. We have acquired sites or options with respect to sites for three other potential ethanol production facilities that we may develop, or which are currently under development or construction, including sites at Burley, Idaho and Stockton, California. See “Business—Production Facilities.”
 
 
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 adversely affect our financial position, results of operations or cash flows.
 
Barry Spiegel – State Court Action
 
On December 23, 2005, Barry J. Spiegel, a former shareholder and director of our predecessor, Accessity Corp., or Accessity, filed a complaint in the Circuit Court of the 17th Judicial District in and for Broward County, Florida (Case No. 05018512), or State Court Action, against Barry Siegel, Philip Kart, Kenneth Friedman and Bruce Udell, or collectively, the Individual Defendants. Messrs. Siegel, Udell and Friedman are former directors of Accessity and Pacific Ethanol. Mr. Kart is a 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 $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, or the Order, 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 purported 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 includes Pacific Ethanol as a defendant. The breach of fiduciary duty counts are alleged solely against the Individual Defendants and not Pacific Ethanol. On June 19, 2007, we filed a motion to dismiss the amended complaint. The Court denied the motion to dismiss the amended complaint by order dated July 31, 2007. Mr. Spiegel, however, voluntarily dismissed without prejudice the case against us on August 27, 2007, and therefore we are no longer a party to the state action.
 
24

 
Barry Spiegel – Federal Court Action
 
On December 22, 2006, Barry J. Spiegel, filed a complaint in the United States District Court, Southern District of Florida (Case No. 06-61848), or 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 Exchange Act and 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 February 9, 2007 and then sought to stay his own federal case, but the Motion was denied on July 17, 2007. Mr. Spiegel filed his reply to our Motion to Dismiss and that Motion remains pending. We intend to vigorously defend the Federal Court Action.
 
Mercator Group, LLC
 
In 2003, Accessity filed a lawsuit seeking damages in excess of $100 million against: (i) Presidion Corporation, f/k/a MediaBus Networks, Inc., the parent corporation of Presidion Solutions, Inc., or Presidion,  (ii) Presidion’s investment bankers, Mercator Group, LLC, or Mercator, and various related and affiliated parties, and (iii) Taurus Global LLC, or Taurus, (collectively referred to as the “Mercator Action”), alleging that these parties committed a number of wrongful acts, including, but not limited to tortiously interfering in the transaction between Accessity and Presidion. In 2004, Accessity dismissed this lawsuit without prejudice, which was filed in Florida state court. In January 2005, Accessity refiled this action in the State of California, for a similar amount, as Accessity believed that this was the proper jurisdiction. On August 18, 2005, the court stayed the action and ordered the parties to arbitration. The parties agreed to mediate the matter. Mediation took place on December 9, 2005 and was not successful. On December 5, 2005, we filed a Demand for Arbitration with the American Arbitration Association. On April 6, 2006, a single arbitrator was appointed. Arbitration hearings had been scheduled to commence in July 2007. In April 2007, the arbitration proceedings were suspended due to non-payment of arbitration fees by Presidion and Taurus. As a result of non-payment of arbitration fees, a default order was entered against Taurus by the Los Angeles Superior Court. In July, 2007, we entered into a confidential settlement agreement with Presidion and its former officers. On July 23, 2007, we dismissed Presidion from the arbitration. On July 23, 2007, Taurus filed a Voluntary Petition for Chapter 7 Bankruptcy in the United States District Court, Central District of California, Case Number SV07-12547 GM. The arbitration hearings against Mercator began on February 11, 2008 and concluded on February 19, 2008. After the hearings concluded but prior to an award being issued, the parties engaged in a two day mediation. As a result of the mediation, the parties entered into a confidential settlement agreement. The share exchange agreement relating to the Share Exchange Transaction provides that following full and final settlement or other final resolution of the Mercator Action, after deduction of all fees and expenses incurred by the law firm representing us in this action and payment of the 25% contingency fee to the law firm, shareholders of record of Accessity on the date immediately preceding the closing date of the Share Exchange Transaction will receive two-thirds and we will retain the remaining one-third of the net proceeds from any Mercator Action recovery.
 
25

 
 
None.
 
 
 
Market Information
 
Our common stock has been traded on the Nasdaq Global Market (formerly, the Nasdaq National Market) under the symbol “PEIX” since October 10, 2005. Prior to October 10, 2005 and since March 24, 2005, our common stock traded on the Nasdaq Capital Market (formerly, the Nasdaq SmallCap Market) under the symbol “PEIX.” Prior to March 24, 2005, our common stock traded on the Nasdaq SmallCap Market under the symbol “ACTY.” The table below shows, for each fiscal quarter indicated, the high and low closing prices for shares of our common stock. This information has been obtained from The Nasdaq Stock Market. 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, 2007:
           
First Quarter (January 1 – March 31)
  $ 17.85     $ 14.22  
Second Quarter (April 1 – June 30)
  $ 16.50     $ 12.25  
Third Quarter (July 1 – September 30)
  $ 14.86     $ 8.58  
Fourth Quarter (October 1 – December 31)
  $ 9.46     $ 4.22  
                 
Year Ended December 31, 2006:
               
First Quarter
  $ 22.34     $ 9.99  
Second Quarter
  $ 42.39     $ 20.14  
Third Quarter
  $ 25.45     $ 13.76  
Fourth Quarter
  $ 19.08     $ 12.58  
 
Security Holders
 
As of March 24, 2008, we had 40,674,464 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 24, 2008, the closing sale price of our common stock on the Nasdaq Global Market was $4.94 per share.
 
Performance Graph
 
The graph below shows a comparison of the cumulative total stockholder return on our common stock with the cumulative total return on The NASDAQ Stock Market (U.S.) Index and of public companies filing reports with the Securities and Exchange Commission under Standard Industrial Classification Code 2860—Industrial Organic Chemicals, or Peer Group, in each case over the five-year period ended December 31, 2007.
 
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The graph includes the date of March 23, 2005, the date of the Share Exchange Transaction and the date on which we effectively began operating in a business properly categorized under Standard Industrial Classification Code 2860—Industrial Organic Chemicals. Our predecessor, Accessity, was in an unrelated business prior to March 23, 2005. See “Business—Company History.”
 
The graph assumes $100 invested at the indicated starting date in our common stock and in each of The NASDAQ Stock Market (U.S.) Index and the Peer Group, with the reinvestment of all dividends. We have not paid or declared any cash dividends on our common stock and do not anticipate paying any cash dividends in the foreseeable future. Stockholder returns over the indicated periods should not be considered indicative of future stock prices or stockholder returns. This graph assumes that the value of the investment in our common stock and each of the comparison groups was $100 on December 31, 2002.
 
graph
 
 
Cumulative Total Return ($)
 
12/02
12/03
12/04
3/23/05
12/05
12/06
12/07
PACIFIC ETHANOL, INC.
100.00
151.61
382.58
583.87
698.06
992.90
529.68
THE NASDAQ STOCK MARKET (U.S.) INDEX
100.00
149.75
164.64
155.75
168.60
187.83
205.22
SIC 2860—INDUSTRIAL ORGANIC CHEMICALS
100.00
117.59
148.52
139.73
123.21
180.97
144.37
 
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 the debt, thereby limiting or preventing us from paying cash dividends. In addition, the holders of our preferred stock are entitled to dividends of 5%, and those dividends must be paid prior to the payment of any dividends to our common stockholders.
 
27

 
Recent Sales of Unregistered Securities
 
None.
 
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
 
We have 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. Since October 4, 2006, we have granted an aggregate of 869,239 shares of restricted stock, net of deemed repurchases and cancellations, to our employees and directors, of which an aggregate of 421,145 shares of restricted stock had vested as of December 31, 2007. Future vesting is subject to various restrictions.
 
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 connection with satisfying our withholding requirements, during the fourth quarter of 2007, we withheld an aggregate of 17,464 shares of our common stock and remitted a cash payment to cover the minimum withholding tax amounts, thereby effectively repurchasing from the employees the 17,464 shares of common stock at a deemed purchase price equal to $9.30 per share for an aggregate purchase price of $162,415.
 
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Item 6.     Selected Financial Data.
 
The following financial information should be read in conjunction with the consolidated audited financial statements and the notes to those statements beginning on page F-1 of this report, and the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this report. The consolidated statements of operations data for the years ended December 31, 2007, 2006 and 2005 and the consolidated balance sheet data at December 31, 2007 and 2006 are derived from, and are qualified in their entirety by reference to, the consolidated audited financial statements beginning on page F-1 of this report. The consolidated statements of operations data from January 30, 2003 (inception) to December 31, 2003 and the consolidated balance sheet data at December 31, 2003 are derived from, and qualified in their entirety by reference to, the consolidated audited financial statements of Pacific Ethanol. The historical results that appear below are not necessarily indicative of results to be expected for any future periods.

