Form 10QSB

ASSETS	September 30, 2006		December 31, 2005
	(unaudited)		*
Current Assets:
Cash and cash equivalents	$	100,737,815	$	4,521,111
Restricted cash		1,784,432		—
Investments in marketable securities		—		2,750,000
Accounts receivable (including $2,021,197 and $937,713 as of September 30, 2006 and December 31, 2005, respectively, from related parties)		15,541,096		4,947,538
Notes receivable - related party		—		135,995
Inventories		5,727,301		362,972
Prepaid expenses		162,828		626,575
Prepaid inventory		1,386,814		1,349,427
Derivative instruments		280,826		—
Other current assets		1,555,688		86,054
Total current assets		127,176,800		14,779,672
Property and Equipment, net		80,666,204		23,208,248

Restricted funds for plant construction and acquisitions		60,689,417		—
Goodwill		2,565,750		2,565,750
Intangible assets, net		7,039,397		7,568,723
Other assets		10,088,085		62,419
Total Assets	$	288,225,653	$	48,184,812

LIABILITIES AND STOCKHOLDERS’ EQUITY	September 30, 2006			December 31, 2005
	(unaudited)			*
Current Liabilities:
Current portion - related party note payable	$	—		$	1,200,000
Accounts payable - trade		10,154,230			4,755,235
Accounts payable - related party		7,626,056			6,411,618
Accrued retention - related party		4,548,003			1,450,500
Accrued payroll		429,020			433,887
Other accrued liabilities		3,418,168			3,422,565
Total current liabilities		26,175,477			17,673,805
Related-Party Notes Payable, Net of Current Portion		—			1,995,576

Total Liabilities		26,175,477			19,669,381
Commitments and Contingencies (Note 7)
Stockholders’ Equity:
Preferred stock, $0.001 par value; 10,000,000 shares authorized: Series A Cumulative Redeemable Convertible Preferred Stock, 5,250,000 and 0 shares issued and outstanding and aggregate liquidation preference of $85,050,000 and $0 as of September 30, 2006 and December 31, 2005, respectively		5,250			—
Common stock, $0.001 par value; 100,000,000 shares authorized, 37,262,986 and 28,874,442 shares issued and outstanding as of September 30, 2006 and December 31, 2005, respectively		37,263			28,874
Additional paid-in capital		358,499,248			42,071,522
Accumulated other comprehensive income		79,767			—
Due from stockholders		—			(600	)
Accumulated deficit		(96,571,352	)		(13,584,365	)
Total stockholders’ equity		262,050,176			28,515,431
Total Liabilities and Stockholders’ Equity	$	288,225,653		$	48,184,812

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Net sales (including $3,400,718, $11,985,467, $2,165,315 and $4,017,322 for the three and nine months ended September 30, 2006 and 2005, respectively, to a related party)	$	61,102,145		$	26,414,305		$	145,802,389		$	51,530,735
Cost of goods sold		53,653,782			24,778,592			132,721,159			49,695,870
Gross profit		7,448,363			1,635,713			13,081,230			1,834,865
Operating expenses:
Selling, general and administrative expenses		5,547,900			2,613,316			13,290,980			5,749,620
Services rendered in connection with feasibility study		—			—			—			852,250
Income (loss) from operations		1,900,463			(977,603	)		(209,750	)		(4,767,005	)
Other income (expense), net		1,854,221			55,019			3,170,297			(39,340	)
Income (loss) before provision for income taxes		3,754,684			(922,584	)		2,960,547			(4,806,345	)
Provision for income taxes		—			—			—			—
Net income (loss)	$	3,754,684		$	(922,584	)	$	2,960,547		$	(4,806,345	)
Preferred stock dividends	$	(1,050,000	)	$	—		$	(1,947,534	)	$	—
Deemed dividend on preferred stock		—			—			(84,000,000	)		—
Income (loss) available to common stockholders	$	2,704,684		$	(922,584	)	$	(82,986,987	)	$	(4,806,345	)
Basic weighted average shares outstanding (See Note 2)		37,228,096			28,614,819			33,387,801			23,841,380
Basic and diluted income (loss) per common share	$	0.07		$	(0.03	)	$	(2.49	)	$	(0.20	)

		Nine Months Ended September 30,
		2006			2005

Operating Activities:
Net income (loss)	$	2,960,547		$	(4,806,345	)
Adjustments to reconcile net income (loss) to cash used in operating activities:
Depreciation and amortization		710,680			488,861
Amortization of debt issuance costs		199,824			15,000
Amortization of debt discount		404,424			180,403
Non-cash compensation expense		834,637			951,706
Non-cash consulting expense		1,491,271			798,261
Non-cash services rendered in connection with feasibility study		—			702,250
Non-cash gain on derivatives		322,911			—
Bad debt expense		102,557			—
Changes in operating assets and liabilities:
Accounts receivable		(10,696,114	)		101,525
Note receivable, related party		135,995			—
Inventories		(5,364,330	)		(52,126	)
Prepaid expenses and other assets		(10,041,118	)		(1,181,768	)
Prepaid inventory		(37,387	)		(286,074	)
Increase in restricted cash		(1,784,432	)		—
Increase in derivative assets		(517,000	)		—
Accounts payable and accrued expenses		4,285,441			405,279
Accounts payable and accrued retention, related party		4,311,941			953,740
Net cash used in operating activities		(12,680,153	)		(1,729,288	)
Investing Activities:
Additions to property, plant and equipment		(57,639,310	)		(7,146,598	)
Payment on deposit		—			(4,086	)
Payment on option to acquire site		—			(10,000	)
Proceeds from sale of marketable securities		2,750,000			—
Increase in restricted cash designated for construction projects and acquisitions		(60,642,097	)		—
Net cash acquired in acquisition of Kinergy, ReEnergy and Accessity		—			1,146,854
Costs associated with share exchange transaction		—			(307,808	)
Net cash used in investing activities		(115,531,407	)		(6,321,638	)
Financing Activities:
Proceeds from sale of common stock, net		137,622,041			18,879,749
Proceeds from sale of preferred stock, net		82,566,734			—
Proceeds from exercise of warrants and stock options		9,926,683			447,669
Payments on borrowings, related party		(3,600,000	)		—
Receipt of subscription receivable		600			67,500
Preferred share dividend paid		(897,534	)		—
Cash paid for debt issuance costs		(1,190,260	)		—
Net cash provided by financing activities		224,428,264			19,394,918
Net increase (decrease) in cash and cash equivalents		96,216,704			11,343,992
Cash and cash equivalents at beginning of period		4,521,111			42
Cash and cash equivalents at end of period	$	100,737,815		$	11,344,034

PACIFIC ETHANOL, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

(UNAUDITED)

		Nine Months Ended September 30,
		2006		2005
Supplemental Information:
Cash paid for interest	$	185,671	$	249,018
Cash paid for taxes	$	13,167	$	5,600
Non-Cash Financing and Investing activities:
Change in fair value of derivative instruments	$	32,447	$	—
Deemed dividend on preferred stock	$	84,000,000	$	—
Preferred stock dividend declared	$	1,050,000	$	—
Unrealized gain on restricted available-for-sale securities	$	47,320	$	—
Conversion of debt to equity	$	—	$	1,245,000
Purchase of ReEnergy with stock	$	—	$	316,250
Shares contributed by stockholder in purchase of ReEnergy	$	—	$	506,000
Shares contributed by stockholder in purchase of Kinergy	$	—	$	1,012,000
Stock returned as payment for stock option exercise	$	—	$	1,213,314
Purchase of Kinergy with stock	$	—	$	9,803,750

On March 23, 2005, Pacific Ethanol, Inc., a Delaware corporation, (the “Company”) completed a share exchange transaction (“Share Exchange Transaction”), with the shareholders of Pacific Ethanol California, Inc. (“PEI California”) and the holders of the membership interests of each of Kinergy Marketing, LLC (“Kinergy”) and ReEnergy, LLC (“ReEnergy”), pursuant to which the Company 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, the Company’s predecessor, Accessity Corp., a New York corporation (“Accessity”), reincorporated in the State of Delaware under the name “Pacific Ethanol, Inc.” In connection with the reincorporation, the shareholders of Accessity became stockholders of the Company and the Company succeeded to the rights, properties, and assets and assumed the liabilities of Accessity.

The Share Exchange Transaction has been accounted for as a reverse acquisition whereby PEI California is deemed to be the accounting acquiror. The Company has consolidated the results of PEI California, Kinergy, and ReEnergy beginning March 23, 2005, the date of the Share Exchange Transaction. Accordingly, the Company’s results of operations for the three months ended September 30, 2005 consist of the operations of PEI California, Kinergy and ReEnergy for that entire period; and the Company’s results of operations for the nine months ended September 30, 2005 consist of the operations of PEI California for that entire period and the operations of Kinergy and ReEnergy from March 23, 2005 through September 30, 2005.

Basis of Presentation - The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States and reflect all adjustments, consisting solely of normal recurring adjustments, needed to fairly present the financial results for these interim periods. These financial statements include some amounts that are based on the Company’s best estimates and judgments. These estimates may be adjusted as more information becomes available, and any adjustment could be significant. The impact of any change in estimates is included in the determination of earnings in the period in which the change in estimate is identified. The results of the operations for the three and nine months ended September 30, 2006 are not necessarily indicative of the results that may be expected for the entire year.

The Company has omitted footnote disclosures that would substantially duplicate the disclosures contained in the audited financial statements for the Company. The accompanying unaudited interim consolidated financial statements should be read in conjunction with the financial statements for the years ended December 31, 2005 and 2004 and notes thereto in the Company’s annual report on Form 10-KSB for the year ended December 31, 2005, filed with the Securities and Exchange Commission on April 14, 2006.

