10-K 1 paceth_10k-123106.htm PACIFIC ETHANOL, INC. Pacific Ethanol, Inc.

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, 2006
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, $.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. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  x
Accelerated filer  ¨
Non-accelerated filer  ¨

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 $725.0 million as of June 30, 2006, 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, $.001 par value, outstanding as of March 7, 2007 was 40,285,227.
 
DOCUMENTS INCORPORATED BY REFERENCE:
 
Part III incorporates by reference certain information from the registrant’s definitive proxy statement (the “Proxy Statement”) for the 2007 Annual Meeting of Stockholders to be filed on or before April 30, 2007.

 




TABLE OF CONTENTS

   
 Page
 
  PART I
 
Item 1.
Business
1
Item 1A.
Risk Factors.
13
Item 1B.
Unresolved Staff Comments.
24
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.
27
Item 6.
Selected Financial Data.
30
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
31
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
49
Item 8.
Financial Statements and Supplementary Data.
51
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
51
Item 9A.
Controls and Procedures
51
Item 9B.
Other Information.
59
     
 
PART III
 
Item 10.
Directors, Executive Officers and Corporate Governance
60
Item 11.
Executive Compensation
60
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
60
Item 13.
Certain Relationships and Related Transactions, and Director Independence
60
Item 14.
Principal Accounting Fees and Services
60
 
PART IV
 
Item 15.
Exhibits, Financial Statement Schedules
60
   
Index to Financial Statements
F-1
Index to Exhibits
Signatures
Exhibits Filed With This Report
 


 
-i-


CAUTIONARY STATEMENT
 
All statements included or incorporated by reference in this Annual Report on Form 10-K, other than statements or characterizations of historical fact, are forward-looking statements. Examples of forward-looking statements include, but are not limited to, statements concerning projected net sales, costs and expenses and gross margins; our accounting estimates, assumptions and judgments; our success in pending litigation; the demand for ethanol and its co-products; the competitive nature of and anticipated growth in our industry; production capacity and goals; our ability to consummate acquisitions and integrate their operations successfully; and our prospective needs for additional capital. These forward-looking statements are based on our current expectations, estimates, approximations and projections about our industry and business, management’s beliefs, and certain assumptions made by us, all of which are subject to change. Forward-looking statements can often be identified by words such as “anticipates,” “expects,” “intends,” “plans,” “predicts,” “believes,” “seeks,” “estimates,” “may,” “will,” “should,” “would,” “could,” “potential,” “continue,” “ongoing,” similar expressions, and variations or negatives of these words. These statements are not guarantees of future performance and are subject to risks, uncertainties and assumptions that are difficult to predict. Therefore, our actual results could differ materially and adversely from those expressed in any forward-looking statements as a result of various factors, some of which are listed under “Risk Factors” in Item 1A of this Report. These forward-looking statements speak only as of the date of this Report. We undertake no obligation to revise or update publicly any forward-looking statement for any reason, except as otherwise required by law.
 
PART I
 
Item 1.     Business
 
Business Overview
 
Our primary goal is to become the leading marketer and producer of 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, Washington, Oregon and Colorado. We have extensive customer relationships throughout the Western United States and extensive supplier relationships throughout the Western and Midwestern United States.
 
In October 2006, we completed construction of an ethanol production facility with nameplate annual production capacity of 35 million gallons located in Madera, California, and began producing ethanol. In October 2006, we also acquired approximately 42% of the outstanding membership interests of Front Range Energy, LLC, or Front Range, which owns and operates an ethanol production facility with nameplate annual production capacity of 40 million gallons located in Windsor, Colorado. In addition, we are currently constructing or in advanced stages of development of four additional ethanol production facilities. We also intend to construct or otherwise acquire additional ethanol production facilities as financial resources and business prospects make the construction or acquisition of these facilities advisable. See “—Production Facilities” below.
 
Total annual gasoline consumption in the United States is approximately 140 billion gallons. Total annual ethanol consumption currently represents less than 4% of annual gasoline consumption, or approximately 5.1 billion gallons of ethanol. We believe that the domestic ethanol industry has substantial potential for growth to 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. In California alone, an increase in the consumption of ethanol from California’s current level of 5.7%, or approximately 1.0 billion gallons of ethanol per year, to at least 10% of total annual gasoline consumption would result in consumption of approximately 700 million additional gallons of ethanol, representing an increase in annual ethanol consumption in California alone of approximately 75% and an increase in annual ethanol consumption in the entire United States of approximately 13%.
 
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We intend to achieve our goal of becoming the leading marketer and producer of renewable fuels in the Western United States in part by expanding our production capacity to 220 million gallons of annual production capacity by the second quarter of 2008 and 420 million gallons of annual production capacity by the end of 2010. We intend to achieve this goal in part also by expanding our relationships with third-party ethanol producers to market higher volumes of ethanol throughout the Western United States, 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 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 ultimately as a primary transportation fuel. We also intend to expand our distribution infrastructure by expanding 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. Following our incorporation, 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 strong business relationships with our customers and suppliers. In particular, we have developed strong 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 strong 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 significant competitive advantages, including transportation cost and delivery timing and logistical advantages and 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. 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 produce.
 
Business and Growth Strategy
 
Our primary goal is to become the leading marketer and producer of 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 expanding our ability to provide transportation, storage and related logistical services to our customers throughout the Western United States.
 
· 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 production capacity to 220 million gallons of annual production capacity by the second quarter of 2008 and 420 million gallons of annual production capacity by the end of 2010.
 
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· 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 the following:
 
 
o
Locations near fuel blending facilities will enable lower ethanol transportation costs and enjoy timing and logistical advantages over competing locations requiring ethanol to be shipped over much longer distances.
 
 
o
Locations adjacent to major rail lines will enable the purchase of corn from major corn-producing regions for efficient delivery in large-scale trains.
 
 
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 newly constructed 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.
 
· 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 primarily on a fixed-price basis and, to a lesser extent, by purchasing corn and natural gas futures contracts. To mitigate ethanol inventory price risks, we may sell a portion of our production forward under fixed-price and indexed contracts. We may hedge a portion of the price risks associated with index 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 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.
 
Industry Overview and Market Opportunity
 
Overview of Ethanol Market 
 
The primary applications for fuel-grade ethanol in the United States today 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. In addition, ethanol is commonly added to finished regular grade gasoline as a means of producing higher octane midgrade and premium gasoline.
 
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· 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 today is done for the purpose of extending the volume of fuel sold at the gas pump. Furthermore, the experience in Brazil, where ethanol accounts for 40% of all vehicle fuels and is sold in blends with gasoline ranging from 25% to 100%, suggests that ethanol could capture a much greater portion of the United States market in the future.
 
· Renewable fuels. Ethanol is blended with gasoline in order to enable gasoline refiners to comply with a variety of governmental programs, notably the national renewable fuels standard, or RFS, designed to promote alternatives to fossil fuels. See “—Government Regulation.”
 
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 Policy Act of 2005, which was signed into law in by President Bush in August 2005, enacted the RFS. The RFS sets a minimum amount of renewable fuels (i.e., ethanol, biodiesel or any other liquid fuel produced from biomass or biogas) that must be used by fuel refiners. Beginning in 2006, the minimum amount of renewable fuels that must be used by fuel refiners is 4.0 billion gallons, which increases progressively to 7.5 billion gallons in 2012. 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 the demand depending on the preferences of petroleum refiners and state policies. See “Risk Factors.”
 
We believe that the domestic ethanol industry produced approximately 4.9 billion gallons of ethanol in 2006, an increase of approximately 25% from the approximately 3.9 billion gallons of ethanol produced in 2005. We believe that the ethanol market in California alone was approximately 1.0 billion gallons in 2006, representing approximately 20% of the national market. However, the Western United States has relatively few ethanol plants with ethanol production levels substantially below the 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.
 
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Ethanol prices, net of tax incentives offered by the federal government, are generally positively correlated to fluctuations in gasoline prices. In addition, we believe that ethanol prices in the Western United States are typically $0.15 to $0.20 per gallon higher than in the Midwest due to the freight costs of delivering ethanol from Midwest production facilities.
 
Total annual gasoline consumption in the United States is approximately 140 billion gallons and total annual ethanol consumption currently represents less than 4% of this amount, or approximately five billion gallons of ethanol. We believe that the domestic ethanol industry has substantial potential for growth to 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.
 
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.
 
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.
 
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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 them 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 protein 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.
 
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 2006 and 2005, we produced or purchased from third parties and resold an aggregate of approximately 102 million and 67 million gallons of fuel-grade ethanol to approximately 60 customers and 27 customers, respectively. Sales to our two largest customers represented approximately 25% of our net sales in 2006 and sales to our three largest customers represented approximately 39% of our net sales in 2005. Sales to each of our other customers did not represent 10% or more of our net sales in either 2006 or 2005. 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.
 
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 profitability. 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.
 
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In addition to producing ethanol, we produce ethanol co-products such as WDG. We expect to be one of the few WDG producers with production facilities located in the Western United States. We intend 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 minerals and other feed ingredients. We believe that WDG has an ideal moisture level to carry minerals and other feed ingredients and we expect to increase our profit margins by providing WDG to the feed market in the Western United States.
 
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 are expanding to support the continuing growth of our business.
 
During 2006 and 2005, we purchased an aggregate of approximately 88 million and 67 million gallons of fuel-grade ethanol from approximately 22 suppliers and 15 suppliers, respectively. Purchases from our four and three largest suppliers represented approximately 64% and 59% of our total purchases in 2006 and 2005, respectively. Purchases from each of our other suppliers did not represent 10% or more of total purchases in either 2006 or 2005.
 
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 then cheaply and reliably truck processed 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 in 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 as of March 2007 of our existing ethanol production facilities and our facilities under construction or development.
 
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Madera
Facility
 
Front Range
Facility(1)
 
Boardman
Facility(2)
 
California
Facility(2)
 
Imperial Valley
Facility(2)
Magic
Valley
Facility(2)
 
Location
 
Madera, CA
 
Windsor, CO
 
Boardman, OR
 
TBA
 
Brawley, CA
 
Burley, ID
 
Quarter/Year completed or scheduled to be completed
 
4th Qtr., 2006
 
 
2nd Qtr., 2006
 
 
2nd Qtr., 2007
 
 
2nd Qtr., 2008
 
 
2nd Qtr., 2008
 
 
2nd Qtr., 2008
 
 
Annual ethanol nameplate production capacity (in millions of gallons)
 
35
 
 
40
 
 
35
 
 
50
 
 
50
 
 
50
 
 
Ownership
 
100%
 
42%
 
100%
 
100%
 
100%
 
100%
 
Primary energy source
 
Natural Gas
 
Natural Gas
 
Natural Gas
 
Natural Gas
 
Natural Gas
 
Natural Gas
 
Estimated annual WDG production capacity (in thousands of tons)
 
293
 
335
 
293
 
418
 
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.
 
Potential Future Facilities and Expansions
 
We intend to expand our production capacity to 220 million gallons of annual production capacity by the second quarter of 2008 and 420 million gallons of annual production capacity by the end of 2010. 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 their 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, which was recently acquired by 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 nameplate production capacity of 40 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.
 
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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 23% of total United States ethanol production in 2006. According to the RFA, as of January 2006, there were approximately 110 ethanol plants currently operating with a combined annual production capacity of approximately 5.5 billion gallons. In addition, 73 ethanol plants and 8 expansions of existing plants were under construction with an estimated combined future annual production capacity of approximately 6.0 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 strong customer and supplier relationships, our use of modern technologies at our production facilities and our experienced management. We believe that these advantages will allow us to capture an increasing share of the total market for ethanol and its co-products and earn favorable margins on ethanol and its co-products that we produce.
 
Our strategic focus on particular geographic locations designed to exploit cost efficiencies may nevertheless result in higher than expected costs as a result of more expensive raw materials and related shipping costs, 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 be lost.
 
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.
 
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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.
 
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 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 County ethanol plant, 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 currently 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.
 