 
   
Years Ended December 31,
 
    2007    
2006 
   
2005
   
2004
   
2003
 
   
(in thousands, except per share data)
 
Consolidated Statements of Operations Data:
                         
 
 
Net sales
  $ 461,513     $ 226,356     $ 87,599     $ 20     $ 1,017  
Cost of goods sold
    428,614       201,527       84,444       13       946  
Gross profit
    32,899       24,829       3,155       7       71  
Selling, general and administrative expenses
    30,822       24,641       12,638       2,277       648  
Income (loss) from operations
    2,077       188       (9,483 )     (2,270 )     (577 )
Other income (expense), net
    (6,801 )     3,426       (440 )     (532 )     (282 )
Income (loss) before provision for income taxes and noncontrolling interest in variable interest entity
    (4,724 )     3,614       (9,923 )     (2,802 )     (859 )
Provision for income taxes
                  —               —  
Income (loss) before noncontrolling interest in variable interest entity
    (4,724 )     3,614       (9,923 )     (2,802     (859 )
Noncontrolling interest in variable interest entity
    (9,676     (3,756                  
Net loss
  $ (14,400 )   $ (142 )   $ (9,923 )   $ (2,802 )   $ (859 )
                                         
Preferred stock dividends
  $ (4,200 )   $ (2,998 )   $     —     $     $  
Deemed dividend on preferred stock
    (28 )     (84,000 )       —              
Loss available to common stockholders
  $ (18,628 )   $ (87,140 )   $ (9,923 )   $ (2,802 )   $ (859 )
Loss per share, basic and diluted
  $ (0.47   $ (2.50   $ (0.40   $ (0.23 )   $ (0.07 )
Weighted-average shares outstanding, basic and diluted
     39,895        34,855       25,066       12,397       11,733  
Consolidated Balance Sheet Data:
                                       
Cash and cash equivalents
  $ 5,707     $ 44,053     $ 4,521     $     $ 249  
Working capital (deficit)
  $ (37,886 )   $ 96,094     $ (2,894 )   $ (1,025 )   $ (358 )
Total assets
  $ 651,600     $ 453,820     $ 48,185     $ 7,179     $ 6,560  
Long-term debt
  $ 151,188     $ 28,970     $ 1,995     $ 4,013     $  
Stockholders’ equity
  $ 282,286     $ 298,445     $ 28,516     $ 1,356     $ 1,368  
 
No cash dividends on our common stock were declared during any of the periods presented above.  Various factors materially affect the comparability of the information presented in the above table. These factors relate primarily to a Share Exchange Transaction that was consummated on March 23, 2005 with the shareholders of PEI California, and the holders of the membership interests of each of Kinergy and ReEnergy, pursuant to which we acquired all of the issued and outstanding capital stock of PEI California and all of the outstanding membership interests of Kinergy and ReEnergy. See “Business—Company History.” In addition, we acquired a minority interest in Front Range on October 17, 2006, at which date we began treating Front Range, a variable interest entity, as a consolidated subsidiary, as we are considered the primary beneficiary.
 
29

 
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, without limitation:

·    
fluctuations in the market price of ethanol and its co-products;
·    
the projected growth or contraction in the ethanol and co-product market in which we operate;
·    
our strategies for expanding, maintaining or contracting our presence in these markets;
·    
our ability to successfully develop, finance, construct and operate our planned 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.
 
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.
 
Overview
 
Our primary goal is to be the leading marketer and producer of low carbon renewable fuels in the Western United States.
 
We produce and sell ethanol and its co-products 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 and Idaho. We have extensive customer relationships throughout the Western United States and extensive supplier relationships throughout the Western and Midwestern United States.
 
We own and operate two ethanol production facilities located in Madera, California and Boardman, Oregon. Our Madera facility has an annual production capacity of up to 40 million gallons and has been in operation since October 2006. Our Boardman facility has an annual production capacity of up to 40 million gallons and has been in operation since September 2007. In addition, we own a 42% interest in Front Range Energy, LLC, or Front Range, which owns and operates an ethanol production facility with annual production capacity of up to 50 million gallons in Windsor, Colorado. We have two additional ethanol production facilities under construction, in Burley, Idaho and Stockton, California, which are expected to commence operations in the second and third quarters of 2008, respectively. We also intend to either construct or acquire additional ethanol production facilities as financial resources and business prospects make the construction or acquisition of these facilities advisable. See “Business—Production Facilities.”
 
30

 
Total annual gasoline consumption in the United States is approximately 140 billion gallons. Total annual ethanol consumption represented less than 5% of this amount in 2007. We believe that the domestic ethanol industry has substantial potential for growth to initially reach what we estimate is an achievable level of 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 under the new national Renewable Fuel Standards, or RFS, by 2022. See “Business—Governmental Regulation.”
 
We intend to reach our goal to be 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, by expanding our relationships with animal feed distributors and end users to build local markets for wet distillers grains, or WDG, the primary co-product of our ethanol production, 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. In addition, we intend to expand our annual production capacity to 220 million gallons in 2008, upon completion of our facilities in Burley, Idaho and Stockton, California, and 420 million gallons of annual production capacity in 2010, through new construction or acquisition of additional ethanol production facilities. We also intend 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.
 
Financial Performance Summary
 
Our net sales increased by $235.1 million, or 104%, to $461.5 million for the year ended December 31, 2007 from $226.4 million for the year ended December 31, 2006. Our net loss, however, increased by $14.3 million to $14.4 million for the year ended December 31, 2007 from $0.1 million for the year ended December 31, 2006.
 
Factors that contributed to our results of operations for 2007 include:
 
·   
Net sales. The increase in our net sales in 2007 as compared to 2006 was primarily due to the following combination of factors:
 
o    
Higher sales volumes. Total volume of ethanol sold increased by 87% to 190.6 million gallons in 2007 from 101.7 million gallons in 2006. The increase in sales volume is primarily due to a full year of ethanol production from our Madera and Front Range facilities, each of which accounted for less than three months of production in 2006. Sales also increased in 2007 from startup of production at our Boardman facility and additional supply purchased from third-party suppliers under our ethanol marketing agreements; and
 
o    
Lower ethanol prices. The increase in sales volume was partially offset by lower ethanol prices. Our average sales price of ethanol decreased 6% to $2.15 per gallon in 2007 as compared to $2.28 per gallon in 2006. This decrease is, however, less than the 21% decline in the average Chicago Board of Trade, or CBOT, ethanol price to $1.98 per gallon in 2007 as compared to $2.52 per gallon in 2006.
 
·   
Lower gross profit margin. Our gross profit margin decreased to 7.1% for 2007 as compared to 11.0% for 2006. This decrease was primarily due to lower ethanol prices and higher corn prices. In addition, we had significant fixed-price contracts and held inventory balances during a period of declining ethanol prices, both of which reduced our margins. The average price of corn, the main raw material for ethanol we produce, increased by 48% to $3.61 per bushel for 2007 from $2.44 per bushel for 2006. The average CBOT price for corn increased by 44% to $3.74 per bushel for 2007 from $2.60 per bushel for 2006. Also, gross profit margins from our sale of WDG and other co-products from our ethanol production declined due to the increase in corn prices.
 
31

 
·   
Selling, general and administrative expenses. Our selling, general and administrative expenses increased by $6.2 million to $30.8 million in 2007 as compared to $24.6 million in 2006 primarily as a result of increases in administrative staff, amortization of intangible assets and full-year expenses related to our 42% ownership interest in Front Range. However, these expenses decreased to 6.6% of our net sales in 2007 as compared to 10.9% of our net sales in 2006 due to the substantial growth in our net sales over those periods.
 
·   
Other income (expense). Our other expense increased by $10.2 million to $6.8 million in 2007 from other income of $3.4 million in 2006. This increase is primarily due to an increase in interest expense and amortization of finance charges from our increase in debt. In addition, other expense increased due to mark-to-market charges in the amount of $5.4 million on future interest rate positions.
 
Sales and Margins
 
Over the past three years, our sales mix has shifted significantly from sales generated solely as a marketer of ethanol produced by third parties to now include sales generated as a producer of our own ethanol. Our cost structure also changed significantly, predominantly in 2007, as our Madera and Front Range facilities were in full production and our Boardman facility was in production for more than three months during the year. 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 now include the cost of corn, the principal input commodity for our production of ethanol. Accordingly, our profitability is now highly dependent on the market price of ethanol and the cost of corn.
 
Average ethanol sales prices dropped significantly in 2007 as compared to 2006. Specifically, the average CBOT price of ethanol decreased by 21% in 2007 as compared to the average 2006 price. The decrease in the prevailing market price of ethanol was the primary cause of the decline in our average ethanol sales price. However, because of our combination of fixed- and index-priced ethanol sales contracts, we were able to diminish the decline in our average ethanol sales price to only 6% in 2007 as compared to our average 2006 price.
 
Average corn prices increased significantly in 2007 as compared to 2006. Specifically, the average CBOT price of corn increased by 44% in 2007 as compared to the average 2006 price. The increase in the prevailing market price of corn was the primary cause of the increase in our average corn price. However, our average corn price increased by 48% in 2007 as compared to our average 2006 price—a rate greater than the increase in the average CBOT price of corn—because we purchased more corn in the fourth quarter of 2007, a period during which corn prices were at their highest levels during the year, as compared to previous quarters in connection with the commencement of operations at our Boardman facility.
 
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.
 
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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. Our exposure varies depending on the magnitude of our sales commitments compared to the magnitude of our purchase commitments and 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.
 
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 as an agent for third-party suppliers, we receive a predetermined service fee and we 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 will primarily depend on four 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;
 
·    
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 our facilities to our sales of ethanol produced by third-parties.
 
We believe that our gross profit margins will also depend on the market price of WDG.
 
Management seeks to optimize our gross profit margins by anticipating the factors above and implementing hedging transactions and taking other actions designed to limit risk and address the various 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 inability to anticipate the factors above 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 those factors or favorable movements in the factors themselves 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.
 