Concentrations of Credit Risk - Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed completely to perform as contracted. Concentrations of credit risk (whether on- or off-balance sheet) that arise from financial instruments exist for groups of customers or counterparties when they have similar economic characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions described below.

Financial instruments that subject the Company to credit risk consist of cash balances maintained in excess of federal depository insurance limits and accounts receivable, which have no collateral or security. The accounts maintained by the Company at financial institutions are insured by the Federal Deposit Insurance Corporation (FDIC) up to $100,000. At September 30, 2006, the uninsured balance was $158,929,334 and at December 31, 2005 the uninsured balance was $4,048,476. The uninsured balance at September 30, 2006 included $153,499,085 of United States Government issued marketable securities, including treasuries and agencies. The Company has not experienced any losses in the Company’s bank accounts and the Company believes that it is not exposed to any significant risk of loss on cash.

Restricted funds for plant construction and acquisitions - The long-term restricted funds balance at September 30, 2006 of $60,689,417 is the remaining balance of the $80 million in cash received in connection with the issuance of 5,250,000 shares of the Company’s Series A Cumulative Redeemable Convertible Preferred Stock (the “Series A Preferred Stock”), which will be dispersed to the Company in accordance with the terms of a deposit agreement (the “Deposit Agreement”) between the Company and Comerica Bank. Under the Deposit Agreement, the Company may, with certain prescribed limitations, requisition funds from the restricted cash account for the payment of construction costs in connection with the construction of ethanol production facilities. Of the $80 million deposited into the restricted cash account, $22 million has been advanced to the Company for use in the construction of its Madera County, California ethanol production facility. The restricted funds balance consisted of the following:

Derivative Instruments and Hedging Activities - In 2006, the Company implemented a policy to minimize its exposure to commodity price risk associated with certain anticipated commodity purchases and sales and interest rate risk associated with anticipated corporate borrowings by using derivative instruments. The Company accounts for its derivative transactions in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. Derivative transactions, which can include forward contracts and futures positions on the New York Mercantile Exchange (“NYMEX”) and interest rate caps are recorded on the balance sheet as assets and liabilities based on the derivative’s fair value. Changes in the fair value of the derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If derivatives meet those criteria, effective gains and losses are deferred in other comprehensive income and later recorded together with the hedged item in earnings. For derivatives designated as a hedge, the Company formally documents the hedge and assess the effectiveness with associated transactions. The Company has designated and documented contracts for the physical delivery of commodity products to and from counterparties as normal purchases and normal sales.

Impairment of Long-Lived Assets - The Company evaluates impairment of long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Asset. The Company assesses the impairment of long-lived assets, including property and equipment and purchased intangibles subject to amortization, whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The asset impairment review assesses the fair value of the assets based on the future cash flows the assets are expected to generate. An impairment loss is recognized when estimated undiscounted future cash flows expected to result from the use of the asset plus net proceeds expected from the disposition of the asset (if any) are less than the related asset’s carrying amount. Impairment losses are measured as the amount by which the carrying amounts of the assets exceed their fair values. Estimates of future cash flows are judgments based on management’s experience and knowledge of the Company’s operations and the industries in which the Company operates. These estimates can be significantly affected by future changes in market conditions, the economic environment, and capital spending decisions of the Company’s customers and inflation.

Goodwill - Goodwill represents the excess of cost of an acquired entity over the net of the amounts assigned to net assets acquired and liabilities assumed. The Company accounts for goodwill in accordance with SFAS No. 142, Goodwill and Other Intangible Assets, which requires an annual review for impairment or more frequently if impairment indicators arise. This review would include the determination of the associated reporting unit’s fair value using market multiples and discounted cash flow modeling. The Company has adopted SFAS No. 142 guidelines for annual review of impairment of goodwill and performed its annual review of impairment in March 2006. The Company has not recognized any impairment losses through September 30, 2006.

Stock-Based Compensation - In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (Revised 2004), Share-Based Payments (“SFAS No. 123R”). SFAS No. 123R requires a public entity to measure the cost of employee services received in exchange for the award of equity instruments based on the fair value of the award at the date of grant. The expense is to be recognized over the period during which an employee is required to provide services in exchange for the award. SFAS No. 123R is effective as of the beginning of the first interim or annual reporting period that begins after December 15, 2005 and accordingly the Company adopted this standard on January 1, 2006.

SFAS No. 123R provides for two transition methods. The “modified prospective” method requires that share-based compensation expense be recorded for any employee options granted after the adoption date and for the unvested portion of any employee options outstanding as of the adoption date. The “modified retrospective” method requires that, beginning in the first quarter of 2006, all prior periods presented be restated to reflect the impact of share-based compensation expense consistent with the proforma disclosures previously required under SFAS No. 123. The Company has elected to use the “modified prospective” in adopting this standard.

Prior to January 1, 2006, the Company had adopted SFAS No. 123, Accounting for Stock-Based Compensation. As provided for by SFAS No. 123, the Company had elected to continue to account for its stock-based compensation programs according to the provisions of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees. Accordingly, compensation expense had been recognized to the extent of employee or director services rendered based on the intrinsic value of stock options granted under the plan. The Company accounts for common stock, stock options, and warrants granted to non-employees based on the fair market value of the instrument, using the Black-Scholes option pricing model based on assumptions for expected stock price volatility, term of the option, risk-free interest rate and expected dividend yield at the grant date.

	Three Months Ended September 30, 2005			Nine Months Ended September 30, 2005
Net loss available to common stockholders, as reported	$	(922,584	)	$	(4,806,345	)
Add: Stock-based employee expense included in reported net loss		68,456			951,706
Less: Affect if fair value method had applied to all awards		(507,825	)		(1,391,075	)
Pro-forma net loss available to common stockholders	$	(1,361,953	)	$	(5,245,714	)
Basic and diluted loss per common share, as reported	$	(0.03	)	$	(0.20	)
Pro-forma basic and diluted loss per common share	$	(0.05	)	$	(0.22	)

The estimated fair value of employee options granted was determined in accordance with SFAS No. 123R on the date of grant using the Black-Scholes option valuation model with the following weighted-average assumptions. As no options were granted during the nine months ended September 30, 2006, the following assumptions remain the same: risk free interest rate of 3.9% to 4.5%; dividend yield 0%; volatility 53.6% to 55.0% and expected life of 5.5 to 10 years. The risk-free interest rate assumption is based upon observed interest rates appropriate for the expected term of the stock options. The expected volatility is based on the historical volatility of the common stock of an appropriate proxy company. The Company has not paid any dividends on its common stock since its inception and does not anticipate paying dividends on its common stock in the foreseeable future. The computation of the expected option term is based on expectations regarding future exercises of options which generally vest over 5.5 to 10 years.

The weighted average remaining term of all options outstanding decreased from 9.61 years at December 31, 2005 to 8.86 years at September 30, 2006. At September 30, 2006 the Company had 665,000 stock options outstanding under its 2004 Stock Option Plan, and 66,000 stock options outstanding under its Amended 1995 Incentive Stock Plan. On September 7, 2006, the Company terminated its Amended 1995 Stock Incentive Plan and 2004 Stock Option Plan, except to the extent of currently issued and outstanding options under the plan. The Company’s 2006 Stock Incentive Plan was approved at the Company’s annual meeting of stockholders on September 7, 2006. An aggregate of 2,000,000 shares of the Company’s common stock are available for issuance under the 2006 Stock Incentive Plan. At September 30, 2006, no awards had been made under the 2006 Stock Incentive Plan.

Revenue Recognition - The Company derives revenue primarily from sales of ethanol. The Company’s net sales are based upon written agreements or purchase orders that identify the amount of ethanol to be purchased and the purchase price. Shipments are made to customers, either, directly from suppliers or from the Company’s inventory to its customers by truck or rail. Ethanol that is shipped by rail originates primarily in the Midwest and takes from 10 to 14 days from date of shipment to be delivered to a customer or to various terminals in the Western United States. For local deliveries, the product is shipped by truck and delivered the same day as shipment.

In accordance with SAB No. 104, Revenue Recognition and the related Emerging Issues Task Force (“EITF”) Issue No. 99-19, Reporting Revenue Gross as a Principal Versus Net as an Agent, revenues on the sale of ethanol that are shipped from the Company’s stock of inventory are recognized when the ethanol has been delivered to a customer, provided that appropriate signed documentation of the arrangement, such as a signed contract, purchase order or letter of agreement, has been received, the fee is fixed or determinable and collectibility is reasonably assured.

In addition, the Company has entered into certain contracts under which the supplier is responsible for fulfillment of the customer order, the supplier has approval of pricing terms, credit risk is shared between the Company and the supplier and the Company does not have discretion in the selection of the supplier. Under these contracts, the Company pays the supplier the gross payments received by the Company from third parties for sales of ethanol less certain transaction costs and a fixed fee. In accordance with EITF Issue No. 99-19, revenues under these contracts are recorded net as the Company is deemed to be an agent. In the three and nine months ending September 30, 2006, $806,317 and $1,107,635, of service revenue was recorded, respectively. In the three and nine months ending September 30, 2005, an immaterial amount service revenue was recorded.

Income (Loss) Per Common Share - The Company computes income (loss) per common share in accordance with the provisions of SFAS No. 128, Earnings Per Share. SFAS No. 128 requires companies with complex capital structures to present basic and diluted earnings per share. Basic earnings (loss) per share are computed on the basis of the weighted average number of shares of common stock outstanding during the period. Preferred dividends are deducted from net income and have been considered in the calculation of income (loss) available to common stockholders in computing basic earnings (loss) per share. In periods in which there is a loss available to common shareholders, diluted earnings per share is equal to basic earnings per share. For the three months ended September 30, 2006, $2,704,684 in income was available to common shareholders. Following is the calculation of diluted earnings per share for the three months ended September 30, 2006:

Warrants to purchase 2,748,297 shares of common stock at $31.00 per share were outstanding during the three months ended September 30, 2006, but were not included in the computation of diluted earnings per share as the exercise price of the warrants was greater than the average market price of the common shares. The Series A Preferred Shares are eligible for conversion into common shares which would result in 10,500,000 shares of common stock , but were not included in the computation of diluted earning per share as they are anti-dilutive due to the adjustment for preferred share dividends.