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These state mandates in recent years have created a variety of gasoline grades to meet different regional environmental requirements. RFG accounts for about 30% of nationwide gasoline consumption. California refiners blend a minimum of 2.0% oxygen by weight. This is the equivalent of 5.7% ethanol in every gallon of gas, or roughly 1.0 billion gallons of ethanol per year in California alone.
 
National Energy Legislation
 
The Energy Policy Act of 2005 was signed into law by President Bush in August 2005. The Energy Policy Act of 2005 substituted the then existing oxygenation program in the RFG program with the RFS. The RFS sets a minimum amount of renewable fuels that must be used by fuel refiners. Beginning in 2006, the minimum amount of renewable fuels that must be used by fuel refiners is 4.0 billion gallons, which increases progressively to 7.5 billion gallons in 2012. While we believe that the overall national market for ethanol will grow, we also 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.”
 
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.
 
On January 18, 2007, California’s Governor signed an executive order directing the California Air Resource Board, or CARB, 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 the year 2020.
 
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 CARB. 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 7, 2007, we employed 78 persons on a full-time basis, including through our subsidiaries. Our employees are highly skilled, and our success will depend in part upon our ability to retain such 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.
 
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Item 1A.      Risk Factors.
 
Risks Related to our Business
 
We have incurred losses in the past and we may incur losses in the future. If we continue to incur losses, we will experience negative cash flow, which may hamper our operations, may prevent us from expanding our business and may cause our stock price to decline.
 
We have incurred losses in the past. For the years ended December 31, 2006 and 2005, we incurred net losses of approximately $142,000 and $9.9 million, respectively. We expect to rely on cash on hand, cash, if any, generated from our operations and future financing activities to fund all of the cash requirements of our business. If our net losses continue, we will experience negative cash flow, which may hamper current operations and may prevent us from expanding our business. We may be unable to attain, sustain or increase profitability on a quarterly or annual basis in the future. If we do not achieve, sustain or increase profitability our stock price 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.
 
Our revenue is and will continue to be derived primarily from sales of ethanol. Currently, the predominant oxygenate used to blend with gasoline is ethanol. Ethanol competes with several other existing products and other alternative products could also be developed for use as fuel additives. 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 significantly and adversely affect our sales and profitability.
 
If the expected increase in ethanol demand does not occur, or if ethanol demand decreases, there may be excess capacity in our industry which would likely cause a decline in ethanol prices, adversely impacting our results of operations, cash flows and financial condition.
 
Domestic ethanol production capacity has increased steadily from an annualized rate of 1.7 billion gallons per year in January of 1999 to 5.5 billion gallons per year in December 2006 according to the RFA. In addition, there is a significant amount of capacity being added to our industry. We believe that approximately 4.6 billion gallons per year of production capacity is currently under construction. This capacity is being added to address anticipated increases in demand. Moreover, under the United States Department of Agriculture’s CCC Bioenergy Program, which expired September 30, 2006, the federal government made payments of up to $150 million annually to ethanol producers that increase their production. This created an additional incentive to develop excess capacity. However, demand for ethanol may not increase as quickly as expected, or at all. If the ethanol industry has excess capacity, a fall in prices will likely occur which will have an adverse impact on our results of operations, cash flows and financial condition. Excess capacity may result from the increases in capacity coupled with insufficient demand. Demand 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. For example, price increases could cause businesses and consumers to reduce driving or acquire vehicles with more favorable gasoline mileage capabilities.
 
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We have identified seven 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 seven material weaknesses in our internal control over financial reporting: (i) we had not effectively implemented comprehensive entity-level internal controls; (ii) we did not have a sufficient complement of personnel with appropriate training and experience in generally accepted accounting principals; (iii) we did not adequately segregate the duties of different personnel within our accounting group due to an insufficient complement of staff; (iv) we did not perform adequate oversight of certain accounting functions and maintained inadequate documentation of management review and approval of accounting transactions and financial reporting processes; (v) we did not have adequate controls governing major account invoice processing and payment; (vi) we had not fully implemented certain control activities and capabilities included in the design of our enterprise resource platform, or ERP, system; and (vii) we did not have adequate access and data and formulaic integrity controls over critical spreadsheets used in connection with accounting and financial reporting. See “Controls and Procedures.”
 
Our management, including our Chief Executive Officer and Acting Chief Financial Officer, does not expect that our internal control over financial reporting will prevent all error 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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We may not be able to implement our planned expansion strategy, including as a result of our failure to successfully manage our growth, which would prevent us from achieving our goals.
 
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 additional financing to implement our expansion strategy and we may not have access to the funding required for the expansion of our business or such funding may not be available to us on acceptable terms. We plan to finance the expansion of our business with additional indebtedness. We may also issue additional equity securities to help finance our expansion. 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 are initially using our existing cash to implement this strategy based on the belief that we can secure additional debt financing in the future in order to complete our expansion. If we are unable to secure this debt financing, we will suffer from a 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 effected.
 
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 position. 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 have not entered into any construction contracts, other than site acquisition arrangements and engineering contracts, that might limit our exposure to higher costs in developing and completing any new facilities. 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 as expected at our facilities.
 
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 may not find additional appropriate sites for new facilities and we may not be able to finance, construct, develop or operate these new facilities successfully. We also may be unable to find suitable acquisition candidates. Accordingly, we may fail to implement our planned expansion strategy, including as a result of our failure to successfully manage our growth, and as a result, we may fail to achieve our goals.
 
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The market price of ethanol is volatile and subject to significant fluctuations, which may cause our profitability or losses to fluctuate significantly.
 
The market price of ethanol is dependent upon many factors, including the price of gasoline, which is in turn dependent upon the price of petroleum. Petroleum prices are highly volatile and difficult to forecast due to frequent changes in global politics and the world economy. The distribution of petroleum throughout the world is affected by incidents in unstable political environments, such as Iraq, Iran, Kuwait, Saudi Arabia, the former U.S.S.R. and other countries and regions. The industrialized world depends critically upon oil from these areas, and any disruption or other reduction in oil supply can cause significant fluctuations in the prices of oil and gasoline. We cannot predict the future price of oil or gasoline and may establish unprofitable prices for the sale of ethanol due to significant fluctuations in market prices. For example, our average sales price of ethanol declined by approximately 25% from our 2004 average sales price per gallon in five months from January 2005 through May 2005 and reversed this decline and increased to approximately 55% above our 2004 average sales price per gallon in four months from June 2005 through September 2005; and from September through December 2005, our average sales price of ethanol trended downward, but reversed its trend by rising approximately 36% above our 2005 average price per gallon by the end of 2006. In recent years, the prices of gasoline, petroleum and ethanol have all reached historically unprecedented high levels. If the prices of gasoline and petroleum decline, we believe that the demand for and price of ethanol may be adversely affected. Fluctuations in the market price of ethanol may cause our profitability or losses to fluctuate significantly.
 
We believe that the production of ethanol is expanding rapidly. There are a number of new plants under construction and planned for construction, both inside and outside California. We expect existing ethanol plants to expand by increasing production capacity and actual production. Increases in the demand for ethanol may not be commensurate with increasing supplies of ethanol. Thus, increased production of ethanol may lead to lower ethanol prices. The increased production of ethanol could also have other adverse effects. For example, increased ethanol production could lead to increased supplies of co-products from the production of ethanol, such as WDG. Those increased supplies could lead to lower prices for those co-products. Also, the increased production of ethanol could result in increased demand for corn. This could result in higher prices for corn and cause higher ethanol production costs and, in the event that we are unable to pass increases in the price of corn to our customers, will result in lower profit margins. We cannot predict the future price of ethanol, WDG or corn. Any material decline in the price of ethanol or WDG, or any material increase in the price of corn, will adversely affect our sales and profitability.
 
We rely heavily on our President and Chief Executive Officer, Neil Koehler. The loss of his services could adversely affect our ability to source ethanol from our key suppliers and our ability to sell ethanol to our customers.
 
Our success depends, to a significant extent, upon the continued services of Neil Koehler, who is our President and Chief Executive Officer. For example, Mr. Koehler has developed key personal relationships with our ethanol suppliers and customers. We greatly rely on these relationships in the conduct of our operations and the execution of our business strategies. The loss of Mr. Koehler could, therefore, result in the loss of our favorable relationships with one or more of our ethanol suppliers and customers. In addition, Mr. Koehler has considerable experience in the construction, start-up and operation of ethanol production facilities and in the ethanol marketing business. Although we have entered into an employment agreement with Mr. Koehler, that agreement is of limited duration and is subject to early termination by Mr. Koehler under certain circumstances. In addition, we do not maintain “key person” life insurance covering Mr. Koehler or any other executive officer. The loss of Mr. Koehler could also significantly delay or prevent the achievement of our business objectives.
 
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The raw materials and energy necessary to produce ethanol may be unavailable or may increase in price, adversely affecting our sales and profitability.
 
The principal raw material we use to produce ethanol and its co-products is corn. As a result, changes in the price of corn can significantly affect our business. In general, rising corn prices produce 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 costs to our customers because the price of ethanol is primarily determined by other factors, such as the price of oil and gasoline. At certain levels, corn prices may make ethanol uneconomical to use in markets where the use of fuel oxygenates is not mandated.
 
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 demand and supply. 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. Corn prices as measured by the United States Department of Agriculture, or USDA, reported as prices received, had increased 57% over the previous year by December 2006. The USDA’s December 2006 crop report estimated that corn bought by ethanol plants will represent approximately 17% of the 2006/2007 crop year’s total corn supply, up from 13% in the prior crop year. The increasing ethanol capacity could boost demand for corn and result in the sustainment or further increase in corn prices.
 
The production of ethanol also requires a significant amount of other raw materials and energy, primarily water, electricity and natural gas. Our production facilities require significant and uninterrupted supplies of 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 such resources on acceptable terms. In addition, if there is an interruption in the supply of water or energy for any reason, we may be required to halt ethanol production.
 
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 materially adversely affect 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.
 
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Waivers of the RFS minimum levels of renewable fuels included in gasoline could have a material adverse affect on our results of operations.
 
Under the Energy Policy Act of 2005, the Department of Energy, in consultation with the Secretary of Agriculture and the Secretary of Energy, may waive the RFS mandate with respect to one or more states if the administrator determines that implementing the requirements would severely harm the economy or the environment of a state, a region or the United States, or that there is inadequate supply to meet the requirement. Any waiver of the RFS with respect to one or more states would adversely offset demand for ethanol and could have a material adverse effect on our results of operations and financial condition.
 
While the Energy Policy Act of 2005 imposes the RFS, it does not mandate the use of ethanol and eliminates the oxygenate requirement for reformulated gasoline in the RFG program program included in the Clean Air Act.
 
The RFG program’s oxygenate requirements contained in the Clean Air Act, which, according to the RFA, accounted for approximately 2.0 billion gallons of ethanol use in 2004, was completely eliminated on May 5, 2006 by the Energy Policy Act of 2005. While the RFA expects that ethanol should account for the largest share of renewable fuels produced and consumed under the RFS, the RFS is not limited to ethanol and also includes biodiesel and any other liquid fuel produced from biomass or biogas. The elimination of the oxygenate requirement for reformulated gasoline in the RFG program included in the Clean Air Act may result in a decline in ethanol consumption in favor of other alternative fuels, which in turn could have a material adverse effect on our results of operations and financial condition.
 
Certain countries can export ethanol to the United States duty-free, which may undermine the ethanol production industry in the United States.
 