33

 
Results of Operations
 
The following selected financial data 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,
   
Percentage Variance
From Prior Year
 
   
2007
   
2006
   
2005
   
2007
   
2006
 
Gallons sold (in millions)
    190.6         101.7         52.3         87.4
      94.4
 
Average sales price per gallon
  $ 2.15       $ 2.28       $ 1.67         (5.7
)% 
      36.5
 
Corn cost per bushel—CBOT equivalent(1)
  $ 3.61       $ 2.44         N/A         48.0
      N/A    
Co-product revenues as % of delivered cost of corn(2)
    24.8
%
      33.4
      N/A         (8.6
)% 
      N/A    
                                                   
Average CBOT ethanol price per gallon
  $ 1.98       $ 2.52       $ 1.70         (21.4
)% 
      48.2
 
Average CBOT corn price per bushel
  $ 3.74       $ 2.60       $ 1.77         43.9
      46.9
 
_____________
                                                 
 
(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.
 
Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006
 
   
Years Ended
   
 Dollar
Variance
   
Percentage
Variance
   
Results as a Percentage
of Net Sales for the
Years Ended
 
   
December 31,
   
Favorable
   
Favorable
   
December 31,
 
   
2007
   
2006
   
(Unfavorable)
   
(Unfavorable)
   
2007
   
2006
 
   
(dollars in thousands)
 
Net sales
  $ 461,513     $ 226,356     $ 235,157       103.9 %     100.0 %     100.0 %
Cost of goods sold
    428,614       201,527       (227,087 )     (112.7 )     92.9       89.0  
Gross profit
    32,899       24,829       8,070       32.5       7.1       11.0  
Selling, general and administrative expenses
    30,822       24,641       (6,181 )     (25.1 )     6.6       10.9  
Income from operations
    2,077       188       1,889       1,004.8       0.5       0.1  
Other income (expense), net
    (6,801 )     3,426       (10,227 )     (298.5 )     (1.5 )     1.5  
Income (loss) before provision for income taxes and noncontrolling interest in variable interest entity
    (4,724 )     3,614       (8,338 )     (230.7 )     (1.0 )     1.6  
Provision for income taxes
                                   
Noncontrolling interest in variable interest entity
    (9,676 )     (3,756 )     (5,920 )     (157.6 )     (2.1 )     (1.7 )
Net loss
  $ (14,400 )   $ (142 )   $ (14,258 )     (10,040.9 )%     (3.1 )%     (0.1 )%
Preferred stock dividends
    (4,200 )     (2,998 )     (1,202 )     (40.1 )     (0.9 )     (1.3 )
Deemed dividend on preferred stock
    (28 )     (84,000 )     83,972       100.0       (0.0 )     (37.1 )
Loss available to common stockholders
  $ (18,628 )   $ (87,140 )   $ 68,512       78.6 %     (4.0 )%     (38.5 )%
 
Net Sales
 
The increase in our net sales in 2007 as compared to 2006 was primarily due to a substantial increase in sales volume, which was partially offset by decreased average sales prices.
 
 
34

Total volume of ethanol sold increased by 88.9 million gallons, or 87%, to 190.6 million gallons in 2007 as compared to 101.7 million gallons in 2006. The substantial increase in sales volume is primarily due to a full year of ethanol production at our Madera and Front Range facilities in 2007. Our Madera and Front Range facilities each accounted for less than three months of ethanol production in 2006. In addition, in 2007, we commenced ethanol production at our Boardman facility and also generated increased sales from the purchase and resale of additional supply from third-parties under our ethanol marketing agreements. The production and sale of ethanol and its co-products from our Madera and Boardman facilities, and through Front Range, contributed an aggregate of $194.0 million to our increase in net sales in 2007.
 
Our average sales price per gallon declined 6% to $2.15 in 2007 from an average sales price per gallon of $2.28 in 2006. The average CBOT price per gallon declined 21% to $1.98 in 2007 from an average CBOT price per gallon of $2.52 in 2006. We believe that we were insulated from some of this decline due to our fixed-price ethanol contracts which were partially offset by derivative losses incurred as a result of locking in margins.
 
Cost of Goods Sold and Gross Profit
 
The increase in our cost of goods sold in 2007 as compared to 2006 was predominantly due to increased sales volume and increased corn costs which contributed to higher costs per gallon. Our gross margin declined to 7.1% in 2007 from 11.0% in 2006 primarily due to increased corn costs, lower average sales prices per gallon and losses on derivatives, as further discussed below.
 
Although a large proportion of our sales volume results from the marketing and sale of ethanol produced by third parties, production of our own ethanol is growing rapidly and we expect that our production will continue to grow as new facilities commence operations. Our purchase and sale prices of ethanol produced by third parties typically fluctuate closely with market prices. As a result, our average cost of ethanol purchased from third parties decreased in line with the overall decline in our average sales price per gallon.
 
Corn is the single largest component of the cost of our ethanol production. Average corn prices rose significantly in 2007 as compared to 2006, with greater increases occurring in the second half of 2007 than in the first half of the year. These increases pushed our average corn price higher than the average market price for all of 2007 because our corn requirements increased significantly during the second half of 2007 due to the commencement of operations at our Boardman facility in September 2007. Overall, the price of corn had a much larger impact on our production costs per gallon in 2007 than in 2006 due to the higher proportion of sales from production of our own ethanol in 2007 as compared to 2006.
 
Cost of goods sold also increased by $4,122,000 from net losses on derivatives in 2007 as compared to only a nominal amount in 2006. These losses resulted from derivatives that we entered in order to lock in margins during the year and were partially offset by gains from derivatives we entered in order to lock in the price of corn. Of these losses, $1,649,000 was related to open positions at December 31, 2007.
 
Selling, General and Administrative Expenses
 
Our selling, general and administrative expenses, or SG&A, increased by $6,181,000 to $30,822,000 for 2007 as compared to $24,641,000 for 2006. SG&A, however, decreased as a percentage of net sales due to our significant sales growth. The increase in the dollar amount of SG&A is primarily due to the following factors:
 
35

 
·    
payroll and benefits increased by $3,017,000, or 68%, due to increased administrative staff;
 
·    
amortization of intangible assets resulting from our acquisition of our 42% ownership interest in Front Range increased by $2,117,000, as we incurred a full year of amortization compared to less than three months in 2006; we expect these costs to decline to approximately $500,000 for each of the next seven years;
 
·    
SG&A attributable to Front Range increased by $2,042,000 as we incurred a full year of these expenses as compared to less than three months in 2006;
 
·    
consulting and temporary staff expenses increased by $1,950,000, or 126%, due to the retention of additional consulting and temporary staff personnel to assist us in meeting our accounting and public reporting requirements, including as we transitioned our permanent staff to our new corporate headquarters in Sacramento, California; these consulting and temporary staff personnel also assisted us in training new administrative staff members;
 
·    
recruiting, hiring and training expenses increased by $709,000, or 1,055%, employee travel and office setup costs increased by $377,000, or 243%, and rent expense increased by $457,000, or 221%; each of these increases resulted primarily from the relocation of our corporate headquarters in early 2007 from Fresno to Sacramento;
 
·    
external audit costs increased by $582,000, or 312%, due to our overall growth and business initiatives; and
 
·    
travel-related costs increased by $311,000, or 52%, due to expanded operations and new office locations.
 
Partially offsetting the foregoing increases were the following decreases:
 
·    
non-cash compensation expense decreased by $4,023,000, or 64%, due to the completion of vesting of incentive compensation paid to employees and consultants;
 
·    
legal expenses decreased by $918,000, or 43%, primarily due to one-time costs associated with greater legal activity from litigation and business transactions that occurred in 2006; and
 
·    
costs associated with implementing and testing our internal controls and related compliance required under the Sarbanes-Oxley Act of 2002 decreased by $902,000, or 76%, as many costs that occurred in 2006 were related predominantly to our initial implementation and testing of our internal controls.
 
Other Income (Expense), Net
 
Other expense increased by $10,227,000 to $6,801,000 in 2007 from other income of $3,426,000 in 2006. The increase in other expense is primarily due to the following factors:
 
·    
interest expense increased by $1,828,000, or 286%, due to additional borrowings and a full year of interest accruing on outstanding debt; and
 
36

 
·    
amortization of interest and financing costs increased by $3,164,000, or 305%, primarily due to an amendment to our construction financing credit facility that reduced its application from five to four facilities and reduced the total amount of available financing; as a result, we wrote off $1,962,000 of unamortized costs associated with our Imperial Valley facility, the construction of which  has been suspended; interest and financing costs incurred under the construction phase of each of our facilities are being capitalized until the corresponding facility becomes operational; this increase in amortization of interest and financing costs is net of approximately $7,823,000 of additional capitalized amounts over 2006.
 
In addition, we recognized losses of $119,000 and $5,442,000 of effective and ineffectiveness positions, respectively, from our interest rate hedges which required that we mark-to-market our ineffective positions in a declining interest rate environment. The ineffectiveness related to our interest rate swaps and primarily resulted from the suspension of construction of our Imperial Valley facility.
 
Noncontrolling Interest in Variable Interest Entity
 
Noncontrolling interest in variable interest entity relates to the consolidated treatment of Front Range, a variable interest entity, and represents the noncontrolling interest of others in the earnings of Front Range. We consolidate the entire income statement of Front Range for the period covered. However, because we own only 42% of Front Range, we must reduce our net income or increase our net loss for the noncontrolling interest, which is the 58% ownership interest that we do not own. This amount increased by $5,920,000 to $9,676,000 in 2007 from $3,756,000 in 2006 due to the consolidation of Front Range’s operations for all of 2007 as compared to less than three months in 2006.
 