Allowance for Doubtful Accounts. The Company primarily sells ethanol to gasoline refining and distribution companies, it also sells wet distillers grain to dairy operators and animal feed distributors. The Company had significant concentrations of credit risk as of September 30, 2006, as described in Note 2 of the Company’s consolidated financial statements. However, those customers historically have had good credit ratings and the Company has historically collected amounts that were billed to those customers. Receivables from customers are generally unsecured. The Company continuously monitors its customer account balances and actively pursues collections on past due balances.

The Company maintains an allowance for doubtful accounts for balances that appear to have specific collection issues. The 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, the Company has been unsuccessful in the collection efforts, then a bad debt allowance is recorded for the balance at question. The balance would eventually be written-off when the Company has determined that collection is not likely. The factors considered in reaching this determination are the apparent financial condition of the customer, and the Company’s 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. The Company’s start-up activities consist primarily of costs associated with new or potential sites for ethanol production facilities. All the costs associated with a potential site are expensed, 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 the consolidated statement 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. The Company is currently evaluating the impact this statement may have on its 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. The Company does not anticipate FSP AUG AIR-1 to have a material affect on its consolidated financial statements.

In June 2006, the FASB issued FASB Interpretation Number 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109. 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 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. These provisions are effective for the Company beginning in the first quarter of 2007. The Company is currently evaluating the impact this statement may have on its consolidated financial statements.

As of September 30, 2006 and December 31, 2005, the Company had accounts payable due to W.M. Lyles Co. (a subsidiary of Lyles Diversified, Inc., a former stockholder of the Company) of $7,626,056 and $6,411,618, respectively, related to the construction in progress of an ethanol plant. As of September 30, 2006 and December 31, 2005, the Company had accrued retention due to W.M. Lyles Co. of $4,548,003 and $1,450,500, respectively, related to the construction in progress of an ethanol plant. Included in construction in progress at September 30, 2006 and December 31, 2005 is capitalized interest of $1,029,258 and $343,793, respectively.

The Company’s Boardman, Oregon ethanol production facility is currently estimated to have a construction cost and a total project cost of approximately $69.4 million and $86.1 million, respectively. In addition to construction, the total project cost includes budgeted amounts for inventory, financing fees, working capital and a contingency reserve. Of the $69.4 million estimated construction cost, approximately $45.1 million has been committed under various engineering, construction, and equipment purchase agreements as of September 30, 2006.

Preferred Stock - The Company has 10,000,000 shares of preferred stock authorized, of which 7,000,000 have been designated as Series A Preferred Stock. As of September 30, 2006, 5,250,000 shares of Series A Preferred Stock were issued and outstanding. The holders of the Series A Preferred Stock have conversion rights initially equivalent to two shares of common stock for each share of Series A Preferred Stock. The Series A Preferred Stock ranks senior in liquidation and dividend preferences to the Company’s common stock. Holders of 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. The holders of Series A Preferred Stock have a liquidation preference over the holders of the Company’s common stock, equivalent to the purchase price per share of the Series A Preferred Stock plus any accrued and unpaid dividends on the Series A Preferred Stock.

In accordance with EITF 98-5, Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios, and EITF 00-27, Application of Issue No. 98-5 to Certain Convertible Instruments, the Series A Preferred Stock is considered to have an embedded beneficial conversion feature because the conversion price was less than the fair value of the Company’s common stock at the issuance date. The Company has recorded a deemed dividend on preferred stock in the second quarter of 2006 in an amount of $84 million. 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 the Company’s 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. This amount has been charged to accumulated deficit with the offsetting credit to additional paid-in-capital. The Company has treated the deemed dividend on preferred stock as a reconciling item on the Consolidated Statements of Operations to adjust its reported net loss, together with any preferred stock dividends recorded during the applicable period, to “loss available to common stockholders.”

The Series A Preferred Stock has a redemption feature, which under the provisions of SFAS No. 133, is likely a derivative instrument that requires bifurcation from the host contract. SFAS No. 133 requires all derivative instruments to be measured at fair value. However, because the underlying events that would cause the redemption feature to be exercisable (i.e., redemption events) are not probable of occurrence in the foreseeable future, the Company believes that the fair value of the embedded derivative was de minimis at the date of issuance of the Series A Preferred Stock through September 30, 2006. The Company will continue to evaluate the redemption feature and the probability of the occurrence of the redemption events at each reporting period to determine if a fair value should be ascribed to such embedded derivative and recorded in the Company’s financial statements.

Ethanol Purchase and Marketing Agreements - The Company entered into ethanol purchase and marketing contracts with two owners of ethanol production facilities, in which the Company is required to purchase or market all of the ethanol produced from the respective ethanol facilities. Under these agreements, the Company is obligated to purchase the ethanol at a negotiated price or the Company receives a pre-negotiated margin of the sales price. The effective term for each of the agreements runs through April 2008 and June 2013, respectively, with automatic renewals for additional one-year periods.

Litigation - General - The Company is 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 the Company’s 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 the Company’s financial position, results of operations or cash flows.

Litigation - Barry Spiegel - On December 23, 2005, Barry J. Spiegel, a stockholder of the Company and former director of Accessity, filed a complaint in the Circuit Court of the 17^th Judicial District in and for Broward County, Florida (Case No. 05018512) (the “Spiegel Action”), against Barry Siegel, Philip Kart, Kenneth Friedman and Bruce Udell (collectively, the “Defendants”). Messrs. Siegel, Udell and Friedman are former directors of Accessity and the Company. Mr. Kart is a former executive officer of Accessity and the Company. The Spiegel Action relates to the Share Exchange Transaction and purports to state five counts against the Defendants: (i) breach of fiduciary duty, (ii) violation of Florida’s Deceptive and Unfair Trade Practices Act, (iii) conspiracy to defraud, (iv) fraud, and (v) violation of Florida Securities and Investor Protection Act. Mr. Spiegel is seeking $22.0 million in damages. On March 8, 2006, Defendants filed a motion to dismiss the Spiegel Action, which remains pending. No discovery has been taken. The Company has agreed with Messrs. Friedman, Siegel, Kart and Udell to advance the costs of defense in connection with the Spiegel Action. Under applicable provisions of Delaware law, the Company may be responsible to indemnify each of the Defendants in connection with the Spiegel Action.

Litigation - Gerald Zutler - In January 2003, DriverShield CRM Corp., or DriverShield, then a wholly-owned subsidiary of the Company’s predecessor, Accessity, was served with a complaint filed by Mr. Gerald Zutler, its former President and Chief Operating Officer, alleging, among other things, that DriverShield breached its employment contract with Mr. Zutler, that there was fraudulent concealment of DriverShield’s intention to terminate its employment agreement with Mr. Zutler, and discrimination on the basis of age and aiding and abetting violation of the New York State Human Rights Law. The complaint was filed in the Supreme Court of the State of New York, County of Nassau, Index No.: 654/03. Mr. Zutler sought damages of approximately $2.2 million, plus punitive damages and reasonable attorneys’ fees. On July 20, 2006, the Company settled Mr. Zutler’s claims in full and subsequently made a settlement payment to Mr. Zutler in the amount of $515,000, of which $150,000 was covered by DriverShield’s insurance carrier.

Litigation - Mercator - In 2003, Accessity filed a lawsuit seeking damages in excess of $100 million 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 tortuously interfering in a transaction between Accessity and Presidion Solutions Inc. In 2004, Accessity dismissed this lawsuit without prejudice, which was filed in Florida state court. The Company recently refiled this action in the State of California, for a similar amount, as the Company believes that this is 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, the Company 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 March 2007. 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 the Company 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 the Company will retain the remaining one-third of the net proceeds from any Mercator Action recovery.

The business and activities of the Company expose it to a variety of market risks, including risks related to changes in commodity prices and interest rates. The Company monitors and manages these financial exposures as an integral part of its 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. The Company accounts for its use of derivatives related to its hedging activities pursuant to SFAS No. 133, in which the Company recognizes all of its derivative instruments in its statement of financial position as either assets or liabilities, depending on the rights or obligations under the contracts. The Company has 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 earnings. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

Commodity Risk - Cash Flow Hedges - As part of its risk management strategy, the Company uses derivative instruments to protect cash flows from fluctuations caused by volatility in commodity prices out up to fifteen months. These hedging activities are conducted to protect product margin to reduce the potentially adverse effects that market volatility could have on operating results by minimizing the Company’s 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 NYMEX price of gasoline or the Chicago Board of Trade price of ethanol. In addition, the Company hedges anticipated sales of ethanol to minimize its 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 the Company’s 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 three and nine months ended September 30, 2006, $753,486 and $771,044 of ineffectiveness was recorded in cost of goods sold. For the three and nine months ending September 30, 2006, $1,080,384 and $892,140 was recorded in other income, respectively. There was no ineffectiveness or effectiveness recorded in the nine months ended September 30, 2005. Amounts remaining in other comprehensive income will be reclassified to earnings upon the recognition of the related purchase or sale. The notional balance of these derivatives as of September 30, 2006 and 2005 were $32,560,500 and $0, respectively.