Imported ethanol is generally subject to a $0.54 per gallon tariff and a 2.5% ad valorem tax that was designed to offset the $0.51 per gallon ethanol subsidy available under the federal excise tax incentive program for refineries that blend ethanol in their fuel. There is a special exemption from the tariff for ethanol imported from 24 countries in Central America and the Caribbean islands which is limited to a total of 7.0% of United States production per year (with additional exemptions for ethanol produced from feedstock in the Caribbean region over the 7.0% limit). In May 2006, bills were introduced in both the United States House of Representatives and United States Senate to repeal the $0.54 per gallon tariff. We do not know the extent to which the volume of imports would increase or the effect on United States prices for ethanol if this proposed legislation is enacted or if the tariff is not renewed beyond its current expiration in December 2007. In addition The North America Free Trade Agreement countries, Canada and Mexico, are exempt from duty. Imports from the exempted countries have increased in recent years and are expected to increase further as a result of new plants under development. The import of ethanol duty-free from a country exempted from the tariff may negatively impact the demand for domestic ethanol and the price at which we sell our ethanol.
 
Our purchase and sale commitments as well as inventory of ethanol held for sale subject us to the risk of fluctuations in the price of ethanol, which may result in lower or even negative gross margins and which could materially and adversely affect our profitability.
 
Our purchases and sales of ethanol are not always matched with sales and purchases of ethanol at prevailing market prices. We commit from time to time to the sale of ethanol to our customers without corresponding and commensurate commitments for the supply of ethanol from our suppliers, which subjects us to the risk of an increase in the price of ethanol. We also commit from time to time to the purchase of ethanol from our suppliers without corresponding and commensurate commitments for the purchase of ethanol by our customers, which subjects us to the risk of a decline in the price of ethanol. In addition, we generally increase inventory levels in anticipation of rising ethanol prices and decrease inventory levels in anticipation of declining ethanol prices. As a result, we are subject to the risk of ethanol prices moving in unanticipated directions, which could result in declining or even negative gross margins. Accordingly, our business is subject to fluctuations in the price of ethanol and these fluctuations may result in lower or even negative gross margins and which could materially and adversely affect our profitability.
 
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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 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. During 2005, sales to our three largest customers, each of whom accounted for 10% or more of total net sales, represented an aggregate of approximately 39%, 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 depend on a small number of suppliers for the majority of the ethanol that we sell. If any of these suppliers is unable or decides not to 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 depend on a small number of suppliers for the majority of the ethanol that we sell. During 2006, our four largest suppliers, each of whom accounted for 10% or more of total purchases, represented approximately 64% of the total ethanol we purchased for resale. During 2005, our three largest suppliers, each of whom accounted for 10% or more of total purchases, represented approximately 59% of the total ethanol we purchased for resale. We expect to continue to depend for the foreseeable future upon a small number of suppliers for a significant majority of the ethanol that we purchase. In addition, we source the ethanol that we sell primarily from suppliers in the Midwestern United States. The delivery of the ethanol that we sell 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 its customers. If this occurs, our sales and profitability and our relationships with our customers will be adversely affected.
 
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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 position.
 
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 position.
 
20

 
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.
 
In addition, some of our suppliers are potential competitors and, especially if the price of ethanol remains at 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 will decline.
 
We also face increasing competition from international suppliers. Although there is a $0.54 per gallon tariff, which is scheduled to expire in December 2007, on foreign-produced ethanol that is approximately equal to the blenders’ credit, ethanol imports equivalent to up to 7% of total domestic production in any given year from various countries were exempted from this tariff under the Caribbean Basin Initiative to spur economic development in Central America and the Caribbean. 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 position.
 
We engage in hedging transactions and other risk mitigation strategies that could harm our results.
 
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 and also 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. 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 is often settled in the same time frame as the physical commodity is either purchased or sold. 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 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 increases in the price of corn or natural gas or decreases in the price of ethanol or unleaded gasoline.
 
21

 
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.
 
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 7, 2007, we had outstanding approximately 40.3 million shares of our common stock. Approximately 10.1 million of these shares were restricted under the Securities Act of 1933, or Securities Act, including approximately 5.4 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 30.2 million shares.
 
We have registered for resale a substantial number of shares of our common stock, including shares of our common stock underlying warrants. The holders of these shares are 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, including shares issued upon the exercise of stock options or warrants, or an 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., our common stockholders may experience numerous negative effects and most of the rights of our common stockholders will be subordinate to the rights of Cascade Investment, L.L.C.
 
As a result of our issuance of shares of Series A Preferred Stock to Cascade Investment, L.L.C., or Cascade, common stockholders may experience numerous negative effects, including substantial dilution. The 5,250,000 shares of Series A Preferred Stock issued to Cascade are immediately convertible into 10,500,000 shares of our common stock, which amount, when issued, would, based upon the number of shares of our common stock outstanding as of March 7, 2007, represent approximately 21% of our shares outstanding and, in the event that we are profitable, would likewise result in a decrease in our diluted earnings per share by approximately 21%, without taking into account cash or stock payable as dividends on the Series A Preferred Stock.
 
22

 
Other negative effects to our common stockholders may include additional dilution from dividends paid in Series A Preferred Stock and certain antidilution adjustments. In addition, rights in favor of holders of our Series A Preferred Stock include: seniority in liquidation and dividend preferences; substantial voting rights; numerous protective provisions; 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, the Series A 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 has approximately 21% of all outstanding voting power as compared to approximately 11% of all outstanding voting power held in aggregate by our current executive officers and directors. Any of the above factors may materially and adversely affect our common stockholders and the values of their investments in our common stock.
 
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.
 
23

 
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 adversely affect our sales and profitability and also the price of our common stock.
 
Item 1B.      Unresolved Staff Comments.
 
None.
 
Item 2.      Properties.
 
Our corporate headquarters, located in Sacramento, California, consists of a 7,000 square foot office leased for approximately 40 months. We also rent, under a four-year lease, an office in Fresno, California, consisting of 3,000 square feet and an office in Davis, California, consisting of 500 square feet. In addition, we rent, under a three-year lease, an office in Portland, Oregon, consisting of 860 square feet. We also rent under a six-month lease, with an option for an additional six month extension, an office in Fresno, California, consisting of 800 square feet.
 
Our completed ethanol production facilities are located in Madera, California, at which a 137 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 are constructing an ethanol production facility in Boardman, Oregon, on a 25 acre plot. We have acquired sites or options with respect to sites for four other potential ethanol production facilities that we may develop, or which are currently under development or construction, including sites at Brawley, California; and another plant in California, the location of which is yet to be announced; and Burley, Idaho. See “Business—Production Facilities” above.
 
Item 3.      Legal Proceedings. 
 
We are subject to legal proceedings, claims and litigation arising in the ordinary course of business. While the amounts claimed may be substantial, the ultimate liability cannot presently be determined because of considerable uncertainties that exist. Therefore, it is possible that the outcome of those legal proceedings, claims and litigation could adversely affect our quarterly or annual operating results or cash flows when resolved in a future period. However, based on facts currently available, management believes such matters will not 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 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.
 
24

 
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 bases 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 (the “Order”), on the grounds that Mr. Spiegel failed to bring his claims as a derivative action. Mr. Spiegel is seeking appellate review of the Order.
 
On February 9, 2007, Mr. Spiegel filed an amended complaint which purports to state the following five counts: (i) breach of fiduciary duty, (ii) fraudulent inducement, (iii) violation of Florida’s Securities and Investor Protection Act, (iv) fraudulent concealment and (v) breach of fiduciary duty of disclosure. The amended complaint includes Pacific Ethanol as a defendant. The breach of fiduciary duty counts are alleged solely against the Individual Defendants and not Pacific Ethanol. We expect to vigorously defend the amended complaint.-
 
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 SEC Rule 14a-9, (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 March 5, 2007 and only recently served the complaint on Pacific Ethanol. We expect to vigorously defend the Federal Court Action.
 
Mercator Group, LLC
 
We filed a Demand for Arbitration against Presidion Solutions, Inc., or Presidion, alleging that Presidion breached the terms of the Memorandum of Understanding, or the MOU, between Accessity and Presidion dated January 17, 2003. We sought a break-up fee of $250,000 pursuant to the terms of the MOU alleging that Presidion breached the MOU by wrongfully terminating the MOU. Additionally, we sought out of pocket costs of its due diligence amounting to approximately $37,000. Presidion filed a counterclaim against us alleging that we had breached the MOU and therefore owe Presidion a break-up fee of $250,000. The dispute was heard by a single arbitrator before the American Arbitration Association in Broward County, Florida in late February 2004. During June 2004, the arbitrator awarded us the $250,000 break-up fee set forth in the MOU between us and Presidion, as well as our share of the costs of the arbitration and interest from the date of the termination by Presidion of the MOU, aggregating approximately $280,000. During the third quarter of 2004, Presidion paid us the full amount of the award with accrued interest. The arbitrator dismissed Presidion’s counterclaim against us.
 
25

 
In 2003, we filed a lawsuit seeking damages in excess of $100 million as a result of information obtained during the course of the arbitration discussed above, against: (i) Presidion Corporation, f/k/a MediaBus Networks, Inc., Presidion’s parent corporation, (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 us and Presidion. In 2004, we dismissed this lawsuit without prejudice, which was filed in Florida state court. In January 2005, we refiled this action in the State of California, for a similar amount, as we believe this to be 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 have been scheduled to commence in July 2007.
 
The final outcome of the Mercator Action will most likely take an indefinite time to resolve. We currently have limited information regarding the financial condition of the defendants and the extent of their insurance coverage. Therefore, it is possible that we may prevail, but may not be able to collect any judgment. 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.
 
Item 4.      Submission of Matters to a Vote of Security Holders.
 
None.

 
26


 
 
 
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, 2005:
   
First Quarter (January 1 - March 31)
$10.25
$5.49
Second Quarter (April 1 - June 30)
12.94
8.58
Third Quarter (July 1 - September 30)
11.20
7.78
Fourth Quarter (October 1 - December 31)
13.48
7.71
     
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 7, 2007, we had 40,285,227 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 7, 2007, the closing sale price of our common stock on the Nasdaq Global Market was $15.28 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, 2006.
 
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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Share Exchange Transaction.”
 
27

 
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, 2001.
 

 
Cumulative Total Return ($)
 
12/01
12/02
12/03
12/04
3/23/05
12/05
12/06
PACIFIC ETHANOL, INC.
100.00
24.60
37.30
94.13
143.65
171.75
244.29
THE NASDAQ STOCK MARKET (U.S.) INDEX
100.00
69.66
99.71
113.79
106.87
114.47
124.20
SIC 2860—INDUSTRIAL ORGANIC CHEMICALS
100.00
84.41
105.89
156.97
154.98
130.92
166.23
 
Dividend Policy
 
We have never paid cash dividends on our common stock and do not currently intend to pay cash dividends on our common stock in the foreseeable future. We currently 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.
 
28

 
Recent Sales of Unregistered Securities
 
From October through December 2006, we issued an aggregate of 28,750 shares of our common stock upon the exercise of outstanding warrants. In connection with the warrant exercises we received aggregate gross proceeds of $2.87.
 
On October 17, 2006, we issued 2,081,888 shares of our common stock and a warrant to purchase 693,963 shares of our common stock as partial consideration for our acquisition of 42% of the membership interests of Front Range.
 
Exemption from the registration provisions of the Securities Act for the transactions described above is claimed under Section 4(2) of the Securities Act, among others, on the basis that such transactions did not involve any public offering and the purchasers were accredited or sophisticated with access to the kind of information registration would provide. In each case, appropriate investment representations were obtained, stock certificates were issued with restricted stock legends, and/or stop transfer orders were placed with our transfer agent.
 
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
 
On October 4, 2006, we granted to certain employees and directors shares of restricted stock under our 2006 Stock Incentive Plan pursuant to Restricted Stock Agreements dated and effective as of October 4, 2006 by and between us and those employees and directors. We granted an aggregate of 945,560 shares of restricted stock to the employees and directors, with an aggregate of 280,720 shares of restricted stock vesting immediately and an aggregate of 148,568 shares of restricted stock vesting on each of the next two anniversaries of the grant date starting on October 4, 2007 and an aggregate of 122,568 shares of restricted stock vesting on each of the subsequent three anniversaries of the grant date starting on October 4, 2009. 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, we withheld an aggregate of 42,157 shares of our common stock and remitted a cash payment to cover the minimum withholding tax amounts, thereby effectively repurchasing from the employees the 42,157 shares of common stock at a deemed purchase price equal to $13.06 per share for an aggregate purchase price of $551,000.