Preferred Stock Dividends
 
Shares of our Series A Cumulative Redeemable Convertible Preferred Stock, or Series A Preferred Stock, are entitled to quarterly cumulative dividends payable in arrears in cash in an amount equal to 5% per annum of the purchase price per share of the Series A Preferred Stock, or, at our option, payable in additional shares of Series A Preferred Stock based on the value of the purchase price per share of the Series A Preferred Stock. In 2007, we declared and paid dividends on our Series A Preferred Stock in the aggregate amount of $4,200,000 comprised of cash dividends in the aggregate amount of $3,150,000 for the first three quarters and a dividend payment-in-kind in the amount of $1,050,000 that was issued in shares of Series A Preferred Stock for the fourth quarter.
 
Deemed Dividend on Preferred Stock
 
We recorded a deemed dividend on preferred stock of $28,000 for 2007 in connection with our issuance of shares of Series A Preferred Stock as a dividend payment-in-kind for the fourth quarter. We also recorded a deemed dividend on preferred stock of $84,000,000 for 2006 in connection with our initial issuance of shares of Series A Preferred Stock. These non-cash dividends reflect the implied economic value to the preferred stockholder of being able to convert these additional shares into common stock at prices which were in excess of the fair value of the Series A Preferred Stock at the times of issuance. The fair value was calculated using the difference between the agreed-upon conversion price of the Series A Preferred Stock into shares of common stock of $8.00 per share and the fair market value of our common stock of $8.21 and $29.27 on the date of issuance of the additional shares of Series A Preferred Stock for 2007 and 2006, respectively. The fair value allocated to the initial issuance of the Series A Preferred Stock in 2006 was in excess of the gross proceeds received of $84,000,000 in connection with the initial sale of the Series A Preferred Stock; however, the deemed dividend on the Series A Preferred Stock for 2006 is limited to the gross proceeds received of $84,000,000. The deemed dividend on preferred stock is a reconciling item and adjusts our reported net loss, together with the preferred stock dividends discussed above, to loss available to common stockholders.
 
37

 
Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005
 
   
Years Ended
   
Dollar
Variance
   
Percentage
Variance
   
Results as a Percentage
of Net Sales for the
Years Ended
 
   
December 31,
   
Favorable
   
Favorable
   
December 31,
 
   
2006
   
2005
   
(Unfavorable)
   
(Unfavorable)
   
2006
   
2005
 
   
(dollars in thousands)
 
Net sales
  $ 226,356     $ 87,599     $ 138,757       158.4 %     100.0 %     100.0 %
Cost of goods sold
    201,527       84,444       (117,083 )     (138.7 )     89.0       96.4  
Gross profit
    24,829       3,155       21,674       687.0       11.0       3.6  
Selling, general and administrative expenses
    24,641       12,638       (12,003 )     (95.0 )     10.9       14.4  
Income (loss) from operations
    188       (9,483 )     9,671       102.0       0.1       (10.8 )
Other income (expense), net
    3,426       (440 )     3,866       878.6       1.5       (0.5 )
Income (loss) before provision for income taxes and noncontrolling interest in variable interest entity
    3,614       (9,923 )     13,537       136.4       1.6       (11.3 )
Provision for income taxes
                                   
Noncontrolling interest in variable interest entity
    (3,756 )           (3,756 )     (100.0 )     (1.7 )      
Net loss
  $ (142 )   $ (9,923 )   $ 9,781       98.6 %     (0.1 )%     (11.3 )%
Preferred stock dividends
    (2,998 )           (2,998 )     (100.0 )     (1.3 )      
Deemed dividend on preferred stock
    (84,000 )           (84,000 )     (100.0 )     (37.1 )      
Loss available to common stockholders
  $ (87,140 )   $ (9,923 )   $ (77,217 )     (778.2 )%     (38.5 )%     (11.3 )%
 
Net Sales
 
The increase in our net sales in 2006 as compared to 2005 was predominantly due to increased sales volume and increased average sales prices. During 2006, total volume of ethanol sold increased by 49.4 million gallons, or 94%, to 101.7 million gallons as compared to 52.3 million gallons for 2005. For 2006, our average sales price of ethanol increased by $0.61 per gallon, or 37%, to $2.28 per gallon for as compared to $1.67 per gallon for 2005. The substantial increase in sales volume is primarily due to additional supply provided under our ethanol marketing agreements and the commencement of ethanol production. In the fourth quarter of 2006, we commenced producing ethanol and its co-products at our Madera facility and, based on our ownership interest in Front Range, began recording a proportionate amount of its net sales. The production and sale of ethanol and its co-products at our Madera facility and through Front Range contributed an aggregate of $28,064,000 in sales for 2006.
 
Cost of Goods Sold and Gross Profit
 
The increase in our cost of goods sold in 2006 as compared to 2005 was predominantly due to increased sales volume. The increase in gross profit, both in dollars and as a percentage of net sales, in 2006 as compared to 2005 is generally reflective of more advantageous buying and selling during a period of increasing market prices as well as the commencement of ethanol production at our Madera facility and our acquisition of a 42% interest in Front Range, both of which occurred in the fourth quarter of 2006. We established and maintained net long ethanol positions during much of 2006. The decision to maintain net long ethanol positions was reached in accordance with our risk management program and was based on a confluence of factors, including management’s expectation of increased prices of gasoline and petroleum and the continued phase-out of methyl tertiary-butyl ether, or MTBE, blending which we believed would result in a significant increase in demand for blending ethanol with gasoline. Future gross profit margins will vary based upon, among other things, the size and timing of our net long or short positions during our various contract periods and the volatility of the market price of ethanol.
 
38

 
Selling, General and Administrative Expenses
 
The increase in SG&A during 2006 as compared to 2005 was primarily due to a $5,613,000 increase in payroll and benefits related to the hiring of additional staff, a $2,759,000 increase in legal, accounting and consulting fees, a $1,671,000 increase in additional non-cash director and consulting expenses, a $1,200,000 increase in depreciation and amortization, a $769,000 increase in insurance expense primarily related to increased directors and officers insurance costs, a $626,000 increase in general office and administrative expenses, a $619,000 increase in costs related to implementation and testing of internal controls and procedures in connection with the Sarbanes-Oxley Act of 2002, a $452,000 increase in travel and entertainment and a $250,000 increase in investor relations expense.
 
Other Income (Expense), Net
 
Other income increased during 2006 as compared to 2005, primarily due to a $4,332,000 increase in interest income associated with the significant increase in our cash position due to the sale of shares of our common stock in May 2006 and shares of our Series A Preferred Stock in April 2006, $1,110,000 in deferred financing cost amortization related to potential plant expansion financing and $494,000 in interest expense related to notes payable. Other changes included a $373,000 increase in capitalized interest related to a loan for the construction of our Madera production facility, a $297,000 decrease in penalties and fines expenses and a $350,000 increase in all other categories.
 
Noncontrolling Interest in Variable Interest Entity
 
Noncontrolling interest in variable interest entity was $3,756,000. As noted above, this amount relates to the consolidated treatment of Front Range, a variable interest entity and represents the noncontrolling interest of others in the earnings of Front Range.
 
Preferred Stock Dividends
 
As noted above, shares of our Series A Preferred Stock are entitled to quarterly cumulative dividends. In 2006, we declared and paid cash dividends on shares of our Series A Preferred Stock in the aggregate amount of $2,998,000.
 
Deemed Dividend on Preferred Stock
 
We recorded a deemed dividend on preferred stock of $84,000,000 for 2006 in connection with our initial issuance of shares of Series A Preferred Stock. This non-cash dividend reflects the implied economic value to the preferred stockholder of being able to convert the shares into common stock at a price which was in excess of the fair value of the Series A Preferred Stock at the time of issuance. The fair value was calculated using the difference between the agreed-upon conversion price of the Series A Preferred Stock into shares of common stock of $8.00 per share and the fair market value of our common stock of $29.27 on the date of issuance of the shares of Series A Preferred Stock. The fair value allocated to the issuance of the Series A Preferred Stock was in excess of the gross proceeds received of $84,000,000 in connection with the sale of the Series A Preferred Stock; however, the deemed dividend on the Series A Preferred Stock for 2006 is limited to the gross proceeds received of $84,000,000. The deemed dividend on preferred stock is a reconciling item and adjusts our reported net loss, together with the preferred stock dividends discussed above, to loss available to common stockholders.
 
39

 
Liquidity and Capital Resources
 
Overview
 
During 2007, we funded our operations primarily from our cash on hand, borrowings on our credit facilities and other loans. In the first half of 2007, we obtained financing for our first five ethanol production facilities and received the first draw under this credit facility in the amount of $76.6 million for our Madera facility. We also received approximately $24.9 million in the first half of 2007, which represented the remaining balance in a restricted cash account from our April 2006 sale of our Series A Preferred Stock. These proceeds were used to fund the continued construction of four ethanol production facilities.
 
In the second half of 2007, we received the second draw under our credit facility in the amount of $50.4 million for our Boardman facility. In the second half of 2007, we also settled certain cost-overruns at our Boardman facility through the issuance of a $6.0 million note due in December 2008. Also in the second half of 2007, after evaluating the overall ethanol market and our production capacity and cost structure, we decided to suspend construction of our Imperial Valley facility near Calipatria, California. At the time of this decision, we owed approximately $30.0 million for work already performed on the project. We borrowed $30.0 million in the fourth quarter of 2007 to help cover these and other costs. See “—Current and Prospective Capital Needs” and “—Notes Payable” below.
 