Interest Rate Risk - As part of the Company’s interest rate risk management strategy, the Company uses derivative instruments to minimize significant unanticipated earnings fluctuations that may arise from rising variable interest rate cost associated with existing and anticipated borrowings. To meet these objectives the Company purchased interest rate caps on the three-month LIBOR. The capitalization rate for a notional balance ranging from $0 to $22,705,473 is 5.50% per annum. The capitalization 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 caps 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 three and nine months ended September 30, 2006 and 2005, ineffectiveness in the amount of $38,299 was recorded in interest expense. Amounts remaining in other comprehensive income will be reclassified to earnings upon the recognition of the hedged interest expense.

Related Customer - On January 14, 2006, the Company entered into a 6-month sales contract with Southern Counties Oil Co., an entity owned by a director of the Company. The contract period is from April 1, 2006 through September 30, 2006 for 2,100,000 gallons of fuel grade ethanol to be delivered ratably at approximately 350,000 gallons per month at varying prices based on delivery destinations in California. On June 13, 2006, the Company entered into an additional 6-month sales contract with a contract period from October 1, 2006 through March 31, 2007 for 6,300,000 gallons of fuel grade ethanol to be delivered ratably at approximately 1,050,000 gallons per month at varying prices based on delivery destinations in California, Nevada, and Arizona. During the nine months ended September 30, 2006, sales to Southern Counties Oil Co. totaled $11,985,467 and accounts receivable from Southern Counties Oil Co. at September 30, 2006 totaled $2,021,197.

Grant of Restricted Stock - On October 4, 2006, the Company granted shares of restricted stock under the Company’s 2006 Stock Incentive Plan to employees and certain non-employee directors. The Company granted an aggregate of 836,360 shares to employees, of which, 246,920 vested immediately and an aggregate of 117,888 shares vest on each of the next five anniversaries of the grant date starting on October 4, 2007. As a condition to subsequent vesting of the shares, an employee must remain continuously employed by the Company on a full time basis from the grant date through each subsequent vesting date. Resulting from the grant of restricted stock to employees, the Company expects additional non-cash expense of approximately $3.2 million in the fourth quarter of 2006, and additional non-cash expense of approximately $384,000 each quarter thereafter during the vesting period.

The Company granted an aggregate of 109,200 shares to non-employee directors, of which, 33,800 vested immediately and an aggregate of 26,000 shares vest on each of the next two anniversaries of the grant date starting on October 4, 2007, and for one non-employee director, 4,680 shares vest on each of the next five anniversaries of the grant date starting on October 4, 2007. As a condition to subsequent vesting of the shares of restricted stock, a non-employee director must remain continuously in the service of the Company as a member of its Board of Directors from the grant date through each subsequent vesting date. Resulting from the grant of restricted stock to non-employee directors, the Company expects additional non-cash expense of approximately $441,000 in the fourth quarter of 2006, additional non-cash expense of approximately $100,000 each quarter during the two subsequent vesting years, and additional non-cash expense of approximately $15,000 each quarter thereafter during the remaining vesting period for one non-employee director.

Purchase of 42% Interest in Front Range Energy, LLC - On October 17, 2006, the Company acquired approximately 42% of the outstanding membership interests of Front Range Energy, LLC, which owns and operates an ethanol production facility located in Windsor, Colorado. As consideration for the acquisition of the membership interests, the Company paid $30 million in cash and issued an aggregate of 2,081,888 shares of the Company’s common stock and a warrant to purchase an aggregate of up to 693,963 shares of the Company’s common stock at an exercise price of $14.41 per share. The warrant is exercisable on October 17, 2006 through and including October 17, 2007. The warrant contains both cash and cashless exercise provisions.

Amendment to the Construction and Term Loan Agreement - On October 2, 2006, the Company entered into an Amendment to its Construction and Term Loan Agreement with TD BankNorth, N.A. and Comerica Bank. Under the Amendment, the Company may terminate the debt financing and its related agreements by December 15, 2006. If the Company’s terminates the debt financing, it will be obligated to pay a termination fee of $1.0 million to the lenders. If the Company does not terminate the loan but fails to draw down on the full $34.0 million by December 15, 2006, the Company may be obligated to pay a fee in the amount of up to $1.0 million to the lenders, calculated in proportion to the balance of the $34.0 million that the Company has not utilized.

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 strategies. The forward-looking statements and associated risks may include, relate to or be qualified by other important factors, including, without limitation:

We are currently engaged in the business of marketing and producing ethanol and its co-products in the Western United States. We provide transportation, storage and delivery of ethanol through third-party service providers and sell ethanol and its co-products 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 County, California. We believe that this facility is capable of operating at an annual production rate of approximately 40 million gallons. This facility has completed start-up and is currently producing ethanol and its co-products. We are also constructing an ethanol production facility with nameplate annual production capacity of 35 million gallons located in Boardman, Oregon. We believe that this facility will also be capable of operating at an annual production rate of approximately 40 million gallons. We expect to complete this facility by the second quarter of 2007. In October 2006, we acquired approximately 42% of the outstanding membership interests of Front Range Energy, LLC, which owns and operates an ethanol production facility with nameplate annual production capacity of 40 million gallons located in Windsor, Colorado. We believe that the facility is capable of operating at an annual production rate of approximately 48 million gallons, subject to modification of applicable permits. In addition, we are currently in advanced stages of development of three additional ethanol facilities in two Western states. We expect that construction of each of these facilities will begin by the end of the first quarter of 2007. 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.

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 5 billion gallons of ethanol. We believe that the 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 950 million 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 18%.

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 California and other Western states. We also 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 marketing industry and understand the business of marketing ethanol. In addition, we believe that our focus on developing and acquiring ethanol production facilities in locations that enable us to exploit production cost advantages over competing ethanol production facilities provides us with significant competitive advantages. 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 net sales increased by $34.7 million, or 131%, to $61.1 million in the third quarter of 2006 from $26.4 million in the third quarter of 2005. Our net income increased by $4.7 million to $3.8 million in the third quarter of 2006 from a net loss of $900,000 in the third quarter of 2005. Our net sales increased by $94.3 million, or 183% to $145.8 million in the first nine months of 2006 from $51.5 million in the first nine months of 2005. Our net income increased by $7.8 million to $3.0 million in the first nine months of 2006 from a net loss of $4.8 million in the first nine months of 2005. We commenced producing ethanol and its co-products in the fourth quarter of 2006. Accordingly, our net sales for all periods presented include only net sales associated with our ethanol marketing operations.

Higher ethanol prices. Our average sales price of ethanol increased by $0.81 per gallon, or 49%, to $2.45 per gallon for all gallons sold as a principal and an agent for the third quarter of 2006 as compared to $1.64 per gallon for the third quarter of 2005. Our average sales price of ethanol increased by $0.69 per gallon, or 44%, to $2.27 per gallon for all gallons sold as a principal and an agent for the first nine months of 2006 as compared to $1.58 per gallon for the first nine months of 2005.

Gross profit. Our gross profit margin increased to 12.2% in the third quarter of 2006 as compared to a gross profit margin of 6.2% in the third quarter of 2005. Our gross profit margin increased to 9.0% in the first nine months of 2006 as compared to a gross profit margin of 3.6% in the first nine months of 2005. These increases were primarily due to locking in favorable margins by way of purchase and sale commitments consistent with our risk management guidelines at various times during the periods.

Selling, general and administrative expenses. Our selling, general and administrative expenses increased by approximately $2.9 million to approximately $5.5 million in the third quarter of 2006 as compared to approximately $2.6 million in the third quarter of 2005 and increased by approximately $7.6 million to approximately $13.3 million in the first nine months of 2006 as compared to approximately $5.7 million in the first nine months of 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 9.1% of net sales in the third quarter of 2006 as compared to 9.9% of net sales in the third quarter of 2005 and decreased to 9.1% of net sales in the first nine months of 2006 as compared to 11.2% of net sales in the first nine months of 2005.

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 wet distillers grain, or WDG, the primary co-product of our ethanol production. 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.

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.

For both direct and inventory sales, we typically conduct back-to-back sales in which we match ethanol purchase and sale contracts of like quantities and delivery periods. Back-to-back direct sales typically involve no price risks that otherwise may result from fluctuations in the market price of ethanol. However, timing differences do exist and consequently, back-to-back inventory sales may lag by up to two or more weeks. This time lag results from inventory transit and turnover times. As a result, we may supply ethanol under new inventory sales contracts from existing inventory. These back-to-back inventory sales therefore involve some price risks resulting from potential fluctuations in the market price of ethanol.

Management seeks to optimize transitions to new inventory sales contracts and reduce the effects of declining ethanol prices by managing inventory as carefully as possible to decrease inventory levels in anticipation of declining ethanol prices and to increase inventory levels in anticipation of rising ethanol prices. Because we decrease inventory levels in anticipation of declining ethanol prices and increase inventory levels in anticipation of rising ethanol prices, we are subject to the risk of ethanol prices moving in unanticipated directions, which could result in declining or even negative gross profit margins over certain periods of time, but also enables us to potentially benefit from above-normal gross profit margins.

Prior to 2005, Kinergy’s gross profit margins for marketing ethanol produced by third parties have averaged between 2.0% and 4.4%. Gross profit margins above this historical average range generally result when we are able to correctly anticipate and benefit 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 generally result when a net long or short position is held and there is a sustained adverse movement in market prices.

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 in the first nine months of 2006 by rising approximately 38% above our 2005 average sales price. 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 will be adversely affected. Fluctuations in the market price of ethanol may cause our results of operations to fluctuate significantly.

We believe that our future gross profit margins will primarily depend on the confluence of five key factors: (i) the degree of competition in the ethanol market, which may reduce margins; (ii) the proportion of direct sale arrangements, which typically result in lower gross profit margins, to our inventory sales, which typically result in higher gross profit margins; (iii) the volatility of the market price of ethanol and WDG; (iv) with respect to our ethanol production operations, the volatility of the market price of key input commodities, including corn and natural gas; and (v) management’s ability to anticipate trends in the market price of ethanol, WDG and key input commodities and our ability to implement appropriate risk management strategies and hold appropriate net long or net short ethanol inventory positions. Given the difficulty associated with forecasting any of these factors, we are unable to estimate our future gross profit margins.