 
29


 
 
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, 2006, 2005 and 2004 and the consolidated balance sheet data at December 31, 2006 and 2005 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.

   
Year Ended December 31,
 
   
2006
 
2005
 
2004
 
2003
 
   
(in thousands, except per share data)
 
Consolidated Statements of Operations Data:
   
 
 
 
 
 
 
Net sales
$
226,356
$
87,599
$
20
$
1,017
 
Cost of goods sold
 
201,527
 
84,444
   
13
   
946
 
Gross profit
   
24,829
   
3,155
   
7
   
71
 
Selling, general and administrative expenses
   
24,641
   
12,638
   
2,277
   
648
 
Income (loss) from operations
   
188
   
(9,483
)
 
(2,270
)
 
(577
)
Other income (expense), net
   
3,426
   
(440
)
 
(532
)
 
(282
)
Non-controlling interest in variable interest entity
   
(3,756
)
 
   
   
 
Loss from operations before income taxes
   
(142
)
 
(9,923
)
 
(2,802
)
 
(859
)
Provision for income taxes
   
   
   
   
 
Net loss
 
$
(142
)
$
(9,923
)
$
(2,802
)
$
(859
)
                           
Preferred stock dividends
 
$
(2,998
)
$
 
$
 
$
 
Deemed dividend on preferred stock
   
(84,000
)
 
   
   
 
Loss available to common stockholders
 
$
(87,140
)
$
(9,923
)
$
(2,802
)
$
(859
)
Loss per common share, basic and diluted
 
$
(2.50
)
$
(0.40
)
$
(0.23
)
$
(0.07
)
Weighted-average shares outstanding, basic and diluted
   
34,855
   
25,066
   
12,397
   
11,733
 
Consolidated Balance Sheet Data:
                         
Cash and cash equivalents
 
$
44,053
 
$
4,521
 
$
 
$
249
 
Working capital (deficit)
   
96,451
   
(2,894
)
 
(1,025
)
 
(358
)
Total assets
   
453,820
   
48,185
   
7,179
   
6,560
 
Long-term debt
   
28,970
   
1,995
   
4,013
   
 
Stockholders’ equity
   
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. In addition, we acquired a minority interest in Front Range on October 17, 2006 and will treat Front Range as a consolidated subsidiary for financial reporting purposes, in accordance with Financial Accounting Standards Board’s (“FASB”) Financial Interpretation No. (“FIN”) 46(R), Consolidation of Variable Interest Entities, as we are considered the primary beneficiary.
 
30

 
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.
 
Any of the factors described 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 become the leading marketer and producer of 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, Washington, Oregon and Colorado. We have extensive customer relationships throughout the Western United States and extensive supplier relationships throughout the Western and Midwestern United States.
 
In October 2006, we completed construction of an ethanol production facility with nameplate annual production capacity of 35 million gallons located in Madera, California, and began producing ethanol. In October 2006, we also acquired approximately 42% of the outstanding membership interests of Front Range Energy, LLC, or Front Range, which owns and operates an ethanol production facility with nameplate annual production capacity of 40 million gallons located in Windsor, Colorado. In addition, we are currently constructing or in advanced stages of development of four additional ethanol production facilities. We also intend to construct or otherwise acquire additional ethanol production facilities as financial resources and business prospects make the construction or acquisition of these facilities advisable. See “Business—Production Facilities” below.
 
31

 
Total annual gasoline consumption in the United States is approximately 140 billion gallons. Total annual ethanol consumption currently represents less than 4% of annual gasoline consumption, or approximately 5.1 billion gallons of ethanol. We believe that the domestic ethanol industry has substantial potential for growth to 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. In California alone, an increase in the consumption of ethanol from California’s current level of 5.7%, or approximately 1.0 billion gallons of ethanol per year, to at least 10% of total annual gasoline consumption would result in consumption of approximately 700 million additional gallons of ethanol, representing an increase in annual ethanol consumption in California alone of approximately 75% and an increase in annual ethanol consumption in the entire United States of approximately 13%.
 
We intend to achieve our goal of becoming the leading marketer and producer of renewable fuels in the Western United States in part by expanding our production capacity to 220 million gallons of annual production capacity by the second quarter of 2008 and 420 million gallons of annual production capacity by the end of 2010. We intend to achieve this goal in part also by expanding our relationships with third-party ethanol producers to market higher volumes of ethanol throughout the Western United States, 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 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 ultimately as a primary transportation fuel. We also intend to expand our distribution infrastructure by expanding 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 $138.8 million, or 158.4% to $226.4 million for the year ended December 31, 2006 from $87.6 million for the year ended December 31, 2005. Our net loss decreased by $9.8 million to $142,000 for 2006 from a net loss of $9.9 million for 2005.
 
The following factors contributed to our operating results for 2006:
 
 
·
Net sales. Our increase in net sales in 2006 as compared to 2005 was primarily due to the following combination of factors:
 
 
o
Higher sales volumes. Total volume of ethanol sold as a principal and an agent increased by 49.4 million gallons, or 94.5%, to 101.7 million gallons for 2006 from 52.3 million gallons 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.
 
 
o
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 $25.9 million in sales for 2006.
 
 
o
Higher ethanol prices. Our average sales price of ethanol increased by $0.61 per gallon, or 36.5%, to $2.28 per gallon for all gallons sold as a principal and an agent for 2006 as compared to $1.67 per gallon for 2005.
 
32

 
 
o
Partial period comparison. Our results of operations for 2006, including our net sales, include our operations and those of all of our wholly-owned subsidiaries, including Kinergy Marketing, LLC, or Kinergy, for that entire period. However, our results of operations for 2005, including our net sales, exclude Kinergy’s net sales for the period from January 1, 2005 through March 22, 2005 in the amount of $23.6 million. See “Share Exchange Transaction” below.
 
 
·
Gross profit. Our gross profit margin increased to 10.9% for 2006 as compared to a gross profit margin of 3.6% for 2005. This increase was primarily due to locking in favorable margins through purchase and sale commitments consistent with our risk management guidelines at various times during 2006. The increase in our gross profit margins was also due to sales resulting from ethanol production, which typically generates higher gross profits than ethanol marketing arrangements, at our Madera facility and also through Front Range.
 
·
Selling, general and administrative expenses. Our selling, general and administrative expenses increased by $12.0 million to $24.6 million in 2006 as compared to $12.6 million in 2005; however, these expenses decreased as a percentage of our net sales due to our substantial growth in net sales. Our selling, general and administrative expenses decreased to 10.9% of net sales in 2006 as compared to 14.4% of net sales in 2005.
 
Sales and Margins
 
Historically, we have generated all of our revenues from marketing ethanol produced by third parties. However, in the fourth quarter of 2006, we began generating revenues from the production and sale of ethanol and its co-products as a result of the commencement of operations at our Madera facility and our interest in Front Range.
 
We have three principal methods of selling ethanol: as a merchant, as a producer and as an agent. See “Critical Accounting Policies—Revenue Recognition” below.
 
When acting as a merchant or as a producer, we generally enter into sales contracts having a typical term of six months 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.
 
Prior to 2005, Kinergy’s gross profit margins for marketing ethanol produced by third parties averaged between 2.0% and 4.4%. Gross profit margins above this historical range generally result when we are able to correctly anticipate and benefit from holding a net long position (i.e., volume on purchase commitments, together with existing inventory, exceeds volume on sales commitments) while ethanol prices are rising, or holding a net short position (i.e., volume on sales commitments exceeds volume on purchase commitments and existing inventory) while ethanol prices are declining. Gross profit margins below this historical range generally result when a net long or short position is held and there is a sustained adverse movement in market prices.
 
33

 
The market price of ethanol has recently experienced significant fluctuations. For example, Kinergy’s average sales price per gallon of ethanol declined by approximately 25% from its 2004 average sales price in the five months from January 2005 through May 2005 and reversed this decline and increased to approximately 55% above Kinergy’s 2004 average sales price in the four months from June 2005 through September 2005; and from September through December 2005, our average sales price per gallon of ethanol trended downward but reversed its trend by rising approximately 36% above our 2005 average sales price by the end of 2006. Fluctuations in the market price of ethanol may cause our results of operations to fluctuate significantly.
 
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.
 
Acquisition of Front Range
 
On October 17, 2006, we entered into a Membership Interest Purchase Agreement with Eagle Energy to acquire Eagle Energy’s 42% interest in Front Range. As consideration for the acquisition of Eagle Energy’s interest in Front Range, we paid to Eagle Energy cash of $30 million, issued 2,081,888 shares of common stock valued at $30 million under the valuation provisions of the agreement and issued a warrant to purchase up to 693,963 shares of common stock at an exercise price of $14.41 per share. The warrant had a fair value of $5.1 million. The warrant expires October 17, 2007.
 
34

 
Share Exchange Transaction
 
On March 23, 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, 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.
 
Critical Accounting Policies
 
Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of net sales and expenses for each period. The following represents a summary of our critical accounting policies, defined as those policies that we believe are the most important to the portrayal of our financial condition and results of operations and that require management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effects of matters that are inherently uncertain.
 
Revenue Recognition
 
We recognize revenue when it is realized or realizable and earned. We consider revenue realized or realizable and earned when 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 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 a producer. Sales as a producer consist of sales of our inventory produced at our facilities, including by Front Range.
 
 
·
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 risk of loss in the transactions does not since all transacted sales prices flow back to our third-party suppliers. 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 receive a predetermined service fee under these transactions and therefore act predominantly in an agency capacity.
 
35

 
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 is 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 is 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 has 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 are therefore required to treat Front Range as a consolidated subsidiary for financial reporting purposes rather than use equity investment accounting treatment. We determined that we had become the primary beneficiary of the variable interest entity as of October 17, 2006, the date we acquired our ownership interest in Front Range. 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. Therefore, we restated the assets, liabilities, and the non-controlling interests of Front Range to fair market values consistent with Statement of Financial Accounting Standards (“SFAS”) No. 141, Business Combinations, and SFAS No. 142, Goodwill & Other Intangible Assets. In accordance with SFAS No. 141, we allocated the purchase price to the tangible and intangible assets and liabilities acquired based upon their estimated fair values. The excess purchase price over the fair value was recorded as goodwill.
 
The following summarizes our estimated fair values of the Front Range tangible and intangible assets and liabilities acquired (in thousands):
 
36


 
Cash and cash equivalents
 
$
742
 
Investments
   
7,058
 
Accounts receivable
   
3,520
 
Inventories
   
3,535
 
Other current assets
   
235
 
Property and equipment
   
92,376
 
Other long-term assets
   
584
 
Intangibles - customer backlog
   
3,900
 
Intangibles - non-compete covenants
   
400
 
Goodwill
   
80,607
 
Current portion of long-term debt
   
(3,395
)
Accounts payable and accrued expenses
   
(4,591
)
Long-term debt
   
(28,753
)
Non-controlling interest in variable interest entity
   
(90,606
)
Net Assets
 
$
65,612
 
 
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 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 Madera and Front Range ethanol production facilities. The long-lived assets attributable to Front Range were recorded as a result of the determination of our status as the primary beneficiary of a variable interest entity and the resulting consolidated accounting treatment.
 
We account for goodwill and intangible assets in accordance with SFAS No. 142. We review goodwill and intangible assets at least annually, or more frequently if impairment indicators arise. In our review, we determine the fair value of these intangibles 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 statement 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, 2006.
 
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, and capital spending decisions of our customers and inflation. We have not recognized any impairment losses on long-lived assets through December 31, 2006.
 
37

 
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 (Revised 2004), 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 in 2006 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 earnings per share had the fair value method been applied to all outstanding and unvested awards in each period are reflected in Note 14 of the 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 14 of the 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. 123R.
 