Sale of Series B Preferred Stock
 
On March 27, 2008, we issued to Lyles United, LLC, 2,051,282 shares of our Series B Preferred Stock and a ten-year warrant to purchase an aggregate of 3,076,923 shares of our common stock at an exercise price of $7.00 per share for an aggregate purchase price of $40.0 million. Each share of Series B Preferred Stock is initially convertible into three shares of our common stock. We intend to use the proceeds from the sale of our Series B Preferred Stock for general working capital purposes and to further fund the construction of our Burley and Stockton ethanol production facilities.
 
Current and Prospective Capital Needs
 
We believe that current and future capital resources, revenues generated from operations and other existing sources of liquidity, including available proceeds from our existing debt financing, will be adequate to fund our operations through 2008 and meet our capital expenditure requirements to reach our goal of 220 million gallons of annual production capacity in 2008 upon completion of our Burley and Stockton facilities.  We will require substantial additional financing to reach our goal of 420 million gallons of annual production capacity in 2010 and we plan to reach this goal through new construction or acquisition of additional ethanol production facilities.  If ethanol production margins deteriorate from current levels, if we experience additional cost overruns at our ethanol production facilities under construction, if our capital requirements or cash flows otherwise vary materially and adversely from our current projections, or if other adverse unforeseen circumstances occur, our working capital may be inadequate to fully fund our operations or meet our capital expenditure requirements, or both. We are presently exploring potential sources of new financing to provide additional working capital.  Our failure to raise capital if or when needed may have a material adverse effect on our results of operations, liquidity and cash flows and may restrict our growth and hinder our ability to compete.
 
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We have recently raised $30.0 million in debt financing from Lyles United, LLC and $40.0 million through the sale of our Series B Preferred Stock and a warrant to Lyles United, LLC.  Our need for this additional capital was due to numerous factors that arose or that we identified in the fourth quarter of 2007.  We experienced higher than forecast construction costs at our Burley and Stockton facilities as a result of unanticipated change orders.  We also incurred higher costs related to the completion of “punch list” items at our Boardman facility and costs related to the suspension of construction of our Imperial Valley facility.  In aggregate, these cost overruns that arose or that were identified in the fourth quarter of 2007 were approximately $27.0 million.  In addition, funding under our construction loan facility will occur later than previously anticipated.  Consequently, we expect to fund approximately $29.0 million for the ongoing construction of our Burley and Stockton facilities.  We expect a significant portion of the $29.0 million to be recovered upon completion of our Burley and Stockton facilities, at which time we expect to draw additional loan proceeds under the terms of our existing construction loan facility.  In addition to the above factors, we also continued to experience adverse ethanol market conditions during the fourth quarter of 2007.  The effects of lower than expected commodity margins—the difference between the selling price of ethanol and the cost of corn—caused our cash generated from operations to be lower than forecast.
 
Quantitative Year-End Liquidity Status
 
We believe that the following amounts provide insight into our liquidity and capital resources. The following selected financial data 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):

   
As of and for the Year Ended
       
   
December 31,
2007
   
December 31, 2006
   
Variance
 
Current assets
  $ 82,193     $ 127,045       (35.3 )%
Current liabilities
  $ 120,079     $ 30,951       288.0 %
Property and equipment, net
  $ 468,704     $ 196,156       138.9 %
Notes payable, net of current portion
  $ 151,188     $ 28,970       421.9 %
Cash provided by (used in) operating activities
  $ 16,718     $ (8,144 )     305.3 %
Working capital
  $ (37,886 )   $ 96,094       (139.4 )%
Working capital ratio
    0.68       4.10       (83.4 )%
 
Change in Working Capital and Cash Flows
 
Working capital decreased to a deficit of $37,886,000 at December 31, 2007 from working capital of $96,094,000 at December 31, 2006 as a result of a decrease in current assets of $44,852,000 and an increase in current liabilities of $89,128,000.
 
Current assets decreased primarily due to net decreases in cash and cash equivalents and investments in marketable securities of $38,346,000 and $19,766,000, respectively, the proceeds of which were predominantly used for costs associated with the construction of ethanol production facilities, and a decrease in accounts receivable of $1,288,000, which were partially offset by an increase in inventory of $10,945,000, primarily resulting from an increase in ethanol held in inventory, and an increase in all other current assets of $3,120,000.
 
Current liabilities increased primarily due to an increase in construction-related accounts payable and accrued liabilities of $52,172,000, an increase in trade accounts payable of $13,683,000, an increase in current portion of long-term notes payable of $6,973,000, a short-term note payable of $6,000,000, an increase in contract retentions of $5,001,000, an increase in derivative liabilities of $10,256,000, an increase in accrued liabilities of $2,440,000 and an increase in all other liabilities of $1,125,000, which were partially offset by a net decrease in other liabilities – related parties of $8,522,000.
 
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The decrease in working capital was primarily due to construction activity during the year, requiring the use of our cash and investments in marketable securities balances and increased construction-related accounts payable and accrued expenses. The decrease in working capital was also due in part to increased short- and long-term financing, which increased the current portion of our debt.
 
Cash provided by our operating activities of $16,718,000 resulted primarily from an increase in accounts payable and accrued expenses of $10,332,000, depreciation and amortization of intangibles of $17,513,000, non-controlling interest in our variable interest entity of $9,676,000, derivative losses of $6,617,000, amortization of deferred financing fees of $4,726,000, non-cash compensation and consulting expense of $2,225,000 and a decrease in accounts receivable of $1,230,000, which were partially offset by an increase in inventories of $10,945,000 and other liabilities – related parties of $8,524,000.
 
Cash used in our investing activities of $166,214,000 resulted from purchases of additional property and equipment of $210,482,000 which were partially offset by a decrease in restricted cash designated for construction of $24,851,000 and proceeds from sales of marketable securities of $19,417,000.
 
Cash provided by our financing activities of $111,150,000 resulted primarily from proceeds from our debt financing and lines of credit of $137,725,000 and proceeds from the exercise of warrants and stock options of $2,257,000, which were partially offset by cash paid for debt issuance costs of $10,261,000, principal payments paid on borrowings of $8,678,000 and preferred stock dividends paid of $4,200,000.
 
Changes in Other Assets and Liabilities
 
Property and equipment, net, increased to $468,704,000 at December 31, 2007 from $196,156,000 at December 31, 2006 primarily as a result of the construction of ethanol plants.
 
Restricted cash decreased to $0 at December 31, 2007 from $24,851,000 at December 31, 2006. We received approximately $24,851,000 in the first half of 2007, which represented the remaining balance in a restricted cash account from our April 2006 sale of our Series A Preferred Stock.
 
Notes payable, net of current portion, increased to $151,188,000 at December 31, 2007 from $28,970,000 at December 31, 2006 primarily as a result of loan proceeds used for construction activities at our ethanol plants under construction. The proceeds from these notes payable were primarily from our debt financing arrangement described below.
 
Debt Financing
 
On February 27, 2007, we closed a debt financing transaction in the aggregate amount of up to $325,000,000 through certain of our indirectly wholly-owned subsidiaries. The primary purpose of the debt financing was to provide debt financing for the development, construction, installation, engineering, procurement, design, testing, start-up, operation and maintenance of five ethanol production facilities. On November 27, 2007, we amended the related credit agreement to apply to four ethanol production facilities, thereby reducing the aggregate amount of available financing to up to $250,769,000. As of December 31, 2007, two of the four plants had been funded, with the remaining two expected to be funded in 2008. As of that date, the outstanding balance under the debt financing was $101,508,000, comprised of $92,308,000 in construction loans and $9,200,000 in used lines of credit.
 
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Debt financing proceeds are subject to customary conditions precedent, including, among others, the absence of a material adverse effect; the absence of defaults or events of defaults, which include the existence of any material weakness in our internal control over financial reporting; the accuracy of certain representations and warranties; the maintenance of a debt-to-equity ratio that is not in excess of 65:35; the contribution of all required equity by us to the Borrowers, which is expected to be approximately $227,000,000 in the aggregate; and the attainment of at least a 1.5-to-1.0 debt service coverage ratio. Also, the Borrowers may not be able to fully utilize the debt financing if the completed ethanol plants fail to meet certain minimum performance standards or if the corresponding ethanol plants are not timely completed. Borrowings and the borrowers’ obligations under the debt financing are secured by a first-priority security interest in all of our equity interests in the borrowers and substantially all the assets of the borrowers. The security interests granted by the borrowers under the debt financing restrict the assets and revenues of the borrowers and therefore may inhibit our ability to obtain other debt financing.
 
In March 2008, we became aware of various events or circumstances which constituted defaults under our Credit Agreement. These events or circumstances included the existence of material weaknesses in our internal control over financial reporting as of December 31, 2007, cash management activities that violated covenants in our Credit Agreement, failure to maintain adequate amounts in a designated debt service reserve account, the existence of a number of Eurodollar loans in excess of the maximum number permitted under our Credit Agreement, and our failure to pay all remaining project costs on our Madera and Boardman facilities by certain stipulated deadlines. On March 26, 2008, we obtained waivers from our lenders as to these defaults and were required to pay the lenders a consent fee in an aggregate amount of up to approximately $600,000. In addition to the waivers, our lenders agreed to amend the Credit Agreement. These amendments include an increase in the frequency with which we are to deposit certain revenues into a restricted account each month, an increase the allowable Eurodollar loans from a maximum of seven to a maximum of ten, and we are required to pay all remaining project costs on our Madera and Boardman facilities by May 16, 2008.
 