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.

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.

We derive revenue primarily from sales of ethanol. Our net sales are based upon written agreements or purchase orders that identify the amount of ethanol to be purchased and the purchase price. Shipments are made to customers, either, directly from suppliers or from our inventory to our customers by truck or rail. Ethanol that is shipped by rail originates primarily in the Midwest and takes from 10 to 14 days from date of shipment to be delivered to the customer or to one of four terminals in California and Oregon. For local deliveries the product is shipped by truck and delivered the same day as shipment.

Emerging Issues Task Force (“EITF”) Issue No. 99-19, Reporting Revenue Gross as a Principal Versus Net as an Agent, addresses whether a company should record in revenue the total amount billed to customers (as a principal) or only record the amount that is retained by the company (as an agent). For example, as a principal, the total sales price would be included as revenue and the amount owed to the supplier would be recorded in cost of goods sold. As an agent, in the same scenario, excluding the amounts for freight, the gross margin would be included in revenue and nothing would be recorded in cost of goods sold. Several indicators are listed within EITF No. 99-19 that are evaluated in unison to determine whether revenue should be recorded as a principal or as an agent. In accordance with EITF Issue No. 99-19, we record revenue as a principle when we directly sell ethanol purchased from a third-party ethanol supplier, when we are responsible for fulfillment of the customer order, have latitude in pricing, incur credit risk on the receivable and have discretion in the selection of the supplier.

We account for goodwill and intangible assets in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets. 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 Kinergy using market multiples and discounted cash flow modeling and compare it to the net book value of the acquired assets. We performed our annual review of impairment and we have not recognized any impairment losses on any of our intangible assets through September 30, 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 our review of events, or changes in circumstances suggest the fair value of assets could be less then their net book value. In such event, we would 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 September 30, 2006.

During the first quarter of 2006, effective as of the beginning of the year, we adopted the fair value method of accounting for employee stock compensation cost pursuant to SFAS No. 123 (Revised 2004), Share-Based Payments (“SFAS No. 123R”). 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 2 of the financial statements.

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.

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 September 30, 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.

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.

		Three Months Ended						Dollar Variance		Percentage Variance		Results as a Percentage of Net Sales for the Three Months Ended
		September 30,						Favorable		Favorable		September 30,
		2006			2005			(Unfavorable)		(Unfavorable)		2006		2005
Net sales	$	61,102,145		$	26,414,305		$	34,687,840		131.3	%	100.0	%	100.0	%
Cost of sales		53,653,782			24,778,592			(28,875,190	)	(116.5	)	87.8		93.8
Gross profit		7,448,363			1,635,713			5,812,650		355.4		12.2		6.2
Selling, general and administrative expenses		5,547,900			2,613,316			(2,934,584	)	(112.3	)	9.1		9.9
Income (loss) from operations		1,900,463			(977,603	)		2,878,066		294.4		3.1		3.7
Other income, net		1,854,221			55,019			1,799,202		3,270.1		3.0		0.2
Income (loss) from operations before income taxes		3,754,684			(922,584	)		4,677,268		507.0		6.1		3.5
Provision for income taxes		—			—			—		—		—		—
Net income (loss)	$	3,754,684		$	(922,584	)	$	4,677,268		507.0	%	6.1	%	3.5	%
Preferred stock dividends		(1,050,000	)		—			(1,050,000	)	—		1.7		—
Income (loss) available to common stockholders	$	2,704,684		$	(922,584	)	$	3,627,268		393.2	%	4.4	%	3.5	%

Net Sales. Our net sales increased by approximately $34.7 million in the first nine months of 2006 as compared to the same period in 2005. This increase was predominantly due to increased sales volume and increased average sales prices. During the three months ended September 30, 2006, sales volume increased by 6.9 million gallons, or 43%, to 23.1 million gallons as compared to 16.2 million gallons for the three months ended September 30, 2005. For the three months ended September 30, 2006, our average sales price of ethanol increased by $0.81 per gallon, or 49%, to $2.45 per gallon for all gallons sold as a principal and an agent as compared to $1.64 per gallon for the three months ended September 30, 2005.

Gross Profit. The increase in gross profit, both in dollars and as a percentage of net sales, in the third quarter of 2006 as compared to the same period in 2005 is generally reflective of more advantageous buying and selling during a period of rapidly increasing market prices. We established and maintained net long ethanol positions during much of the third quarter 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.

Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses during the three months ended September 30, 2006 as compared to the three months ended September 30, 2005 was primarily due to an increase of $641,726 in additional non-cash director and consulting expenses, a $500,085 increase in legal, accounting and consulting fees, a $293,548 increase in insurance expense primarily related to increased directors and officers insurance costs, a $338,802 increase in costs related to internal controls and procedures in connection with the Sarbanes-Oxley Act of 2002, a $215,151 increase in payroll and benefits due to hiring of additional staff positions, a $442,883 increase in general office and administrative expenses, a $101,081 increase in investor relations expense, a $75,597 increase in non-cash compensation expense, a $120,167 increase in hardware, software, and other information technology related expenses, a $73,478 increase in travel and entertainment, a $68,655 increase in supplies and repair and maintenance related to the Madera facility, a $62,892 increase in depreciation and amortization, a $48,489 increase in trade association dues and memberships, a $12,015 decrease in advertising and promotion, a $32,701 decrease in taxes, licenses, and fees, and a $3,254 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 in response 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.

Preferred Stock Dividends. Shares of our 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. On September 30, 2006, we declared a cash dividend on shares of our Series A Preferred Stock in the amount of $1,050,000.

		Nine Months Ended						Dollar Variance		Percentage Variance		Results as a Percentage of Net Sales for the Nine Months Ended
		September 30,						Favorable		Favorable		September 30,
		2006			2005			(Unfavorable)		(Unfavorable)		2006		2005

Net sales	$	145,802,389		$	51,530,735		$	94,271,654		182.9	%	100.0	%	100.0	%
Cost of sales		132,721,159			49,695,870			(83,025,289	)	(167.1	)	91.0		96.4
Gross profit		13,081,230			1,834,865			11,246,365		612.9		9.0		3.6
Selling, general and administrative expenses		13,290,980			5,749,620			(7,541,360	)	(131.2	)	9.1		11.2
Feasibility study expensed in connection with acquisition of ReEnergy		—			852,250			852,250		100.0		—		1.7
Income (loss) from operations		(209,750	)		(4,767,005	)		4,557,255		95.6		0.1		9.3
Other income (expense), net		3,170,297			(39,340	)		3,209,637		8,158.7		2.2		0.1
Income (loss) from operations before income taxes		2,960,547			(4,806,345	)		7,766,892		161.6		2.0		9.3
Provision for income taxes		—			—			—		—		—		—
Net income (loss)	$	2,960,547		$	(4,806,345	)	$	7,766,892		161.6	%	2.0	%	9.3	%
Preferred stock dividends		(1,947,534	)		—			(1,947,534	)	(100.0	)	1.3		—
Deemed dividend on preferred stock		(84,000,000	)		—			(84,000,000	)	(100.0	)	57.6		—
Loss available to common stockholders	$	(82,986,987	)	$	(4,806,345	)	$	(78,180,642	)	(1,626.6	)%	56.9	%	9.3	%

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 the nine months ended September 30, 2005 include the operations of Kinergy from only March 23 through September 30, 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 the nine months ended September 30, 2005 in the above table. Our results of operations for the nine months ended September 30, 2006 consist of our operations and all of our wholly-owned subsidiaries, including Kinergy, for that entire period.

Net Sales. Our net sales increased by approximately $94.3 million in the first nine months of 2006 as compared to the same period in 2005. Of this amount, approximately $23.6 million is attributable to the exclusion of Kinergy’s net sales for the period from January 1 through March 22, 2005 from our results of operations for the nine months ended September 30, 2005. The balance of the increase in our net sales during the first nine months of 2006 as compared to the same period in 2005 was predominantly due to increased sales volume and increased average sales prices. During the nine months ended September 30, 2006, sales volume increased by 13.9 million gallons, or 29%, to 61.5 million gallons as compared to 47.6 million gallons for the nine months ended September 30, 2005. For the nine months ended September 30, 2006, our average sales price of ethanol increased by $0.69 per gallon, or 44%, to $2.27 per gallon for all gallons sold as a principal and an agent as compared to $1.58 per gallon for the nine months ended September 30, 2005.

Gross Profit. The increase in gross profit, both in dollars and as a percentage of net sales, in the first nine months of 2006 as compared to the same period in 2005 is generally reflective of more advantageous buying and selling during a period of rapidly increasing market prices. We established and maintained net long ethanol positions during much of the first nine months 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 MTBE blending which we believed would result in a significant increase in demand for blending ethanol with gasoline. The increase in gross profit in the first nine months of 2006 as compared to the same period in 2005 was also due to the exclusion of Kinergy’s gross profit for the period from January 1 through March 22, 2005 from our results of operations for the nine months ended September 30, 2005. 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.

Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses for the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005 was primarily due to an increase of $2,415,211 in legal, accounting and consulting fees, a $1,357,124 increase in payroll and benefits due to hiring of additional staff positions, a $1,144,066 increase in non-cash director and consulting expenses, a $577,392 increase in insurance expense primarily related to increased directors and officers insurance costs, a $546,372 increase in costs related to internal controls and procedures in connection with the Sarbanes-Oxley Act of 2002, a $272,977 increase in travel and entertainment, a $591,291 increase in general office and administrative expenses, a $252,399 increase in investor relations expense, a $216,819 increase in depreciation and amortization, a $151,220 increase in hardware, software, and other information technology related expenses, a $99,357 increase in supplies and repair and maintenance related to the Madera facility, a $59,874 increase in taxes, licenses, and fees, a $38,891 increase in advertising and promotion, a $33,597 increase in trade association dues and memberships, a $510,625 decrease in non-cash compensation expense, and a $294,765 increase in all other selling, general, and administrative expenses.