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 other comprehensive income and later recorded together with the gains and losses to offset related results on the hedged item in the income statement. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
 
The estimated gains/(losses) on our derivatives as of December 31, 2006 and 2005 are as follows (in thousands):

   
2006
 
2005
 
Commodity futures
 
$
646
 
$
 
Commodity options
   
(24
)
 
 
Interest rate options
   
(17
)
 
 
Total
 
$
605
 
$
 
 
38

 
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, 2006, as described in Note 2 of 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 at 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 consider 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 statement of operations.
 
Results of Operations
 
The tables presented below, which compare our results of operations from one period to another, present the results for each period, the change in those results from one period to another in both dollars and percentage change, and the results for each period as a percentage of net sales. The columns present the following:
 
 
·
The first two data columns in the tables show the absolute results for each period presented.
 
·
The columns entitled “Dollar Variance” and “Percentage Variance” show the change in results, both in dollars and percentages. These two columns show favorable changes as a positive and unfavorable changes as negative. For example, when our net sales increase from one period to the next, that change is shown as a positive number in both columns. Conversely, when expenses increase from one period to the next, that change is shown as a negative in both columns.
 
·
The last two columns in the tables show the results for each period as a percentage of net sales.
 
39

 
Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005

 
 
 
Year Ended 
   
Dollar
Variance
   
Percentage
Variance
   
Results as a Percentage
of Net Sales for the
Year Ended 
 
     
December 31, 
   
Favorable
   
Favorable
   
December 31,
 
   
2006 
   
2005 
   
(Unfavorable) 
   
(Unfavorable) 
   
2006 
   
2005 
 
     
(in thousands) 
                   
Net sales
 
$
226,356
 
$
87,599
 
$
138,757
   
158.4
%
 
100.0
%
 
100.0
%
Cost of sales
   
201,527
   
84,444
   
(117,083
)
 
(138.6
)
 
89.0
   
96.4
 
Gross profit
   
24,829
   
3,155
   
21,674
   
687.0
   
10.9
   
3.6
 
Selling, general and administrative expenses
   
24,641
   
12,638
   
(12,003
)
 
(94.9
)
 
10.9
   
14.4
 
Income (loss) from operations
   
188
   
(9,483
)
 
9,671
   
101.9
   
0.1
   
(10.8
)
Other income (expense), net
   
3,426
   
(440
)
 
3,866
   
878.6
   
1.5
   
(0.5
)
Income (loss) before non-controlling interest in variable interest entity
   
3,614
   
(9,923
)
 
13,537
   
136.4
   
1.6
   
(11.3
)
Provision for income taxes
   
   
   
   
   
   
 
Non-controlling 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
)%
 
Preliminary Note. Various factors materially affect the comparability of the information presented in the above table. These factors relate primarily to the Share Exchange Transaction. As a result of the Share Exchange Transaction, our results of operations for 2005 include the operations of Kinergy from only March 23 through December 31, 2005. Kinergy’s net sales for the period from January 1 through March 22, 2005 were approximately $23.6 million and, along with other components of Kinergy’s results of operations, are not included in our results of operations for 2005 in the above table. Our results of operations for 2006 consist of our operations and all of our wholly-owned subsidiaries, including Kinergy, for that entire period.
 
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 as a principal and an agent increased by 49.4 million gallons, or 94.5%, 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 36.5%, to $2.28 per gallon for all gallons sold as a principal and an agent 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 $25.9 million in sales for 2006.
 
Gross Profit. 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.
 
40

 
Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses 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 positions, 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 internal controls and procedures in connection with the Sarbanes-Oxley Act of 2002, a $452,000 increase in travel and entertainment, a $250,000 increase in investor relations expense, a $152,000 increase in supplies and repair and maintenance related to the Madera facility, a $137,000 increase in hardware, software, and other information technology related expenses, a $102,000 increase in taxes, licenses, and fees, an $85,000 increase in trade association dues and memberships, a $46,000 increase in advertising and promotion, and a $1,321,000 decrease in all other selling, general, and administrative expenses.
 
We expect that over the near-term, our selling, general and administrative expenses will increase in terms of actual expenditures as a result of, among other things, increased legal and accounting fees associated with increased corporate governance activities related to the Sarbanes-Oxley Act of 2002, recently adopted rules and regulations of the Securities and Exchange Commission, increased employee costs associated with planned staffing increases, increased sales and marketing expenses, increased activities related to the construction of ethanol production facilities and increased activity in searching for and analyzing potential acquisitions. However, we expect that over the near-term, our selling, general and administrative expenses will decrease as a percentage of net sales due to our expected sales growth.
 
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 attributable to Front Range. 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.
 
Non-Controlling Interest in Variable Interest Entity. Non-controlling interest in variable interest entity was $3,756,000. This amount relates to our consolidated treatment of our variable interest entity, Front Range, and represents the non-controlling interests in the earnings of Front Range.
 
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, be paid 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 2006, we declared cash dividends on shares of our Series A Preferred Stock in the aggregate amount of $2,998,000.
 
Deemed Dividend on Preferred Stock. We have recorded a deemed dividend on preferred stock in our financial statements for the year ended December 31, 2006. This non-cash dividend is to reflect the implied economic value to the preferred stockholder of being able to convert its shares into common stock at a price which is in excess of the fair value of the Series A Preferred Stock. The fair value allocated to the Series A Preferred Stock together with the original conversion terms were used to calculate the value of the deemed dividend on the Series A Preferred Stock of $84 million at the date 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 Series A Preferred Stock. The fair value allocated to the Series A Preferred Stock was in excess of the gross proceeds received of $84 million in connection with the sale of the Series A Preferred Stock; however, the deemed dividend on the Series A Preferred Stock is limited to the gross proceeds received of $84 million. 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.
 
41

 
Year Ended December 31, 2005 Compared to the Year Ended December 31, 2004

     
Year Ended 
   
Dollar
Variance 
   
Percentage
Variance 
   
Results as a Percentage
of Net Sales for the
Year Ended 
 
     
December 31, 
   
Favorable 
   
Favorable 
   
December 31, 
 
     
2005 
   
2004 
   
(Unfavorable)
   
(Unfavorable) 
   
2005 
   
2004 
 
     
(in thousands) 
                   
Net sales
 
$
87,599
 
$
20
 
$
87,579
   
437,895.0
%
 
100.0
%
 
100.0
%
Cost of sales
   
84,444
   
13
   
(84,431
)
 
(649,469.2
)
 
96.4
   
65.0
 
Gross profit
   
3,155
   
7
   
3,148
   
44,971.4
   
3.6
   
35.0
 
Selling, general and administrative expenses
   
10,995
   
2,277
   
(8,718
)
 
(382.8
)
 
12.6
   
11,385.0
 
Feasibility study expensed in connection with acquisition of ReEnergy
   
852
   
   
(852
)
 
(100.0
)
 
1.0
   
 
Acquisition cost expense in excess of cash received
   
481
   
   
(481
)
 
(100.0
)
 
0.5
   
 
Discontinued design of cogeneration facility
   
310
   
   
(310
)
 
(100.0
)
 
0.4
   
 
Loss from operations
   
(9,483
)
 
(2,270
)
 
(7,213
)
 
(317.8
)
 
(10.8
)
 
(11,350.0
)
Total other expense
   
(440
)
 
(532
)
 
92
   
17.3
   
(0.5
)
 
(2,660.0
)
Loss from operations before income taxes
   
(9,923
)
 
(2,802
)
 
(7,121
)
 
(254.1
)
 
(11.3
)
 
(14,010.0
)
Provision for income taxes
   
   
   
   
   
   
 
Net loss
 
$
(9,923
)
$
(2,802
)
$
(7,121
)
 
(254.1
)
 
(11.3
)%
 
(14,010.0
)%
 
Net Sales. Our net sales increased by approximately $87.6 million in 2005 as compared to 2004. This increase was almost entirely due to the acquisition of Kinergy on March 23, 2005. Without the acquisition of Kinergy, our net sales would have been $16,000 in 2005.
 
Gross Profit. Our increase in gross profit was primarily due to the acquisition of Kinergy on March 23, 2005. Prior to 2005, Kinergy’s gross profit margins for marketing ethanol produced by third parties averaged between 2.0% and 4.4%. Gross profit margins above this historical average range have generally resulted after correctly anticipating and benefiting from holding a net long position (i.e., volume on purchase contracts, together with inventory, exceeds volume on sales contracts) while ethanol prices are rising, or holding a net short position (i.e., volume on sales contracts exceeds volume on purchase contracts and inventory) while ethanol prices are declining. Gross profit margins below the historical average range have generally resulted when a net long or short position was held and there was a sustained adverse movement in market prices.
 
42

 
Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses during 2005 as compared to 2004 was primarily due to $2,041,000 in additional legal, accounting and consulting fees, $2,058,000 in abandoned debt financing fees, $802,000 in additional amortization of intangibles and $1,251,000 in additional payroll expense related to the three executive employment agreements that became effective upon the consummation of the Share Exchange Transaction on March 23, 2005, the addition of two staff positions in May and June 2005, an employee promotion in May 2005, the addition of two executive positions in June 2005, the addition of two high-level ethanol plant management positions in September 2005 and the addition of three additional staff positions in the fourth quarter of 2005. Additionally, non-cash compensation and consulting fees increased $651,000 for non-cash compensation from stock grants in connection with the hiring of two employees, $232,000 for a stock grant that vested upon closing of the Share Exchange Transaction on March 23, 2005, $104,000 for non-cash consulting fees related to stock options granted to a consulting firm in connection with the employment of our Chief Financial Officer, $59,000 for non-cash compensation related to stock options granted in connection with the hiring of two ethanol plant managers, $22,000 for non-cash compensation related to stock options granted to reward employees for past performance, $173,000 for non-cash consulting fees related to warrants that were granted in February 2004 and vested over one year, and $823,000 for non-cash consulting fees related to warrants that were granted in connection with the Share Exchange Transaction that vest ratably over two years. The increase in selling, general and administrative expenses was also due to $195,000 in additional insurance expense related primarily to liability and property coverage for our Madera construction site, a $409,000 increase in non-sales commission expense related to insurance proceeds for the casualty loss at the Company’s Madera facility, a $164,000 increase for expenses related to the termination of the proposed acquisition of PBI, a $221,000 increase in business travel expenses, a $82,000 increase in research and development expense, a $168,000 increase in market and filing fees, a $165,000 increase in policy and investor relations expenses, a $72,000 increase in rents, a $48,000 increase in advertising and marketing expense, an $55,000 increase in dues and trade memberships, a $54,000 increase in printing and postage expense, a $25,000 increase in telephone expense, a $7,000 increase in bad debt expense, and the net balance of $45,000 related to various increases in other selling, general and administrative expenses.
 
Other Income (Expense), Net. Other income increased during 2005 as compared to 2004 primarily due to a $345,000 increase in interest income on cash held in seven day investment accounts, $28,000 in management fees and other income, a net decrease of $37,000 in interest expense related to long-term debt, amortization of discount, and construction payables, net of capitalized interest related to our Madera ethanol plant, all of which were partially offset by an increase of $15,000 in bank charges, finance charges, and short-term interest and an increase in liquidated damages and fees paid to stockholders in the amount of $299,000.
 
Liquidity and Capital Resources
 
During 2006, we funded our operations primarily from our cash on hand, net income from the operations, and net proceeds from the issuance and sale of shares of our Series A Preferred Stock and common stock, as well as the exercise of warrants and options to purchase shares of our common stock. As of December 31, 2006, we had working capital of $96,451,000 representing an increase in working capital of $99,345,000 from negative working capital of $2,894,000 as of December 31, 2005. This increase in working capital is primarily due to a private offering of our common stock that we conducted in May 2006 in which we raised $137,619,000 in net proceeds.
 
Our current available capital resources consist primarily of approximately $44,053,000 in cash and cash equivalents as of December 31, 2006. We expect that our future available capital resources will consist primarily of any balance of this cash and cash equivalents as of December 31, 2006, cash generated from operations, if any, unrestricted proceeds from the sale of our Series A Preferred Stock, and any future debt and/or equity financings. We also have $24,851,000 of restricted funds remaining as of December 31, 2006 from the proceeds of the sale of our Series A Preferred Stock. These funds are held in a restricted funds account and are subject to restrictions which, among other things, limit the requisition of funds only for the payment of costs in connection with the construction or acquisition of ethanol production facilities.
 