Line of Credit
 
In addition to the above debt financing, in August 2007, we secured a working capital credit facility in the amount of up to $25,000,000 which expires in July 2009. As of December 31, 2007, we had $6,217,000 outstanding under this credit facility under two separate variable interest rates of 6.19% and 6.75%.
 
Notes Payable
 
In November and December 2007, one of our subsidiaries borrowed an aggregate of $30,000,000 in two separate loans of $15,000,000 each. The loans accrue interest at a rate equal to the Prime Rate of interest as reported from time to time in The Wall Street Journal, plus 2.00%. The November 2007 is due February 25, 2009. The December 2007 loan is due on March 31, 2008 or, if extended at our discretion, on March 31, 2009. We intend to extend the due date of the December 2007 loan. Both loans are secured by substantially all of our subsidiary’s assets. In addition, we have executed a corporate guaranty that guarantees the repayment of the loans.
 
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Contractual Obligations
 
The following table outlines payments due under our significant contractual obligations (in thousands):
 
Contractual Obligations
At December 31, 2007
 
2008
   
2009
   
2010
   
2011
   
2012
   
Thereafter
   
Total
 
Sourcing commitments(1)
  $ 76,780     $     $     $     $     $     $ 76,780  
Debt principal
    13,637       53,465       7,260       17,546       5,661       70,717       168,286  
Debt interest
    14,787       13,898       9,416       8,749       7,243       18,396       72,489  
Operating leases(2)
    2,247       2,434       2,425       2,267       1,965       10,282       21,620  
Firm capital commitments(3)
    118,357                                     118,357  
Preferred dividends(4)
    4,253       4,253       4,253       4,253       4,253       4,253       25,518  
                                                         
Total commitments
  $ 230,061     $ 74,050     $ 23,354     $ 32,815     $ 19,122     $ 103,648     $ 483,050  
 
__________
 
(1)
Unconditional purchase commitments for production materials incurred in the normal course of business.
 
(2)
Future minimum payments under non cancelable operating leases.
 
(3)
Construction commitments for in-progress and contracted ethanol processing facilities
 
(4)
Represents dividends on 5,315,625 shares of Series A Preferred Stock.
 
The above table outlines our obligations as of December 31, 2007 and does not reflect the changes in our obligations that occurred after that date.
 
 
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 it has persuasive evidence of an arrangement, delivery has occurred, the sales price is fixed or determinable, and collection is reasonably assured in conformity with Staff Accounting Bulletin No. 104, Revenue Recognition.
 
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 our facilities.
 
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·    
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 risk and rewards of inventory ownership remains with third-party suppliers as we receive a predetermined service fee under these transactions and therefore act predominantly in an agency capacity. When acting as an agent for third-party suppliers, we conduct back-to-back purchases and sales in which we match ethanol purchase and sales contracts of like quantities and delivery periods.
 
We have employed the principles detailed in Emerging Issues Task Force (“EITF”) Issue No. 99-19, Reporting Revenue Gross as a Principal Versus Net as an Agent, as guidance in our revenue recognition policies. 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 only, based upon the amount of net revenues retained in excess of amounts paid to suppliers.
 
Consolidation of Variable Interest Entities.
 
We have determined that Front Range meets the definition of a variable interest entity under the Financial Accounting Standards Board’s (“FASB”) Financial Interpretation No. (“FIN”) 46(R), Consolidation of Variable Interest Entities. We have also determined that we are the primary beneficiary and we are 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 have consolidated the financial results of Front Range, including its entire balance sheet with the balance of the noncontrolling interest displayed between liabilities and equity, and the income statement after intercompany eliminations with an adjustment for the noncontrolling interest in net income since our acquisition on October 17, 2006. Under FIN 46(R), and as long as we are deemed the primary beneficiary of Front Range, we must treat Front Range as a consolidated subsidiary for financial reporting purposes.
 
Impairment of Intangible and Long-Lived Assets
 
Our intangible assets, including goodwill, were derived from the acquisition of our interest in Front Range in 2006 and our acquisition of Kinergy in 2005 in connection with the Share Exchange Transaction. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 141, we allocated the respective purchase prices to the tangible assets, liabilities and intangible assets acquired based upon their estimated fair values. The excess purchase prices over the fair values of the assets acquired and liabilities assumed were recorded as goodwill. Our long-lived assets are primarily associated with our ethanol production facilities.
 
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We account for goodwill and intangible assets with indefinite lives in accordance with SFAS No. 142. We review these assets 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. Any assessed impairments will be recorded permanently and expensed in the period in which the impairment is determined. If it is determined through our assessment process that any of our intangible assets require impairment charges, they will be recorded in the line item other operating charges in the consolidated statements of operations. We performed our annual review of impairment and we have not recognized any impairment losses on any of our intangible assets through December 31, 2007.
 
We evaluate impairment of long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. 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 suggest the fair value of assets could be less then their net book value. In such event, we assess long-lived assets for impairment by determining their fair value based on the forecasted, undiscounted cash flows the assets are expected to generate plus the net proceeds expected from the sale of the asset. An impairment loss would be recognized when the fair value is less than the related asset’s 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 capital spending decisions of our customers. We have not recognized any impairment losses on long-lived assets through December 31, 2007.
 
Stock-Based Compensation
 
Effective January 1, 2006, we adopted the fair value method of accounting for employee stock compensation cost pursuant to SFAS No. 123(R), Share-Based Payments. Prior to that date, we used the intrinsic value method under Accounting Policy Board Opinion No. 25 to recognize compensation cost. Under the method of accounting for the change to the fair value method, compensation cost recognized is the same amount that would have been recognized if the fair value method would have been used for all awards granted. The effects on net income and income per share had the fair value method been applied to all outstanding and unvested awards in each period are reflected in Note 15 of the consolidated financial statements.
 
Our assumptions made for purposes of estimating the fair value of our stock options, as well as a summary of the activity under our stock option plan are included in Note 15 of the consolidated financial statements.
 
We account for the stock options granted to non-employees in accordance with EITF Issue No. 96-18, Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services, and SFAS No. 123(R).
 
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Derivative Instruments and Hedging Activities
 
Our business and activities expose us to a variety of market risks, including risks related to changes in commodity prices and interest rates. We monitor and manage these financial exposures as an integral part of our risk management program. This program recognizes the unpredictability of financial markets and seeks to reduce the potentially adverse effects that market volatility could have on operating results. We account for our use of derivatives related to our hedging activities pursuant to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, in which we recognize all of our derivative instruments in our statement of financial position as either assets or liabilities, depending on the rights or obligations under the contracts. We have designated and documented contracts for the physical delivery of commodity products to and from counterparties as normal purchases and normal sales. Derivative instruments are measured at fair value, pursuant to the definition found in SFAS No. 107, Disclosures about Fair Value of Financial Instruments. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s effective gains and losses to be deferred in accumulated other comprehensive income and later recorded together with the gains and losses to offset related results on the hedged item in the statements of operations. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
 
The estimated gains (losses) on our derivatives were as follows (in thousands):

   
December 31,
 
   
2007
   
2006
 
Commodity futures
  $ (6,702 )   $ 646  
Commodity options
    1,371       (24 )
Interest rate options
    (5,590 )     (17 )
Total
  $ (10,921 )   $ 605  
 
Allowance for Doubtful Accounts
 
We primarily sell ethanol to gasoline refining and distribution companies. We also sell WDG to dairy operators and animal feed distributors. We had significant concentrations of credit risk as of December 31, 2007, as described in Note 1 to our consolidated financial statements. However, those 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.
 
Costs of Start-up Activities
 
Start-up activities are defined broadly in Statement of Position 98-5, Reporting on the Costs of Start-Up Activities, as those one-time activities related to opening a new facility, introducing a new product or service, conducting business in a new territory, conducting business with a new class of customer or beneficiary, initiating a new process in an existing facility, commencing some new operation or activities related to organizing a new entity. Our start-up activities consist primarily of costs associated with new or potential sites for ethanol production facilities. We expense all the costs associated with a potential site, until the site is considered viable by management, at which time costs would be considered for capitalization based on authoritative accounting literature. These costs are included in selling, general, and administrative expenses in our consolidated statements of operations.
 
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Impact of New Accounting Pronouncements
 
In March 2008, the FASB issued SFAS No. 161, Disclosure about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133. SFAS No. 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement No. 133 and its related interpretations and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We are currently evaluating the impact SFAS No. 161 may have on our consolidated financial statements.
 
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. SFAS No. 141(R) retains the fundamental requirements in SFAS No. 141 that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) requires an acquirer to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions specified in SFAS No. 141(R). In addition, SFAS No. 141(R) requires acquisition costs and restructuring costs that the acquirer expected but was not obligated to incur to be recognized separately from the business combination, therefore, expensed instead of part of the purchase price allocation. SFAS No. 141(R) will be applied prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Early adoption is prohibited. We expect to adopt SFAS No. 141(R) to any business combinations with an acquisition date on or after January 1, 2009.
 
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment to ARB No. 51. SFAS No. 160 changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. We are currently evaluating the impact SFAS No. 160 may have on our consolidated financial statements.
 