Feasibility Study Expensed in Connection with Acquisition of ReEnergy. There were no feasibility study expenses for the nine months ended September 30, 2006 as compared to $852,250 for the nine months ended September 30, 2005. This amount arose in the connection with the acquisition of ReEnergy and relates to a feasibility study for an ethanol plant in Visalia, California. Based on this study, ReEnergy entered into an option to buy land for the ethanol plant. The option expired unexercised on December 15, 2005.

Preferred Stock Dividends. Shares of our 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. For the nine months ended September 30, 2006, we had declared cash dividends on shares of our Series A Preferred Stock in the aggregate amount of $1,947,534.

Deemed Dividend on Preferred Stock. We have recorded a deemed dividend on preferred stock in our financial statements for the nine months ended September 30, 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.

During the nine months ended September 30, 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 September 30, 2006, we had working capital of $101,001,323, representing an increase in working capital of $103,895,456 from negative working capital of $2,894,133 as of December 31, 2005. This increase in working capital is primarily due to private offerings of our Series A Preferred Stock and our common stock that we conducted in April and May 2006 in which we raised approximately $84 million and $138 million, respectively, in net proceeds.

Our current available capital resources consist primarily of approximately $101 million in cash as of September 30, 2006. We expect that our future available capital resources will consist primarily of any balance of the $101 million in cash as of September 30, 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 $60 million of restricted funds remaining as of September 30, 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.

Total other assets increased $70,185,757 during the nine months ended September 30, 2006 from $10,196,892 as of December 31, 2005 to $80,382,649 as of September 30, 2006. The increase is primarily due to an increase in restricted cash from the sale of our Series A Preferred Stock and deferred financing fees related to our April 2006 debt financing that may be used for the completion of our ethanol production facility in Madera County and proceeds from our private offering of common stock in May 2006.

Cash used in our investing activities totaled $115,531,407 for the nine months ended September 30, 2006 as compared to $6,321,638 for the nine months ended September 31, 2005. Included in the results for the nine months ended September 30, 2006 is $60,642,097 in restricted cash designated for construction projects and acquisitions, $57,639,310 in cash used for additions to property, plant, and equipment primarily reflecting the Madera County plant construction and $2,750,000 in proceeds from the sale of marketable securities.

Cash provided by our financing activities totaled $224,428,264 for the nine months ended September 30, 2006 as compared to $19,394,918 for the nine months ended September 30, 2005. This significant increase is related to proceeds from our private offerings of common stock and Series A Preferred Stock in April and May 2006, respectively, as well as from the exercise of warrants and stock options. The amount for the nine months ended September 30, 2005 includes the proceeds from the sale of our common stock in March 2005.

In October 2006, we acquired 42% of the outstanding membership interests of Front Range Energy, LLC, 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.

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 and will be disbursed in accordance with a Deposit Agreement. We are entitled to use 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. Of the $80.0 million deposited into the restricted cash account, $20.0 million has been advanced to us for use in the construction of our Madera County ethanol plant.

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. If we draw down on this facility, we must use the loan proceeds for the financing of our Madera County ethanol production facility. We may terminate the debt financing and its related agreements by December 15, 2006. If we terminate the debt financing, we will be obligated to pay a termination fee of $1.0 million to the lenders. If we do not terminate the loan but fail to draw down on the full $34.0 million by December 15, 2006, we may be obligated to pay a fee in the amount of up to $1.0 million to the lenders, calculated in proportion to the balance of the $34.0 million that we have not utilized.

In addition to the Construction and Term Loan Agreement with TD BankNorth, N.A. and Comerica Bank described above, we will require substantial additional debt financing to complete the construction of the ethanol facilities we currently have under development. We anticipate that additional debt financing will take the form of construction loans secured by projects under construction and term financing that will replace the construction loans, except with respect to our Boardman, Oregon project, which we are initially self-financing but which we expect to convert to term financing and withdrawal capital contributions after its completion.

We believe that current and future available capital resources, revenues generated from operations and other existing sources of liquidity, including our credit facilities, remaining proceeds from our private offerings of Series A Preferred Stock and common stock, distributions, if any, as a result of our ownership interest in Front Range Energy, LLC, and the available proceeds from anticipated construction and term loans, will be adequate to meet our anticipated working capital and capital expenditure requirements for at least the next twelve months.

As part of our risk management strategy, we use derivative instruments to protect cash flows from fluctuations caused by volatility in commodity prices out up to fifteen months. These hedging activities are conducted to protect product margin 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 NYMEX price of gasoline or the Chicago Board of Trade price of ethanol. In addition, we hedge anticipated sales of ethanol to minimize our exposure to the potentially adverse effects of price volatility. These derivatives are designated and documented as SFAS No. 133 cash flow hedges and effectiveness is evaluated by assessing the probability of the anticipated transactions and regressing commodity futures prices against our purchase and sales prices. Ineffectiveness, which is defined as the degree to which the derivative does not offset the underlying exposure, is recognized immediately in income. In the three and nine months ending September 30, 2006 $753,486 and $771,044 of ineffectiveness was recorded in cost of goods sold. In the three and nine months ending September 30, 2006 $1,080,384 and $892,140 was recorded in other income, respectively. There was no ineffectiveness or effectiveness recorded in the nine months ended September 30, 2005. Amounts remaining in other comprehensive income will be reclassified to earnings upon the recognition of the related purchase or sale. The notional balance of these derivatives as of September 30, 2006 and 2005 were $32,560,500 and $0, respectively.

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 cost associated with existing and anticipated borrowings. To meet these objectives we purchased two interest rate caps on three-month LIBOR in May 2006. Both interest rate caps call for quarterly interest rate payments. The cap rate for a notional balance ranging from $0 to $22,705,473 is 5.50% per annum. The cap 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 caps against the historical value in the existing and anticipated debt. Ineffectiveness, reflecting the degree to which the derivative does not offset the underlying exposure, is recognized immediately in income. During the three and nine months ending September 30, 2006, ineffectiveness in the amount of $38,299 was recorded in interest expense. Amounts remaining in other comprehensive income will be reclassified to earnings upon the recognition of the hedged interest expense.

We conducted an evaluation, with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, as of September 30, 2006, to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities Exchange Commission’s rules and forms, including to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is accumulated and communicated to management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of September 30, 2006, our disclosure controls and procedures were not effective at the reasonable assurance level due to the material weakness described below.

A material weakness is a control deficiency (within the meaning of the Public Company Accounting Oversight Board (PCAOB) Auditing Standard No. 2) or combination of 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. On April 7, 2006, in connection with its audit of our consolidated financial statements for the year ended December 31, 2005, and again in connection with its review of our consolidated financial statements for the three and nine months ended September 30, 2006, Hein & Associates LLP, our independent registered public accounting firm (“Hein”), advised management and our audit committee of the following matter that Hein considered to be a material weakness: 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.

Hein stated that this matter was evidenced by the following issues encountered in connection with its audit of our consolidated financial statements for the year ended December 31, 2005: (i) we were unable to provide accurate accounting for and disclosure of the Share Exchange Transaction, (ii) our closing procedures were not adequate and resulted in significant accounting adjustments, and (iii) we were unable to adequately perform the financial reporting process as evidenced by a significant number of suggested revisions and comments by Hein to our consolidated financial statements and related disclosures for the year ended December 31, 2005. In addition to issues (ii) and (iii) above, which Hein restated as issues encountered in connection with its review of our consolidated financial statements for the three and nine months ended September 30, 2006, Hein stated that this matter was further evidenced by inadequate supervision within our accounting department which contributed to our inability to provide accurate accounting for and disclosure of certain basic transactions.

As a result of the identification of this matter by Hein, management evaluated, with consultation from our audit committee, in the fourth quarter of 2006 and as of September 30, 2006, the impact of our lack of appropriate resources and adequate technical skills in our accounting department and concluded, in the fourth quarter of 2006 and as of September 30, 2006, that the control deficiency that resulted in our lack of appropriate resources and adequate technical skills in our accounting department represented a material weakness and concluded that, as of September 30, 2006, our disclosure controls and procedures were not effective at the reasonable assurance level.

In the second quarter of 2006, we developed plans to alter the current organization of our accounting department to hire additional personnel to assist in our financial reporting processes, including a Director of Financial Reporting who has expertise in public company financial reporting compliance and one or more additional accounting supervisory support staff members who will report to our Controller and/or our Director of Financial Reporting. In the third quarter of 2006, we developed plans to hire a new Controller and a Director of Accounting. In the fourth quarter of 2006, we developed plans to hire an Internal Auditor to further assist us in our financial reporting processes.

In the second quarter of 2006, we successfully hired a Director of Financial Reporting who has expertise in public company financial reporting compliance. During this period, we also replaced one support staff member with a more well-qualified individual. We continue to seek to hire a Controller, a Director of Accounting and one or more additional accounting supervisory support staff members who will report to our Controller and/or our Director of Financial Reporting. During the second quarter of 2006, we also hired a General Counsel who has expertise in public company reporting compliance and related legal matters.

In the second and third quarters of 2006, we sought guidance from financial consultants who are certified public accountants with the requisite background and experience to assist us in identifying and evaluating complex accounting and reporting matters. In addition, during these periods, we implemented new internal processes for identifying and disclosing both routine and non-routine transactions and for researching and determining proper accounting treatment for those transactions. During these periods, we also assigned personnel to perform these processes and continued to provide those individuals with technical and other resources to help ensure the proper application of accounting principles and the timely and appropriate disclosure of routine and non-routine transactions.