43

 
Accounts receivable increased $24,374,000 during 2006 from $4,948,000 as of December 31, 2005 to $29,322,000 as of December 31, 2006. This increase is primarily due to a 158.4% increase in our net sales for 2006 over 2005.
 
Inventory balances increased $7,232,000 during 2006, from $363,000 as of December 31, 2005 to $7,595,000 as of December 31, 2006. As of December 31, 2005, there was significant inventory in transit (prepaid inventory) due to logistical delays in delivery to our inventory terminal locations. The increased inventory balance as of December 31, 2006 reflects a return to a more typical balance between inventory in transit and actual inventory on hand.
 
Other current assets increased $2,221,000 during 2006, from $86,000 as of December 31, 2005 to $2,307,000 as of December 31, 2006. The increase is primarily related to a $1,310,000 increase in deferred financing fees.
 
Property and equipment increased $172,948,000 during 2006 from $23,208,000 as of December 31, 2005 to $196,156,000 as of December 31, 2006. This increase is primarily due to our construction activities at our plants under development and our acquisition of our interest in Front Range.
 
Total tangible other assets increased $35,095,000 during 2006 from $62,000 as of December 31, 2005 to $35,157,000 as of December 31, 2006. The increase is primarily due to an increase in restricted cash from the sale of our Series A Preferred Stock, and advances made for equipment, and deferred financing fees related to our April 2006 debt financing.
 
Cash used in our operating activities totaled $8,151,000 for 2006 as compared to $4,007,000 generated in 2005. This $12,158,000 increase in use of cash is primarily due to a $20,939,000 increase in accounts receivable, a $3,697,000 increase in inventory and a $513,000 increase in prepaid expenses and other assets, partially offset by a $4,050,000 increase in accounts payable.
 
Cash used in our investing activities totaled $174,820,000 for 2006 as compared to $17,251,000 for 2005. Included in the results for 2006 is $24,851,000 in restricted cash designated for construction projects and acquisitions, $81,540,000 in cash used for additions to property, plant, and equipment reflecting activities associated with our plants under development and $28,962,000 in purchases of available for sale investments.
 
Cash provided by our financing activities totaled $222,503,000 for 2006 as compared to $17,765,000 for 2005. This significant increase is related to proceeds from our private offerings of Series A Preferred Stock and common stock in April and May 2006, respectively, as well as from the exercise of warrants and stock options. The amount for 2005 includes the proceeds from the sale of our common stock in March 2005.
 
We believe that current and future available capital resources, revenues generated from operations and other existing sources of liquidity, including proceeds from our new debt financing described below, proceeds remaining from our private offerings of Series A Preferred Stock in April 2006 and common stock in May 2006 described below, and distributions, if any, as a result of our ownership interest in Front Range, will be adequate to meet our anticipated working capital and capital expenditure requirements for at least the next twelve months. If, however, our capital requirements or cash flow vary materially from our current projections, if unforeseen circumstances occur or if we require a significant amount of cash to fund future acquisitions, we may require additional financing. Our failure to raise capital, if needed, could restrict our growth or hinder our ability to compete.
 
44

 
New Debt Financing
 
In February 2007, we closed a debt financing transaction, or Debt Financing, in the aggregate amount of up to $325,000,000 through certain of our wholly-owned indirect subsidiaries, or the Borrowers. The primary purpose of the credit facility is to provide debt financing in connection with the development, construction, installation, engineering, procurement, design, testing, start-up, operation and maintenance of five ethanol production facilities.
 
The Debt Financing includes (i) a construction loan facility in an aggregate amount of up to $300,000,000 that matures on the earlier of October 27, 2008 and the date, or Conversion Date, the construction loans made thereunder are converted into term loans, and (ii) a term loan facility in an aggregate amount of up to $300,000,000 that matures on the date that is 84 months after the Conversion Date, and (iii) a working capital and letter of credit facility in an aggregate amount of up to $25,000,000 that matures on the date that is 12 months after the Conversion Date.
 
During the term of the working capital and letter of credit facility, the Borrowers may borrow, repay and re-borrow amounts available under the working capital and letter of credit facility. Loans made under the construction loan or the term loan facility may not be re-borrowed once repaid or prepaid. Loans made under the construction loan facility do not amortize, and are fully due and payable on their maturity date. The term loan facility is intended to refinance the loans made under the construction loan facility. Loans made under the term loan facility amortize at a rate of 6.0% per annum from and after the Conversion Date, and the remaining principal amounts are fully due and payable on their maturity date. Loans made under the working capital and letter of credit facility are fully due and payable on their maturity date.
 
The Borrowers have the option to select floating or periodic fixed-rate loans under the Debt Financing. Depending upon the type of loan and whether the loan is made under the construction loan facility, the term loan facility or the working capital and letter of credit facility, loans under the Debt Financing bear interest at rates ranging from 2.25% to 4.50% over the selected fixed or floating interest rate. Interest on floating rate loans is payable quarterly in arrears, while interest on the various fixed-rate loans available under the credit facility is payable quarterly (or earlier if at the end of selected interest periods ranging from one to six months).
 
Borrowings and the Borrowers’ other obligations under the Debt Financing are secured by a first-priority security interest in all of the equity interests in the Borrowers and substantially all the assets of the Borrowers.
 
Loans and letters of credit under the credit facility are subject to conditions precedent, including, among others, the absence of a material adverse effect; the absence of defaults or events of defaults; the accuracy of certain representations and warranties; the maintenance of a debt to equity ratio which is not in excess of 65:35; title insurance date-downs; payment of fees and expenses; the contribution of all required equity, which is anticipated to be approximately $218.8 million in the aggregate; obtainment of required contracts, permits and insurance; and certain certifications from the independent engineer in respect of construction progress. Loans and letters of credit under the credit facility are also generally not available for the Madera plant or the Boardman plant until its completion. Also, the Borrowers may not be able to fully utilize the credit facility if the completed ethanol plants fail to meet certain minimum performance standards. Finally, disbursements from the construction and term facility are limited to a percentage of project costs of the corresponding plant and in any event are not to exceed approximately $1.15 per gallon of annual production capacity of the plant.
 
45

 
We expect to achieve a senior debt to equity ratio of approximately 55:45 upon commencement of commercial operations of each of the Madera and Boardman ethanol plants. We expect to achieve a senior debt to equity ratio of approximately 35:65 during the construction phase of each of the Burley, and Brawley ethanol plants and another plant in California, the location of which is yet to be announced. Upon commencement of commercial operations of each of these plants, we expect to draw additional funds to increase the senior debt to equity ratio to approximately 55:45.
 
In connection with the Debt Financing, we have also entered into a Sponsor Support Agreement under which we are to provide limited contingent equity support in connection with the development, construction, installation, engineering, procurement, design, testing, start-up and maintenance of five ethanol production facilities. In particular, we have agreed to contribute to the Borrowers up to an aggregate of $42,400,000, or Sponsor Funding Cap, of contingent equity in the event the Borrowers’ have insufficient funds to either pay their project costs (other than debt service under the Debt Financing) as they become due and payable or cause the ethanol production facilities to be completed by the Conversion Date. We have agreed to provide a warranty with respect to all ethanol plants other than our Madera facility. The term of the warranty is one year from the date the ethanol plant achieves commercial operations. Our obligations under the warranty are capped at the Sponsor Funding Cap. Until our contingent equity obligations have been fully performed or the warranty period has expired, we may not incur any secured indebtedness for borrowed money, grant liens on our assets or provide any secured credit enhancements in an aggregate amount in excess of $10,000,000 unless we provide the lenders under the Debt Financing with the same liens or credit support.
 
Acquisition of Front Range
 
In October 2006, we acquired 42% of the outstanding membership interests of Front Range, which owns and operates an ethanol production facility located in Windsor, Colorado. As consideration for the acquisition of the membership interests, we paid $30 million in cash and issued an aggregate of 2,081,888 shares of our common stock and a warrant to purchase an aggregate of up to 693,963 shares of our common stock at an exercise price of $14.41 per share. The warrant is exercisable immediately through and including October 17, 2007.
 
Front Range is subject to certain loan covenants which became effective in the fourth quarter of 2006. Under these covenants, Front Range is required to maintain a certain fixed-charge coverage ratio, a minimum level of working capital, and a minimum level of net worth. The covenants also limit annual distributions made to the owners of Front Range, including Pacific Ethanol, based on Front Range’s leverage ratio.
 
Sale of Common Stock
 
On May 31, 2006, we issued to 45 investors an aggregate of 5,496,583 shares of our common stock at a price of $26.38 per share, for an aggregate purchase price of $145.0 million in cash. Net proceeds from this private offering totaled approximately $138.0 million. We also issued to the investors warrants to purchase an aggregate of 2,748,297 shares of our common stock at an exercise price of $31.55 per share.
 
Sale of Series A Preferred Stock
 
On April 13, 2006, we issued to Cascade 5,250,000 shares of our Series A Preferred Stock at a price of $16.00 per share for an aggregate purchase price of $84.0 million. Of the $84.0 million aggregate purchase price, $4.0 million was paid to us at closing and $80.0 million was deposited into a restricted cash account that is disbursed in accordance with a Deposit Agreement. We used the initial $4.0 million of proceeds for general working capital and must use the remaining $80.0 million for the construction or acquisition of one or more ethanol production facilities in accordance with the terms of the Deposit Agreement.
 
46

 
Terminated Debt Financing
 
On April 13, 2006, we entered into a Construction and Term Loan Agreement with TD BankNorth, N.A. and Comerica Bank for debt financing in the aggregate amount of up to approximately $34.0 million. In December 2006, we paid $1.0 million to amend this agreement to extend the termination date through February 28, 2007. On February 28, 2007, this debt financing was unused and terminated.
 
Effects of Inflation
 
The impact of inflation has not been significant on our financial condition or results of operations or those of our operating subsidiaries.
 
Impact of New Accounting Pronouncements
 
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 cost 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 are currently evaluating the impact of adopting SFAS No. 159 on our financial condition or results of operations.
 
In September 2006, the Securities and Exchange Commission issued SAB No. 108, Topic 1N, Financial Statements—Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements. SAB No. 108 addresses how to quantify the effect of an error on the financial statements and requires a dual approach to compute the materiality of the misstatement. Specifically, the amount of the misstatement is to be computed using both the “rollover” (i.e., the current year income statement perspective) and the “iron curtain” (i.e., the year-end balance sheet perspective). SAB No. 108 is effective for all fiscal years ending after November 15, 2006, and accordingly, we adopted SAB No. 108 in the fourth quarter of fiscal 2006. The adoption of SAB No. 108 did not have a material impact on our financial condition or our results of operations.
 
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. 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 required effective date of SFAS No. 157 is the first quarter of 2008. We are currently evaluating the impact this statement may have on our consolidated financial statements.
 
In September 2006, the FASB issued FASB Staff Position (“FSP”) AUG AIR-1, Accounting for Planned Major Maintenance Activities. The principal source of guidance on the accounting for planned major maintenance activities is the Airline Guide. The Airline Guide permitted four alternative methods of accounting for planned major maintenance activities: direct expense, built-in overhaul, deferral and accrual (accrue-in-advance). FSP AUG AIR-1 amended the Airline Guide by prohibiting the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. The required effective date of FSP AUG-AIR-1 is the first quarter of 2007. We do not anticipate FSP AUG AIR-1 to have a material affect on our consolidated financial statements.
 
47

 
In June 2006, the FASB issued Financial Interpretation No. (“FIN”) 48, Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement No. 109. This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation contains a two-step approach to recognizing and measuring uncertain tax positions accounted for in accordance with SFAS No. 109. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates that it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than fifty percent likely of being realized upon ultimate settlement. The interpretation also provides guidance on derecognition, classification, interest and penalties, and other matters. These provisions are effective for us beginning in the first quarter of 2007. We are assessing the impact of this statement and currently do not believe that the adoption will have a material effect on our consolidated financial statements.
 