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits an entity to irrevocably elect fair value on a contract-by-contract basis as the initial and subsequent measurement attribute for many financial assets and liabilities and certain other items including insurance contracts. Entities electing the fair value option would be required to recognize changes in fair value in earnings and to expense upfront costs and fees associated with the item for which the fair value option is elected. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provisions of SFAS No. 157, Fair Value Measurements. We do not expect the adoption of SFAS No. 159 to have a material impact on our financial condition or results of operations.
 
In September 2006, the FASB issued SFAS No. 157. This new statement provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. The original required effective date of SFAS No. 157 was the first quarter of 2008, however, the FASB issued FASB Staff Position 157-2, Effective Date of FASB Statement No. 157, which deferred the adoption date by one year for all nonfinancial assets and nonfinancial liabilities. We are currently evaluating the impact SFAS No. 157 may have on our consolidated financial statements.
 
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Item 7A.     Quantitative and Qualitative Disclosures About Market Risk.
 
We are exposed to various market risks, including changes in commodity prices and interest rates. Market risk is the potential loss arising from adverse changes in market rates and prices. In the ordinary course of business, we enter into various types of transactions involving financial instruments to manage and reduce the impact of changes in commodity prices and interest rates. We do not enter into derivatives or other financial instruments for trading or speculative purposes.
 
Commodity RiskCash Flow Hedges
 
As part of our risk management strategy, we use derivative instruments to protect cash flows from fluctuations caused by volatility in commodity prices for periods of up to twelve months. These hedging activities are conducted to protect gross margins to reduce the potentially adverse effects that market volatility could have on operating results by minimizing our exposure to price volatility on ethanol sale and purchase commitments where the price is to be set at a future date and/or if the contract specifies a floating or index-based price for ethanol that is based on either the New York Mercantile Exchange price of gasoline or the Chicago Board of Trade price of ethanol. In addition, we hedge anticipated sales of ethanol to minimize our exposure to the potentially adverse effects of price volatility. These derivatives are designated and documented as SFAS No. 133 cash flow hedges and effectiveness is evaluated by assessing the probability of the anticipated transactions and regressing commodity futures prices against our purchase and sales prices. Ineffectiveness, which is defined as the degree to which the derivative does not offset the underlying exposure, is recognized immediately in income. For the year ended December 31, 2007, a gain from ineffectiveness in the amount of $2,832,000 and an effective loss in the amount of $1,680,000 were recorded in cost of goods sold. For the year ended December 31, 2006, losses of ineffectiveness in the amount of $239,000 and an effective loss in the amount of $438,000 were recorded in cost of goods sold. For the year ended December 31, 2006, an effective gain in the amount of $1,281,000 was recorded in sales. Amounts remaining in accumulated other comprehensive income (loss) will be reclassified to income upon the recognition of the related purchase or sale. Accumulated other comprehensive loss in the amount of $455,000 associated with commodity cash flow hedges is expected to be recognized in income over the next twelve months. The notional balance of these derivatives as of December 31, 2007 and 2006 was $2,427,000 and $11,588,000, respectively.
 
Commodity RiskNon-Designated Derivatives
 
As part of our risk management strategy, we use forward contracts on corn, crude oil and reformulated blendstock for oxygenate blending gasoline to lock in prices for certain amounts of corn, denaturant and ethanol, respectively. These derivatives are not designated under SFAS No. 133 for special hedge accounting treatment. The changes in fair value of these contracts are recorded on the balance sheet and recognized immediately in cost of goods sold. We recognized a loss of $6,484,000 (of which $3,532,000 is related to settled non-designated hedges) and $0 as the change in the fair value of these contracts for the year ended December 31, 2007 and 2006, respectively. The notional balances remaining on the contracts as of December 31, 2007 and 2006 were $29,999,000 and $0, respectively.
 
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Interest Rate Risk
 
As part of our interest rate risk management strategy, we use derivative instruments to minimize significant unanticipated earnings fluctuations that may arise from rising variable interest rate costs associated with existing and anticipated borrowings. To meet these objectives we purchased interest rate caps and swaps. The rate for notional balances of interest rate caps ranging from $0 to $21,588,000 is 5.50%-6.00% per annum. The rate for notional balances of interest rate swaps ranging from $0 to $63,219,000 is 5.01%-8.16% per annum. These derivatives are designated and documented as SFAS No. 133 cash flow hedges and effectiveness is evaluated by assessing the probability of anticipated interest expense and regressing the historical value of the rates against the historical value in the existing and anticipated debt. Ineffectiveness, reflecting the degree to which the derivative does not offset the underlying exposure, is recognized immediately in income. For the year ended December 31, 2007, losses from ineffectiveness in the amount of $4,836,000, losses from effectiveness in the amount of $147,000 and losses from undesignated hedges in the amount of $606,000 were recorded in other income (expense). For the year ended December 31, 2006, ineffectiveness in the amount of $24,000 was recorded in other income (expense). There was no ineffectiveness for the year ended December 31, 2005. Amounts remaining in accumulated other comprehensive income will be reclassified to income upon the recognition of the hedged interest expense. For the year ending December 31, 2008, we anticipate reclassifying $595,000 to income associated with our cash flow interest rate caps and swaps.
 
We marked all of our derivative instruments to fair value at each period end, except for those derivative contracts which qualified for the normal purchase and sale exemption pursuant to SFAS No. 133. According to our designation of the derivative, changes in the fair value of derivatives are reflected in net income or accumulated other comprehensive income.
 
Accumulated Other Comprehensive Income
 
Accumulated other comprehensive income relative to derivatives for the year ended December 31, 2007 is as follows (in thousands):
 
   
Commodity Derivatives
   
Interest Rate Derivatives
 
   
Gain/(Loss)*
   
Gain/(Loss)*
 
Beginning balance, January 1, 2007
  $ 461     $ (265 )
Net changes
    (2,596 )     (1,810 )
Less:  Amount reclassified to cost of goods sold
    (1,680 )      
Less:  Amount reclassified to other income (expense)
          (147 )
Ending balance, December 31, 2007
  $ (455 )   $ (1,928 )
—————
*Calculated on a pretax basis
 
The estimated fair values of our derivatives were as follows (in thousands):

   
December 31,
 
   
2007
   
2006
 
Commodity futures
  $ (1,649 )   $ 329  
Interest rate options
    (7,091 )     125  
Total
  $ (8,740 )   $ 454  
 
Material Limitations
 
The disclosures with respect to the above noted risks do not take into account the underlying commitments or anticipated transactions. If the underlying items were included in the analysis, the gains or losses on the futures contracts may be offset. Actual results will be determined by a number of factors that are not generally under our control and could vary significantly from the factors disclosed.
 
50

 
We are exposed to credit losses in the event of nonperformance by counterparties on the above instruments, as well as credit or performance risk with respect to our hedged customers’ commitments. Although nonperformance is possible, we do not anticipate nonperformance by any of these parties.
 
Financial Statements and Supplementary Data.
 
Reference is made to the financial statements included in this report, which begin at Page F-1.
 
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
 
None.
 
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, 2007 that our disclosure controls and procedures were not effective at a reasonable assurance level due to the two material weaknesses discussed immediately below.
 
In light of the two material weaknesses described below, we performed additional analysis and other post-closing procedures to ensure that our consolidated financial statements were prepared in accordance with generally accepted accounting principles. Accordingly, we believe that the consolidated financial statements included in this report fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented.
 
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
 
51

 
 
(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, 2007. Based on the results of management’s assessment and evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of December 31, 2007, the following two material weaknesses in our internal control over financial reporting existed:
 
 
(1)
We did not have adequate internal control over our accrual of construction-related costs for our ethanol production facilities; and
 
 
(2)
We did not exercise oversight of our personnel or their actions in a manner reasonably calculated to ensure compliance under the Credit Agreement governing our credit facility.
 
The foregoing material weaknesses are described in detail below under the caption “Material Weaknesses and Related Remediation Initiatives.” As a result of these material weaknesses, our Chief Executive Officer and Chief Financial Officer concluded that we did not maintain effective internal control over financial reporting as of December 31, 2007. If not remediated, these material weaknesses could result in one or more material misstatements in our reported financial statements in a future annual or interim period.
 
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 (“COSO”) in its Internal Control—Integrated Framework. Because of the material weaknesses described above, management believes that, as of December 31, 2007, we did not maintain effective internal control over financial reporting.
 
Our independent registered public accounting firm, Hein & Associates LLP, independently assessed the effectiveness of our internal control over financial reporting. Hein & Associates LLP has issued an attestation report concurring with management’s assessment, which is included herein.
 
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.
 
52

 
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.
 
Material Weaknesses and Related Remediation Initiatives
 
(1)           We did not have adequate internal control over our accrual of construction-related costs for our ethanol production facilities, as evidenced by the following control deficiencies:
 
·    
Our auditors discovered that our accounting staff failed to accrue construction-related costs represented by certain invoices that were set aside for review but overlooked by our accounting staff. During the first quarter of 2008, we implemented the following processes to remediate this deficiency:
 
o   
After our accounts payable subledger is closed for the period, our accounting staff is to communicate with our construction managers to determine whether any invoices or progress billings under their review for the reporting period have not been recorded in our accounts payable subledger; and
 
o   
After our accounts payable subledger is closed for the period, our accounting staff is to segregate any future invoices received for posting that relate to the reporting period. These invoices are to be compared to accrual balances to support the existing construction accruals.
 