We believe that our current Director of Financial Reporting, and any additional accounting supervisory support staff members, a new Controller, a Director of Accounting and an Internal Auditor, once hired, will contribute additional expertise to our team of finance and accounting personnel and will assist us in our financial reporting processes. In addition, we believe that, by replacing one support staff member with a more well-qualified individual, we have added an individual who will contribute additional expertise to our team of finance and accounting personnel. We also believe that our General Counsel will work effectively with our Chief Financial Officer and our Director of Financial Reporting to help ensure that our reporting obligations are satisfied. Finally, we believe that once our accounting department is strengthened through the addition of these additional staff members, we will have in place an adequate supervisory structure to ensure accurate accounting for and disclosure of all transactions in a timely manner.

Management is unsure, at the time of the filing of this report, when the actions described above will remediate the material weakness also described above. Although management intends to hire one or more additional accounting supervisory support staff members, a new Controller, a Director of Accounting and an Internal Auditor as soon as practicable, it may take an extended period of time until suitable candidates can be located and hired. Management is, however, optimistic that these personnel can be located and hired by the end of the first quarter of 2007. Until we hire the necessary additional accounting supervisory support staff members, a new Controller, a Director of Accounting and an Internal Auditor, as planned, management may hire outside consultants to assist us in satisfying our financial reporting obligations.

Our Director of Financial Reporting has an annual base salary of $85,000, not including benefits and other costs of employment. Our General Counsel has an annual base salary of $185,000, not including benefits and other costs of employment. Management believes that suitable candidates for our additional accounting supervisory support staff positions will have annual base salaries in the range of $35,000 to $50,000, a new Controller will have an annual base salary in the range of $125,000 to $150,000, a Director of Accounting will have an annual base salary in the range of $75,000 to $90,000 and an Internal Auditor will have an annual base salary in the range of $100,000 to $125,000, not including benefits and other costs of employment. Management is unable, however, to estimate our expenditures related to fees paid or that may be paid in the future to financial consultants in connection with their guidance in identifying and evaluating complex accounting and reporting matters. Management is also unable to estimate our expenditures related to the development of new internal processes for identifying and disclosing both routine and non-routine transactions and for researching and determining proper accounting treatment for those transactions. Management is also unable to estimate our expenditures related to the hiring of other outside consultants to assist us in satisfying our financial reporting obligations. In addition, management is unable to estimate our expenditures related to higher fees to be paid to our independent auditors in connection with their review of this remediation.

The changes noted above, specifically, the changes relating to our (i) efforts to locate a suitable candidate for the position of Controller, a Director of Accounting and suitable candidates to fill one or more accounting supervisory support staff positions, (ii) engaging of financial consultants who are certified public accountants to assist us in identifying and evaluating complex accounting and reporting matters, (iii) new internal processes for identifying and disclosing both routine and non-routine transactions and for researching and determining proper accounting treatment for those transactions, and (iv) assignment of individuals to perform these processes and provision to those individuals of technical and other resources to help ensure the proper application of accounting principles and the timely and appropriate disclosure of routine and non-routine transactions, 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.

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.

On December 23, 2005, Barry J. Spiegel, a stockholder of Pacific Ethanol and former director of Accessity, filed a complaint in the Circuit Court of the 17th Judicial District in and for Broward County, Florida (Case No. 05018512), or the Spiegel Action, against Barry Siegel, Philip Kart, Kenneth Friedman and Bruce Udell, or collectively, the Defendants. Messrs. Siegel, Udell and Friedman are former directors of Accessity and Pacific Ethanol. Mr. Kart is a former executive officer of Accessity and Pacific Ethanol.

The Spiegel Action relates to the Share Exchange Transaction and purports to state the following five counts against the Defendants: (i) breach of fiduciary duty, (ii) violation of Florida’s Deceptive and Unfair Trade Practices Act, (iii) conspiracy to defraud, (iv) fraud, and (v) violation of Florida Securities and Investor Protection Act. Mr. Spiegel is seeking $22.0 million in damages. On March 8, 2006, Defendants filed a motion to dismiss the Spiegel Action, which remains pending. No discovery has been taken.

In January 2003, DriverShield CRM Corp., or DriverShield, then a wholly-owned subsidiary of our predecessor, Accessity, was served with a complaint filed by Mr. Gerald Zutler, its former President and Chief Operating Officer, alleging, among other things, that DriverShield breached its employment contract with Mr. Zutler, that there was fraudulent concealment of DriverShield’s intention to terminate its employment agreement with Mr. Zutler, and discrimination on the basis of age and aiding and abetting violation of the New York State Human Rights Law. The complaint was filed in the Supreme Court of the State of New York, County of Nassau, Index No.: 654/03. Mr. Zutler sought damages of approximately $2.2 million, plus punitive damages and reasonable attorneys’ fees. On July 20, 2006, we settled Mr. Zutler’s claims in full and subsequently made a settlement payment to Mr. Zutler, approximately one-third of which was covered by DriverShield’s insurance carrier.

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.

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 tortuously interfering in the transaction between us and Presidion. In 2004, we dismissed this lawsuit without prejudice, which was filed in Florida state court. We recently 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 March 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.

An investment in our common stock involves a high degree of risk. In addition to the other information in this report and in our other filings with the Securities and Exchange Commission, you should carefully consider the following risk factors before deciding to invest in shares of our common stock or to maintain or increase your investment in shares of our common stock. If any of the following risks actually occur, it is likely that our business, financial condition and results of operations could be seriously harmed. As a result, the trading price of our common stock could decline, and you could lose part or all of your investment.

We have incurred significant losses in the past. For the year ended December 31, 2005, we incurred a net loss of approximately $9.9 million. 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.

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 production and marketing of ethanol and its co-products for the foreseeable future. We may be unable to shift our business focus away from the production and marketing 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.

Domestic ethanol production capacity has increased steadily from 1.7 billion gallons per year in January of 1999 to 4.8 billion gallons per year at June 2006 according to the Renewable Fuels Association, or RFA. In addition, there is a significant amount of capacity being added to our industry. We believe that approximately 2.0 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 $150.0 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.

In connection with its audit of our consolidated financial statements for the year ended December 31, 2005 and its review of our consolidated financial statements for the three and nine months ended September 30, 2006, our independent registered public accounting firm advised management of the following matter that the accounting firm considered to be a material weakness: The current organization of our accounting department does not provide us with the appropriate resources and adequate technical skills to accurately account for and disclose our activities. Our resources to produce reliable financial reports and fulfill our other obligations as a public company are limited due to our small number of employees and the limited public company experience of our management. The existence of one or more material weaknesses in our internal controls could result in errors in our financial statements and substantial costs and resources may be required to rectify these material weaknesses. If we are unable to produce reliable financial reports, investors could lose confidence in our reported financial information, the market price of our stock could decline significantly, we may be unable to obtain additional financing to operate and expand our business, and our business and financial condition could be harmed.

Our strategy envisions a period of rapid growth. We plan to grow our business by investing in new facilities and/or acquiring existing facilities 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 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 facility too expensive to complete or unprofitable to operate. We have not entered into any construction contracts, other than site acquisition arrangements, 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.

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 in the first nine months of 2006 by rising approximately 38% above our 2005 average price per gallon. 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 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 profits. 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.

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.

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, 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 bought by ethanol plants represented approximately 13% of the 2005 total corn supply according to 2005 results reported by the National Corn Growers Association. The increasing ethanol capacity could boost demand for corn and result in increased prices for corn.

The production of ethanol also requires a significant amount of other raw materials and energy, primarily water, electricity and natural gas. For example, we estimate that our Madera County ethanol production facility will 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 production of ethanol is made significantly more competitive by federal tax incentives. The Federal Excise Tax Credit, or FETC, 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 tax credit for each gallon of ethanol used in the mixture. The FETC 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 FETC could have a material adverse effect 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 Renewable Fuels Standard, or 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. In addition, the Department of Energy was directed under the Energy Policy Act of 2005 to conduct a study by January 2006 to determine if the RFS will have a severe adverse impact on consumers in 2006 on a national, regional or state basis. Based on the results of the study, the Secretary of Energy must make a recommendation to the EPA as to whether the RFS should be waived for 2006. Any waiver of the RFS with respect to one or more states or with respect to 2006 would adversely offset demand for ethanol and could have a material adverse effect on our results of operations and financial condition.

The Reformulated Gasoline, or 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.

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 U.S. House of Representatives and U.S. 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. In particular, the ethanol industry has expressed concern with respect to a new plant under development by Cargill, Inc., the fifth largest ethanol producer in the United States, in El Salvador that would take the water out of Brazilian ethanol and then ship the dehydrated ethanol from El Salvador to the United States duty-free. Since production costs for ethanol in Brazil are estimated to be significantly less than what they are in the United States, the import of the Brazilian ethanol duty-free through El Salvador or another country exempted from the tariff may negatively impact the demand for domestic ethanol and the price at which we sell our ethanol.

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 profit 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.

The majority of our sales are generated from a small number of customers. During 2005, sales to our three largest customers, each of whom accounted for 10% or more of total net sales, represented approximately 18%, 11% and 10%, respectively, representing an aggregate of approximately 39%, of our total net sales. During 2004, sales to Kinergy’s four largest customers, each of whom accounted for 10% or more of total net sales, represented approximately 13%, 12%, 12% and 12%, respectively, representing an aggregate of approximately 49%, of Kinergy’s 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.