In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, which amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and SFAS No. 140, Accounting for the Impairment or Disposal of Long-Lived Assets. Specifically, SFAS No. 155 amends SFAS No. 133 to permit fair value remeasurement for any hybrid financial instrument with an embedded derivative that otherwise would require bifurcation, provided the whole instrument is accounted for on a fair value basis. Additionally, SFAS No. 155 amends SFAS No. 140 to allow a qualifying special purpose entity to hold a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS No. 155 applies to all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006, with early application allowed. We do not expect the adoption of SFAS No. 155 to have a material impact on our results of operations or financial position.
 
Contractual Obligations
 
The following table outlines payments due under our significant contractual obligations (in thousands): 
 
Contractual Obligations
At December 31, 2006
 
 
2007
 
 
2008
 
 
2009
 
 
2010
 
 
2011
 
 
Thereafter
 
 
Total
 
Sourcing commitments(1)
 
$
81,945
 
$
 
$
 
$
 
$
 
$
 
$
81,945
 
Debt principal(2)
   
4,030
   
2,910
   
3,158
   
3,425
   
18,359
   
   
31,882
 
Debt interest(2)
   
2,831
   
2,597
   
2,344
   
2,070
   
1,773
   
   
11,615
 
Water rights - capital lease, including interest(3)
   
160
   
160
   
160
   
160
   
160
   
800
   
1,600
 
Operating leases(4)
   
267
   
203
   
172
   
172
   
110
   
   
924
 
Firm capital commitments(5)
   
78,148
   
17,570
   
   
   
   
   
95,718
 
Preferred dividends(6)
   
4,200
   
4,200
   
4,200
   
4,200
   
4,200
   
4,200
   
25,200
 
 
         
         
   
   
   
 
 
Total commitments
 
$
171,581
 
$
27,640
 
$
10,034
 
$
10,027
 
$
24,602
 
$
5,000
 
$
248,884
 
__________
 
48

(1)
Unconditional purchase commitments for production materials incurred in the normal course of business.
(2)
Under Front Range’s three term loan agreements quarterly payments apply to accrued interest and principal and mature in 2011, but have required principal payments based on a ten year amortization schedule. Interest fluctuates at a premium of 2.75-3.50% based on the 30- or 90-day LIBOR, depending on the loan. At December 31, 2006, the 30-day LIBOR was 5.33% and the 90-day LIBOR was 5.32%.
(3)
The water rights lease obligation of Front Range relates to a lease agreement for water in production processes. The lease requires an initial payment of $400,000 and annual payments of $160,000 per year for the next ten years. The future payments were discounted using a 5.25% interest rate.
(4)
Future minimum payments under non cancellable operating leases.
(5)
Construction commitments for in-progress and contracted ethanol processing facilities.
(6)
Represents dividends on 5,250,000 shares of Series A Preferred Stock.
 
The above table outlines our obligations as of December 31, 2006 and does not reflect the changes in our obligations that occurred after that date.
 
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 Risk - Cash 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 earnings. For the year ended December 31, 2006, losses of ineffectiveness in the amount of $239,000 was 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 to revenue and an effective loss in the amount of $438,000 was recorded in cost of goods sold. There was no ineffectiveness or effectiveness recorded for the year ended December 31, 2005. Amounts remaining in other comprehensive income (loss) will be reclassified to earnings upon the recognition of the related purchase or sale. Other comprehensive gain in the amount of $461,000 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, 2006 and 2005 were $11,588,000 and $0, respectively.
 
49

 
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 on the three-month LIBOR. The rate for a notional balance ranging from $0 to $22,705,473 is 5.50% per annum. The rate for a notional balance ranging from $0 to $9,730,917 is 6.00% 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 earnings. During the year ended December 31, 2006, ineffectiveness in the amount of $24,000 was recorded in interest expense. There was no ineffectiveness recorded in the years ended December 31, 2005 and 2004. Amounts remaining in other comprehensive income will be reclassified to earnings upon the recognition of the hedged interest expense. For the year ending December 31, 2007, we anticipate reclassifying $27,000 to income associated with our cash flow interest rate caps.
 
Front Range, our variable interest entity, entered into an interest rate swap with a notional balance of $17,658,000 to provide a fixed rate of 8.16% on its construction and term loan. This interest rate swap is accounted for as a non-designated derivative in accordance with SFAS No. 133 whereby it is marked to fair value and changes in fair value are recorded to other expense. For the year ended December 31, 2006, an amount of $13,000 was recorded to other expense.
 
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 other comprehensive income.
 
Other Comprehensive Income
 
 
Other comprehensive income relative to derivatives for the year ended December 31, 2006 is as follows (in thousands):
 
   
Commodity Derivatives
 
Interest Rate Derivatives
 
   
Gain/(Loss)*
 
Gain/(Loss)*
 
Beginning balance, January 1, 2006
 
$
 
$
 
Net changes
   
1,307
   
(272
)
Less: Amount reclassified to revenue
   
1,281
   
 
Less: Amount reclassified to cost of goods sold
   
(435
)
 
 
Less: Amount reclassified to other income (expense)
   
   
(7
)
Ending balance, December 31, 2006
 
$
461
 
$
(265
)
—————
*Calculated on a pretax basis
 
The estimated fair values of our derivatives as of December 31, 2006 and 2005 are as follows (in thousands):

   
2006
 
2005
 
Commodity futures
 
$
329
 
$
 
Interest rate options
   
125
   
 
Total
 
$
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 those 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.
 
Item 8.      Financial Statements and Supplementary Data.
 
Reference is made to the financial statements included in this report, which begin at Page F-1.
 
Item 9.      Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
 
None.
 
Item 9A.      Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures
 
We conducted an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Acting Chief Financial Officer, who is also our Chief Operating 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 Acting Chief Financial Officer concluded as of December 31, 2006 that our disclosure controls and procedures were not effective at the reasonable assurance level due to the material weaknesses discussed immediately below.
 
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 in internal control over financial reporting is defined by the Public Company Accounting Oversight Board’s Audit Standard No. 2 as being a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the financial statements would not be prevented or detected. A significant deficiency is a control deficiency, or combination of control deficiencies, that adversely affects the company’s ability to initiate, authorize, record, process, or report external financial data reliably in accordance with generally accepted accounting principles such that there is more than a remote likelihood that a misstatement of the company’s annual or interim financial statements that is more than inconsequential will not be prevented or detected.
 
Management assessed and evaluated the effectiveness of our internal control over financial reporting as of December 31, 2006. Based on the results of management’s assessment and evaluation, our Chief Executive Officer and Acting Chief Financial Officer concluded that while certain of the remediation initiatives undertaken in response to material weaknesses identified and discussed below have been implemented, other remediation initiatives were either not fully implemented by December 31, 2006 or were completed thereafter, but before the filing of this report. Further, the material weakness identified as of December 31, 2005 as “The organization of our accounting department did not provide us with the appropriate resources and adequate technical skills to accurately account for and disclose our activities” continued to exist as of December 31, 2006, but management identified seven more specific material weaknesses relating to our internal control over financial reporting, as follows:
 
 
(1)
We had not effectively implemented comprehensive entity-level internal controls.
 
 
(2)
We did not have a sufficient complement of personnel with appropriate training and experience in generally accepted accounting principals, or GAAP.
 
 
(3)
We did not adequately segregate the duties of different personnel within our accounting group due to an insufficient complement of staff.
 
 
(4)
We did not perform adequate oversight of certain accounting functions and maintained inadequate documentation of management review and approval of accounting transactions and financial reporting processes.
 
 
(5)
We did not have adequate controls governing major account invoice processing and payment.
 
 
(6)
We had not fully implemented certain control activities and capabilities included in the design of our enterprise resource platform, or ERP, system.
 
52

 
 
(7)
We did not have adequate access and data and formulaic integrity controls over critical spreadsheets used in connection with accounting and financial reporting.
 
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 Acting Chief Financial Officer concluded that we did not maintain effective internal control over financial reporting as of December 31, 2006.
 
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, 2006, we did not maintain effective internal control over financial reporting.
 
A nationally-recognized independent consulting firm assisted management with its assessment of the effectiveness of our internal control over financial reporting, including scope determination, planning, staffing, documentation, testing, remediation and retesting and overall program management of the assessment project.
 
Our independent auditors have issued an attestation report on management’s assessment of our internal control over financial reporting. That report appears below under the caption, “Report of Independent Registered Public Accounting Firm.”
 
Inherent Limitations on the Effectiveness of Controls
 
Management does not expect that our disclosure controls and procedures or our internal control over financial reporting will prevent or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control systems are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in a cost-effective control system, no evaluation of internal control over financial reporting can provide absolute assurance that misstatements due to error or fraud will not occur or that all control issues and instances of fraud, if any, have been or will be detected.
 
These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of a simple error or mistake. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is based in part on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Projections of any evaluation of controls effectiveness to future periods are subject to risks. Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures.
 
Material Weaknesses and Related Remediation Initiatives
 
(1) We had not effectively implemented comprehensive entity-level internal controls, as evidenced by the following deficiencies:
 
· We did not maintain documentation evidencing quarterly or other meetings between the Audit Committee, senior financial managers and our General Counsel. Such meetings include reviewing and approving quarterly and annual filings with the Securities and Exchange Commission and reviewing on-going activities to determine if there are any potential audit related issues which may warrant involvement and follow-up action by the Audit Committee. We believe that we have fully implemented processes to create or maintain appropriate documentation. We anticipate that our updated controls will be tested and this deficiency will be remediated by June 30, 2007.
 
53

 
· We did not maintain documentation evidencing discussions comparing actual results to budgeted amounts between executive management and our Board of Directors. We believe that we have fully implemented processes to create or maintain appropriate documentation. We anticipate that our updated controls will be tested and this deficiency will be remediated by June 30, 2007.
 
· We did not obtain prescribed attestations by executive management regarding their compliance with our Codes of Ethics or attestations of employees as to their understanding of and compliance with company policies related to their employment. Our standard operating procedures, or SOPs, are available to all employees through our intranet and our Codes of Ethics are available on our main website. We require all new employees to affirm in writing that they will read and abide by our SOPs. We anticipate that the steps necessary to address this deficiency will be fully implemented by June 30, 2007 and that our updated controls will be tested and this deficiency will be remediated by December 31, 2007.
 
· We did not follow a formal fraud assessment process as prescribed by our SOPs. Our SOPs call for a quarterly fraud assessment as part of our financial closing procedures and an annual fraud assessment as part of the business planning process carried out by our management. We intend to modify our SOPs to assign responsibility for performing the quarterly and annual fraud risk assessments to the Internal Audit Director with review and approval by our Executive Committee. We anticipate that the steps necessary to address this deficiency will be fully implemented by June 30, 2007 and that our updated controls will be tested and this deficiency will be remediated by December 31, 2007.
 
· We did not make available to management timely internal management reports, or to the extent available, we maintained insufficient auditable evidence of management’s review and analysis of those reports. Management has directed that key performance indicators and other financial information be gathered and reported to our Executive Committee on a weekly basis. Management has initiated an effort to provide financial reports from our ERP system and its supporting financial management systems to appropriate members of the operational and financial management teams. This broadened reporting capability will require additional configuration of the appropriate systems and staff training in report writing tools. We expect that the timing of these remediation efforts will be partly dependent on the timing of our hiring of a Chief Financial Officer and a Controller. However, we anticipate that the steps necessary to address this deficiency will be fully implemented by June 30, 2007 and that our updated controls will be tested and this deficiency will be remediated by December 31, 2007.
 
· We did not fully implement or automate through our ERP system our SOP governing delegation of authority, which includes contract and spending limits for all transaction processing functions. Our SOP governing delegation of authority has been reviewed and approved by our management, Executive Committee and General Counsel. We have completed full implementation of an automation of our SOP governing delegation of authority within our ERP system. We anticipate that our updated controls will be tested and this deficiency will be remediated by June 30, 2007.
 