·    
Our period-end closing process lacked a method for determining an estimate for invoices not yet received for construction costs as to which we believe a contract liability existed at the end of the reporting period. During the first quarter of 2008, we implemented the following processes to remediate this deficiency:
 
o   
During our period-end closing process, and after our accounts payable subledger is closed for the period, our accounting staff and senior management are to perform construction cost trending analyses for subsidiaries with significant construction related activities during the period. The trend analyses are to be based on vendor activity and management is to review the trend for reasonableness.
 
We believe that we did, however, maintain adequate controls to ensure accruals were properly recorded for non-construction related invoices received subsequent to the closing of our accounts payable subledger. This material weakness resulted in adjustments to our consolidated balance sheet as of December 31, 2007 but had no impact to our consolidated statements of operations for the year ended December 31, 2007. If not remediated, this material weakness could, however, result in one or more material misstatements in our reported financial statements in a future annual or interim period.
 
53

 
(2)           We did not exercise oversight of our personnel or their actions in a manner reasonably calculated to ensure compliance under the Credit Agreement governing our credit facility, as evidenced by the following control deficiencies:
 
·    
Under the terms of the Credit Agreement, we are generally required to deposit all revenues related to the production facilities financed under the Credit Agreement in segregated revenue accounts which are controlled by our lenders. The Credit Agreement includes specific covenants governing our use of those funds. On Wednesday, March 12, 2008, our senior management was informed that an unauthorized deviation from the Credit Agreement requirements related to the segregated revenue accounts had occurred.  These actions, which we believe began in August 2007, were apparently undertaken for the purpose of optimizing our cash position and resulted in the violation of a number of covenants in the Credit Agreement. Based our current analysis, we believe that the net amount of cash that was diverted from the segregated revenue accounts to other internal uses was approximately $3.9 million, which constituted a default under the Credit Agreement.
 
·    
The Credit Agreement required that, on the date of the initial loan fundings for our Madera and Boardman facilities, a designated debt service reserve related to the loans should have been deposited into a debt service reserve account controlled by our lenders.  The amount of $3.4 million has not been deposited as required by the Credit Agreement, which constitutes a default under the Credit Agreement.
 
·    
The Credit Agreement limits us to no more than seven separate Eurodollar loans outstanding at any time. We had eight Eurodollar loans outstanding, which constitutes a default under the Credit Agreement.
 
·    
The Credit Agreement provides that the “final completion” of our Madera and Boardman facilities should already have occurred. One of the conditions to “final completion” is that the borrowers pay all remaining project costs related to the construction of the particular plant. We are still in the process of negotiating final payments with certain contractors.  Both facilities commenced operations and we received loan fundings for the facilities notwithstanding the failure to achieve “final completion” by the stated deadline, which constitutes a default under the Credit Agreement.
 
During the first quarter of 2008, we implemented the following processes to remediate these deficiencies:
 
·    
We have reassigned cash management responsibilities to our Chief Financial Officer.
 
·    
Our Chief Financial Officer is to perform a review of all debt covenants in place as of December 31, 2007 and determine whether we are in compliance with those covenants; as to any covenants with which we are not in compliance, our Chief Financial Officer is to undertake remediation actions to ensure compliance with those covenants in the future.
 
·    
Our Chief Financial Officer is to review, at the end of each future reporting period, compliance reports prepared by his designee, for all debt covenants as to which we received waivers from our lenders.
 
54

 
This material weakness did not result in any adjustments to our 2007 consolidated financial statements. If not remediated, this material weakness could, however, result in one or more material misstatements in our reported financial statements in a future annual or interim period.
 
Expected Remediation Date and Expenditures
 
Management expects that our internal control over financial reporting as to the material weaknesses described above will be tested, and the material weaknesses will be remediated, by September 30, 2008.  Management is unable, however, to estimate our expenditures associated with this remediation, but we do not expect them to be significant, except that we were required to pay a consent fee in the aggregate amount of up to approximately $600,000 in connection with the waivers from our lenders as to certain defaults under our Credit Agreement, including as a result of the material weaknesses described above that existed as of December 31, 2007.
 
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 Exchange 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.
 
Attestation Report of Independent Registered Public Accounting Firm
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Audit Committee and Management
Pacific Ethanol, Inc.
Sacramento, California
 
We have audited Pacific Ethanol, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Pacific Ethanol, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
55

 
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 a deficiency, or a 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. The following material weaknesses have been identified and included in management’s assessment.
 
1.  
The Company did not have adequate internal control over its accrual of construction-related costs for its ethanol production facilities; and
 
2.  
The Company did not exercise oversight of its personnel or their actions in a manner reasonably calculated to ensure compliance under the Credit Agreement governing its credit facility.
 
These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2007 consolidated financial statements, and this report does not affect our report dated March 27, 2008 on those consolidated financial statements
 
In our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Pacific Ethanol, Inc. has not maintained effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pacific Ethanol, Inc. as of December 31, 2007 and 2006, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007, of Pacific Ethanol, Inc. and our report dated March 27, 2008 expressed an unqualified opinion thereon.
 
/s/ HEIN & ASSOCIATES LLP
 
Irvine, California
March 27, 2008
 
  Item 9A(T).     Controls and Procedures.
 
 
Not applicable.
 
Item 9B.     Other Information.
 
None.
 
56

 
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.
 
 
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.



57

 
Index to Financial Statements
 
Report of Independent Registered Public Accounting Firm
F-2
   
Consolidated Balance Sheets as of December 31, 2007 and 2006
F-3
   
Consolidated Statements of Operations for the Years Ended
 
December 31, 2007, 2006 and 2005
F-5
   
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended
 
December 31, 2007, 2006 and 2005
F-6
   
Consolidated Statement of Stockholders’ Equity for the Years Ended
 
December 31, 2007, 2006 and 2005
F-7
   
Consolidated Statements of Cash Flows for the Years Ended
 
December 31, 2007, 2006 and 2005
F-10
   
Notes to Consolidated Financial Statements
F-12
 

 
F-1

 
To the Board of Directors
Pacific Ethanol, Inc.
Sacramento, California
 
We have audited the accompanying consolidated balance sheets of Pacific Ethanol, Inc. as of December 31, 2007 and 2006, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. 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 audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. 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 consolidated financial position of Pacific Ethanol, Inc. at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pacific Ethanol, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Our report dated March 27, 2008 expressed an opinion that Pacific Ethanol, Inc. had not maintained effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
 
/s/ HEIN & ASSOCIATES LLP
 
Irvine, California
March 27, 2008

F-2


PACIFIC ETHANOL, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands)

   
December 31,
 
ASSETS
 
2007
   
2006
 
             
Current Assets:
           
Cash and cash equivalents
  $ 5,707     $ 44,053  
Investments in marketable securities
    19,353       39,119  
Accounts receivable, net (including $7 and $1,195 as
of December 31, 2007 and 2006,
respectively, from a related party)
    28,034       29,322  
Restricted cash
    780       1,567  
Inventories
    18,540       7,595  
Prepaid expenses
    1,498       1,053  
Prepaid inventory
    3,038       2,029  
Derivative instruments
    1,613       551  
Other current assets
    3,630       1,756  
Total current assets
    82,193       127,045  
Property and equipment, net
    468,704       196,156  
Other Assets:
               
Restricted cash
          24,851  
Deposits and advances
    81       9,040  
Goodwill
    88,168       85,307  
Intangible assets, net
    6,324       10,155  
Other assets
    6,130       1,266  
Total other assets
    100,703       130,619  
Total Assets
  $ 651,600     $ 453,820  

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
 
2007
   
2006
 
Current Liabilities:
           
Accounts payable – trade
  $ 22,641     $ 8,958  
Accrued liabilities
    5,570       3,130  
Accounts payable and accrued liabilities – construction-related
    55,203       3,031  
Contract retentions
    5,358       357  
Other liabilities – related parties
    900       9,422  
Current portion – long-term notes payable
    11,098       4,125  
Short-term note payable
    6,000        
Derivative instruments
    10,353       97  
Other current liabilities
    2,956       1,831  
Total current liabilities
    120,079       30,951  
                 
Notes payable, net of current portion
    151,188       28,970  
Other liabilities
    1,965       1,091  
Total Liabilities
    273,232       61,012  
Commitments and contingencies (Notes 9, 16 and 17)
               
Noncontrolling interest in variable interest entity
    96,082       94,363  
Stockholders’ Equity:
               
Preferred stock, $0.001 par value; 10,000,000 shares authorized; 5,315,625 and 5,250,000 shares issued and outstanding as of December 31, 2007 and 2006, respectively
    5       5  
Common stock, $0.001 par value; 100,000,000 shares authorized; 40,606,214 and 40,269,627 shares issued and outstanding as of December 31, 2007 and 2006, respectively
    41       40  
Additional paid-in capital
    402,932       397,536  
Accumulated other comprehensive income (loss)
    (2,383 )     545  
Accumulated deficit
    (118,309 )     (99,681 )
Total stockholders’ equity
    282,286       298,445  
Total Liabilities and Stockholders’ Equity
  $ 651,600     $ 453,820  
 
 
 

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,
 
   
2007
   
2006
   
2005
 
Net sales (including $6,039, $16,985 and $9,060 for the years ended December 31, 2007, 2006 and 2005, respectively, to a related party)
  $ 461,513     $ 226,356     $ 87,599