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. During 2005, our three largest suppliers, each of whom accounted for 10% or more of total purchases, represented approximately 22%, 20%, and 17%, respectively, of purchases, representing an aggregate of approximately 59%, of the total ethanol we purchased for resale. During 2004, Kinergy’s three largest suppliers, each of whom accounted for 10% or more of the total purchases, represented approximately 27%, 23% and 14%, respectively, of purchases, representing an aggregate of approximately 64% of the total ethanol Kinergy 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.

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.

The ethanol production and marketing industry is extremely competitive. Many of our significant competitors in the ethanol production and marketing industry, such as Archer Daniels Midland Company, or 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. 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.

We also face increasing competition from international suppliers. Although there is a $0.54 per gallon tariff, which is scheduled to expire in 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.

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.

Front Range Energy, LLC operates an ethanol production facility located in Windsor, Colorado. We own approximately 42% of Front Range Energy, LLC, which represents a minority interest in that entity. The manager and majority member of Front Range Energy, LLC owns approximately 51% of that entity and has control that entity’s business decisions, including those related to day-to-day operations. The manager and majority member of Front Range Energy, LLC has the exclusive 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 dependent upon the business judgment and conduct of the manager and majority member of Front Range Energy, LLC. As a result, our interests may not be as well served as if we were in control of Front Range Energy, LLC. Accordingly, the contribution by Front Range Energy, LLC 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.

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. In addition, we are in the process of registering for resale approximately 2.8 million shares of our common stock, including shares of our common stock underlying a warrant, in the registration statement of which this prospectus forms a part. If and when the registration statement covering these shares of common stock is declared effective, holders of these shares will be 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., 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 November 14, 2006, 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.

Other negative effects to our common stockholders will include potential 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 12% 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.

Furthermore, we believe that the economic conditions in California and other states, as well as the United States as a whole, could have a negative impact on our results of operations. Demand for ethanol could also be adversely affected by a slow-down in overall demand for oxygenate and gasoline additive products. The levels of our ethanol production and purchases for resale will be based upon forecasted demand. Accordingly, any inaccuracy in forecasting anticipated revenues and expenses could adversely affect our business. The failure to receive anticipated orders or to complete delivery in any quarterly period could adversely affect our results of operations for that period. Quarterly results are not necessarily indicative of future performance for any particular period, and we may not experience revenue growth or profitability on a quarterly or an annual basis.

The price at which you purchase shares of our common stock may not be indicative of the price that will prevail in the trading market. You may be unable to sell your shares of common stock at or above your purchase price, which may result in substantial losses to you and which may include the complete loss of your investment. In the past, securities class action litigation has often been brought against a company following periods of stock price volatility. We may be the target of similar litigation in the future. Securities litigation could result in substantial costs and divert management’s attention and our resources away from our business. Any of the risks described above could adversely affect our sales and profitability and also the price of our common stock.

(a) We held our 2006 annual meeting of stockholders on September 7, 2006. As of the close of business on July 21, 2006, the record date for determining stockholders entitled to notice of and to vote at the 2006 annual meeting, we had issued and outstanding 37,223,236 shares of common stock held by 527 holders of record and 5,250,000 shares of Series A Cumulative Redeemable Convertible Preferred Stock , or Series A Preferred Stock, held by one holder of record. A total of 38,695,638 votes were represented in person or by proxy at the meeting and constituted a quorum.

Exhibit Number		Description
10.1		Amended and Restated Ethanol Purchase and Sale Agreement dated as of August 9, 2006 by and between Kinergy Marketing, LLC and Front Range Energy, LLC (1)
10.2		Construction Agreement for the Boardman Project between Pacific Ethanol Columbia, LLC and Parsons RCIE Inc. dated as of August 28, 2006 (2)
10.3		Engineering, Procurement and Technology License Agreement dated September 6, 2006 by and between Delta-T Corporation and PEI Columbia, LLC (#)(*)
10.4		Engineering, Procurement and Technology License Agreement (Plant No. 3) dated September 6, 2006 by and between Delta-T Corporation and Pacific Ethanol, Inc. (#)(*)
10.5		Engineering, Procurement and Technology License Agreement (Plant No. 4) dated September 6, 2006 by and between Delta-T Corporation and Pacific Ethanol, Inc. (#)(*)
10.6		Engineering, Procurement and Technology License Agreement (Plant No. 5) dated September 6, 2006 by and between Delta-T Corporation and Pacific Ethanol, Inc. (#)(*)
31.1		Certifications Required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (#)
31.2		Certifications Required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (#)
32.1		Certification of President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (#)

Exhibit Number		Description
10.3		Engineering, Procurement and Technology License Agreement dated September 6, 2006 by and between Delta-T Corporation and PEI Columbia, LLC (*)
10.4		Engineering, Procurement and Technology License Agreement (Plant No. 3) dated September 6, 2006 by and between Delta-T Corporation and Pacific Ethanol, Inc. (*)
10.5		Engineering, Procurement and Technology License Agreement (Plant No. 4) dated September 6, 2006 by and between Delta-T Corporation and Pacific Ethanol, Inc. (*)
10.6		Engineering, Procurement and Technology License Agreement (Plant No. 5) dated September 6, 2006 by and between Delta-T Corporation and Pacific Ethanol, Inc. (*)
31.1		Certification Required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification Required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification of President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

		Page
Item 1.	Financial Statements
	Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005	F-2
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2006 and 2005	F-4
	Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2006 and 2005	F-5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2006 and 2005	F-6
	Notes to Consolidated Financial Statements	F-8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	16
Item 4.	Controls and Procedures	18

PART II OTHER INFORMATION
Item 1.	Legal Proceedings	21
Item 1A.	Risk Factors	23
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Defaults Upon Senior Securities	34
Item 4.	Submission of Matters to a Vote of Security Holders	34
Item 5.	Other Information	35
Item 6.	Exhibits	35
Signatures		36

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005

Employees — included in general and administrative	$	188,733	$	68,456	$	834,637	$	951,706
Non-employees — included in general and administrative		934,921		337,975		1,491,271		798,361
Total stock-based compensation expense	$	1,123,654	$	406,431	$	2,325,908	$	1,750,067

	Number of Shares			Weighted Average Exercise Price
Outstanding at January 1, 2006		927,500		$	7.53
Granted		—		$	—
Exercised		(193,500	)	$	7.06
Terminated		(3,000	)	$	5.50
Outstanding at September 30, 2006		731,000		$	7.65
Options exercisable at September 30, 2006		351,000		$	7.57

	Three Months Ended September 30, 2006
	Income Numerator			Shares Denominator		Per-Share Amount

Net income	$	3,754,684
Less: Preferred stock Dividends		(1,050,000	)

Basic Earning per Share
Income available to common stockholders		2,704,684			37,228,096	$	0.07
Effect of outstanding warrants		—			187,500
Effect of outstanding options		—			352,351

Diluted Earning per Share
Income available to common stockholders, including assumed conversions	$	2,704,684			37,767,947	$	0.07

	September 30, 2006			December 31, 2005
Land	$	515,298		$	515,298
Facilities		4,234,703			4,234,703
Equipment and vehicles		390,152			373,520
Office furniture, fixtures and equipment		809,766			378,149
		5,949,919			5,501,670
Accumulated depreciation		(386,867	)		(210,675	)
		5,563,052			5,290,995
Construction in progress		75,103,152			17,917,253
	$	80,666,204		$	23,208,248

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Customer A		14%		16%		16%		17%
Customer B		17%		14%		15%		12%
Customer C		11%		9%		11%		9%
Customer D		13%		2%		9%		2%

	September 30, 2006		December 31, 2005
Raw materials	$	1,481,112		—
Finished goods		4,246,189		362,972
Total	$	5,727,301		362,972

	September 30, 2006		December 31, 2005
Fire damage restoration in progress	$	850,636	$	3,157,969
Insurance policy premium financing		—		209,469
Preferred stock dividend payable		1,050,000		—
Other accrued liabilities		1,517,533		55,127
Total accrued liabilities	$	3,418,168	$	3,422,565

	Number of Shares			Price per Share		Weighted Average Exercise Price
Balance at December 31, 2005		2,904,818		$	0.0001 - 5.00	$	3.26
Warrants granted		2,748,297			31.55		31.55
Warrants exercised		(2,718,317	)		0.0001 - 5.00		0.17
Balance at September 30, 2006		2,934,798		$	0.0001 - 31.55	$	29.19

Range of Exercise Prices	Warrants Outstanding			Warrants Exercisable
Range of Exercise Prices	Number Outstanding	Weighted Average Remaining Contractual Life	Weighted-Average Exercise Price	Number Exercisable	Weighted-Average Exercise Price
$0.0001	57,501	2.51	$0.0001	—	—
$3.00	86,000	0.48	$3.00	86,000	$3.00
$5.00	43,000	0.48	$5.00	44,000	$5.00
$31.55	2,748,297	0.41	$31.55	2,748,297	$31.55
	2,934,798			2,878,297

	Commodity Derivatives			Interest Rate Derivatives
	Gain/(Loss)*			Gain/(Loss)*
Beginning balance, December 31, 2005	$	—		$	—
Net changes		875,190			214,495
Less: Amount reclassified to revenue		(1,057,238	)		—

Ending balance, September 30, 2006	$	(182,048	)	$	214,495

	September 30, 2006			December 31, 2005
Commodity futures	$	(64,827	)	$	—
Commodity options		7,905			—
Interest rate options		272,921			—
Total	$	215,999		$	—

Nominee	For		Withhold Authority
William L. Jones		38,236,514		459,124
Neil M. Koehler		38,275,960		419,678
Frank P. Greinke		38,217,921		477,717
Douglas L. Kieta		38,260,589		435,049
John L. Prince		38,223,130		472,508
Terry L. Stone		38,186,474		509,164
Robert P. Thomas		38,240,384		455,254

For:	22,007,297
Against:	2,212,300
Abstention:		114,846
Broker non-votes:		14,361,195