54

 
· We did not fully comply with SOPs prescribing deadlines and control activities related to our period-end closing and financial reporting processes during 2006. We have implemented measures to comply with our SOPs relating to deadlines and control activities related to our period-end closing and financial reporting processes. Our efforts include following detailed closing schedules and checklists and timely obtaining complete review and approval by management of all financial close documentation and results. We anticipate that our updated controls will be tested and this deficiency will be remediated by June 30, 2007.
 
· We had not fully implemented the automated internal control capabilities in our ERP system, including change management and control processes, incident management and backup and recovery processes. We have implemented procedures to more rigorously track changes and document and report incidents as they occur in the areas of change and incident management. We have moved support of our financially material systems and servers to an outsourcer who will perform qualified backup and recovery and provide appropriate attestation that the controls are effective. We anticipate that the steps necessary to address this deficiency will be fully implemented by March 31, 2007 and that our updated controls will be tested and this deficiency will be remediated by June 30, 2007.
 
· We did not conduct annual performance reviews or evaluations of our management and staff employees. We intend to perform appropriate reviews in 2007. We anticipate that our updated procedures will be tested and this deficiency will be remediated by December 31, 2007.
 
(2) We did not have a sufficient complement of personnel with appropriate training and experience in GAAP, as evidenced by the following deficiencies:
 
· Our former Chief Financial Officer functioned in that position through November 20, 2006 and retired on December 15, 2006. Our Audit Committee began transitioning the Chief Financial Officer’s responsibilities to others starting on November 20, 2006 and ultimately delegated overall responsibility for accounting functions and reporting to our Acting Chief Financial Officer. Our Audit Committee also launched a recruitment effort in December 2006, and currently has a number of qualified candidates under evaluation for the Chief Financial Officer position. Most qualified candidates are currently employed by other public companies that are preparing annual reports. Accordingly, we do not expect to complete the hiring of a new Chief Financial Officer until the second quarter of 2007. We anticipate that this deficiency will be remediated by June 30, 2007.
 
· The Controller position is currently open, and the Audit Committee and Executive Management are evaluating candidates. Our Director of Financial Reporting is currently filling the position as acting Controller, and a former Controller is reporting to him as acting Assistant Controller. We expect to fill the Controller position within 60 days from the filing of this report and anticipate that this deficiency will be remediated by June 30, 2007.
 
· We believe that during 2006, and through December 31, 2006, the organization and supervision of our accounting department were inappropriate to the scale of our activities. Under the direction of our Acting Chief Financial Officer and Audit Committee, we have undertaken extensive training and reorganization of the accounting staff and allocated significant additional resources to the accounting department, including retaining additional contractors and consultants. We anticipate that the steps necessary to address this deficiency will be fully implemented and that this deficiency will be remediated by June 30, 2007.
 
55

 
· As a result of too few accounting staff members, a variety of tasks were not completed on a timely basis. We continue to seek to hire qualified permanent staff members and we have engaged contract staff members. We have added personnel to our accounts payable and accounts receivable functions, our ethanol sales order process and our commodity management and financial close and reporting processes. We have added additional accounting staff members at our Madera County, California plant site and we plan to hire additional accounting staff members at all new plant sites as they come on-line. In addition, our financial closings are performed in accordance with a scheduled checklist and according to our financial controls. We anticipate that the steps necessary to address this deficiency will be fully implemented and that our updated controls will be tested and this deficiency will be remediated by June 30, 2007.
 
(3) We did not adequately segregate the duties of different personnel within our accounting group due to an insufficient complement of staff and inadequate management oversight. Activities that were not adequately segregated included (a) processing of payments and making modifications to payments prior to issuance, and (b) payroll calculation and payroll processing. We are addressing these segregation issues through revised desk procedures and management and staff training. We anticipate that our updated controls will be tested and this deficiency will be remediated by June 30, 2007.
 
(4) We did not perform adequate oversight of certain accounting functions and maintained inadequate documentation of management review and approval of accounting transactions and financial reporting processes. Our SOPs call for management oversight in a wide variety of transactions and activities to help ensure: (a) accurate entry of inputs into our ERP system that are used to automatically calculate amounts that are reported in our financial statements, (b) preparation and distribution of financial information and reports to operational management for review and approval, and (c) reconciliation of share-based payments. In addition, our SOPs call for documentation of management oversight of a wide variety of transactions and activities, including: (i) customer invoicing and adjustments to customer invoices, (ii) period-end closing processes, (iii) vendor invoices and payment processing, (iv) hedge effectiveness assessments and mark-to-market calculations, (v) payroll processing, and (vi) review of supporting documentation, including resolution of material issues, related to statements and reports filed with the Securities and Exchange Commission. Documentation is now created and maintained as part of management’s routine review and approval process. We are also implementing appropriate management oversight and approval activities in other areas. We anticipate that the steps necessary to address this deficiency will be fully implemented and that our updated controls will be tested and this deficiency will be remediated by June 30, 2007.
 
(5) We did not have adequate controls governing major account invoice processing and payment. Our SOPs provide for a number of procedures to be followed before cash can be remitted to suppliers. These procedures were occasionally bypassed in order to accelerate the payment by wire transfer of amounts owed to major suppliers. We have addressed this deficiency by implementing revised procedures that: (a) provide for all transactions to be processed through the ERP system, (b) assure that the prescribed purchase order, receiving, invoice processing and payment approval processes are followed before payment is remitted to a supplier, (c) restrict access to the recommended payment list within our ERP system, and (d) reconcile all wire transfers as part of the daily bank account reconciliation process. We anticipate that our updated controls will be tested and this deficiency will be remediated by June 30, 2007.
 
(6) We had not fully implemented certain control activities and capabilities included in the design of our ERP system. Certain features of our ERP system are designed to automate accounting procedures and transaction processing, or to enforce controls, including features that enforce proper authorization of credit memos. We believe that we have fully implemented these features. We anticipate that our updated controls will be tested and this deficiency will be remediated by June 30, 2007.
 
56

 
(7) We did not have adequate access and data and formulaic integrity controls over critical spreadsheets used in connection with accounting and financial reporting. Our SOPs call for access and data and formulaic integrity controls over critical spreadsheets used in connection with accounting and financial reporting. We have moved all spreadsheets that are used in our financial management and closing processes to a secured, shared server with access granted to a limited number of management-approved personnel. We have also begun to set passwords at the spreadsheet level to further limit access to critical information. We continue to review and plan for formal processes to ensure qualified review and approval of financial calculations and modifications to those calculations. We expect to revise our SOPs to enhance our internal controls in these regards. We expect that the timing of these remediation efforts will be partly dependent on the timing of our hiring of a Chief Financial Officer and a Controller. However, we anticipate that the steps necessary to address this deficiency will be fully implemented by June 30, 2007 and that our updated controls will be tested and this deficiency will be remediated by December 31, 2007.
 
The above material weaknesses did not result in adjustments to our 2006 consolidated financial statements, however, it is reasonably possible that, if not remediated, one or more of the material weaknesses could result in a material misstatement in our reported financial statements that might result in a material misstatement in a future annual or interim period.
 
Changes in Internal Control over Financial Reporting
 
The changes noted above, are the only changes during our most recently completed fiscal quarter that have materially affected or are reasonably likely to materially affect, our internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act.
 
57

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors
Pacific Ethanol, Inc.
Sacramento, California
 
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Pacific Ethanol, Inc.’s (the “Company”) internal control over financial reporting was not effective as of December 31, 2006, because of the effect of material weaknesses described therein, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). The Company’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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company’s 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 the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
58

 
A material weakness is a significant control deficiency, or combination of significant control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weaknesses have been identified and included in management’s assessment as of December 31, 2006:
 
 
(1)
The Company had not effectively implemented comprehensive entity-level internal controls;
 
 
(2)
The Company did not have a sufficient complement of personnel with appropriate training and experience in generally accepted accounting principles, or GAAP;
 
 
(3)
The Company did not adequately segregate the duties of different personnel within its accounting group due to an insufficient complement of staff;
 
 
(4)
The Company did not perform adequate oversight of certain accounting functions and maintained inadequate documentation of management review and approval of accounting transactions and financial reporting processes;
 
 
(5)
The Company did not have adequate controls governing major account invoice processing and payment;
 
 
(6)
The Company did not fully implement certain control activities and capabilities included in the design of its enterprise resource platform, or ERP system; and
 
 
(7)
The Company did not maintain adequate access and data and formulaic integrity controls over critical spreadsheets used in connection with accounting and financial reporting.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of Pacific Ethanol, Inc. and our report dated March 7, 2007 expressed an unqualified opinion.
 
In our opinion, management’s assessment that the Company did not maintain effective internal control over financial reporting as of December 31, 2006 is fairly stated, in all material respects, based on the COSO framework. Also, in our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2006, based on the COSO framework.
 
We do not express an opinion or any other form of assurance on management’s statements referring to new controls being implemented after December 31, 2006.
 
/s/ HEIN & ASSOCIATES LLP
 
Irvine, California
March 7, 2007
 
Item 9B.      Other Information.
 
None.

 
59


 
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) and (a)(2) Financial Statements and Financial Statement Schedules
 
None.
 
(a)(3) Exhibits
 
Reference is made to the exhibits listed on the Index to Exhibits.


 
60

 

 
Index to Financial Statements
 
 

Report of Independent Registered Public Accounting Firm
F-2
   
Consolidated Balance Sheets as of December 31, 2006 and 2005
F-3
   
Consolidated Statements of Operations for the Years Ended December 31, 2006, 2005 and 2004
F-5
   
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2006, 2005 and 2004
F-6
   
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2006, 2005 and 2004
F-7
   
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004
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, 2006 and 2005 the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for the three year period ended December 31, 2006. 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, 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, 2006 and 2005, and the results of its operations and its cash flows for three year period ended December 31, 2006, 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), the effectiveness of Pacific Ethanol, Inc.’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 7, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.
 
As discussed in Note 11 to the consolidated financial statements, the Company adopted the provisions of SEC Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, which resulted in a change in the manner in which the Company assesses the impact of financial statement errors.
 
/s/ HEIN & ASSOCIATES LLP
 
Irvine, California
March 7, 2007



 
F-2



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

   
December 31,
 
ASSETS
 
2006
 
2005
 
           
Current Assets:
             
Cash and cash equivalents
 
$
44,053
 
$
4,521
 
Investments in marketable securities
   
39,119
   
2,750
 
Accounts receivable, net (including $1,188 and $938 as
of December 31, 2006 and 2005,
respectively, from a related party)
   
29,322
   
4,948
 
Restricted cash
   
1,567
   
 
Notes receivable - related party
   
   
136
 
Inventories
   
7,595
   
363
 
Prepaid expenses
   
1,053
   
627
 
Prepaid inventory
   
2,029
   
1,349
 
Other current assets
   
2,307
   
86
 
Total current assets
   
127,045
   
14,780
 
 
Property and Equipment, Net
   
196,156
   
23,208
 
 
Other Assets:
             
Restricted cash
   
24,851
   
 
Deposits and advances
   
9,040
   
14
 
Goodwill
   
85,307
   
2,566
 
Intangible assets, net
   
10,155
   
7,569
 
Other assets
   
1,266
   
48
 
Total other assets
   
130,619
   
10,197
 
 
Total Assets
 
$
453,820
 
$
48,185
 

The accompanying notes are an integral part of these consolidated financial statements.
 
F-3

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

   
December 31,
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
2006
 
2005
 
 
Current Liabilities:
             
Current portion - related party note payable
 
$
 
$
1,200
 
Current portion - notes payable
   
4,125
   
 
Accounts payable - trade
   
11,483
   
4,755
 
Accounts payable - related party
   
3,884
   
6,412
 
Accrued retention - related party
   
5,538
   
1,450
 
Accrued payroll