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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-Q
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2006
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM                      TO                     
Commission file number: 001-32567
 
Alon USA Energy, Inc.
(Exact name of Registrant as specified in its charter)
 
     
Delaware   74-2966572
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)   Identification No.)
7616 LBJ Freeway, Suite 300, Dallas, Texas 75251
(Address of principal executive offices) (Zip Code)
(972) 367-3600
(Registrant’s telephone number, including area code)
 
     Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer o      Accelerated Filer       o      Non-Accelerated Filer þ
     Indicate by check whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
     The number of shares of the Registrant’s common stock, par value $0.01 per share, outstanding as of August 11, 2006 was 46,806,443.
 
 

 


 

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CERTIFICATION OF CEO PURSUANT TO SECTION 302
       
CERTIFICATION OF CFO PURSUANT TO SECTION 302
       
CERTIFICATION OF CEO AND CFO PURSUANT TO SECTION 906
       
 Certifications of CEO Pursuant to Section 302
 Certifications of CFO Pursuant to Section 302
 Certifications of CEO and CFO Pursuant to Section 906
-i-

 


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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands except per share data)
                 
    June 30,     December 31,  
    2006     2005  
    (Unaudited)          
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 204,348     $ 136,820  
Short-term investments
          185,320  
Accounts and other receivables, net
    129,966       89,529  
Inventories
    113,393       79,181  
Prepaid expenses and other current assets
    7,496       6,264  
 
           
Total current assets
    455,203       497,114  
 
           
Investment in HEP
    22,322       22,754  
Property, plant and equipment, net
    211,933       211,410  
Other assets
    57,143       27,502  
 
           
Total assets
  $ 746,601     $ 758,780  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable
  $ 136,004     $ 157,076  
Accrued liabilities
    58,323       48,128  
Current portion of deferred gain on disposition of assets
    10,750       11,427  
Current portion of long-term debt
    2,067       4,487  
 
           
Total current liabilities
    207,144       221,118  
 
           
Other non-current liabilities
    17,800       18,345  
Deferred gain on disposition of assets
    47,397       52,433  
Long-term debt
    29,096       127,903  
Deferred income tax liability
    76,652       52,422  
 
           
Total liabilities
    378,089       472,221  
 
           
Commitments and contingencies (note 14)
               
Minority interest in subsidiaries
    12,571       7,066  
 
           
Stockholders’ equity:
               
Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding
           
Common stock, par value $0.01, 100,000,000 shares authorized; 46,806,443 and 46,809,857 shares issued and outstanding at June 30, 2006 and December 31, 2005, respectively
    468       468  
Additional paid-in capital
    181,366       181,108  
Accumulated other comprehensive loss, net of income tax
    (2,596 )     (2,596 )
Retained earnings
    176,703       100,513  
 
           
Total stockholders’ equity
    355,941       279,493  
 
           
Total liabilities and stockholders’ equity
  $ 746,601     $ 758,780  
 
           
The accompanying footnotes are an integral part of these financial statements.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except per share data)
                                 
    For the Three Months Ended     For the Six Months Ended  
    June 30,     June 30,  
    2006     2005     2006     2005  
Net sales
  $ 672,262     $ 590,366     $ 1,256,963     $ 998,340  
Operating costs and expenses:
                               
Cost of sales
    556,689       498,047       1,054,516       849,601  
Direct operating expenses
    22,164       20,373       45,435       38,709  
Selling, general and administrative expenses
    20,354       18,983       37,807       35,648  
Depreciation and amortization
    5,408       5,018       10,931       9,852  
 
                       
Total operating costs and expenses
    604,615       542,421       1,148,689       933,810  
 
                       
Gain on disposition of assets
    2,279       1,530       57,665       29,223  
 
                       
Operating income
    69,926       49,475       165,939       93,753  
Interest expense
    (1,349 )     (4,745 )     (10,396 )     (9,752 )
Equity earnings in HEP
    176       277       753       412  
Other income, net
    2,174       830       4,101       1,080  
 
                       
Income before income tax expense and minority interest in income of subsidiaries
    70,927       45,837       160,397       85,493  
Income tax expense
    25,607       16,354       58,133       32,009  
 
                       
Income before minority interest in income of subsidiaries
    45,320       29,483       102,264       53,484  
Minority interest in income of subsidiaries
    2,229       2,001       5,009       3,566  
 
                       
Net income
  $ 43,091     $ 27,482     $ 97,255     $ 49,918  
 
                       
Earnings per share
  $ .92     $ .79     $ 2.08     $ 1.43  
 
                       
 
                               
Weighted average shares outstanding
    46,733,009       35,001,120       46,732,064       35,001,120  
 
                       
Cash dividends per share
  $ .04     $     $ .45     $  
 
                       
The accompanying footnotes are an integral part of these financial statements.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, dollars in thousands)
                 
    For the Six Months Ended  
    June 30,  
    2006     2005  
Cash flows from operating activities:
               
Net income
  $ 97,255     $ 49,918  
Adjustments to reconcile net income to cash (used in) provided by operating activities:
               
Depreciation and amortization
    10,931       9,852  
Stock compensation
    1,420       191  
Deferred income tax expense
    22,658       8,237  
Minority interest in income of subsidiaries
    5,009       3,566  
Accrued interest on subordinated notes to stockholders
          1,059  
Gain on disposition of assets
    (57,665 )     (29,223 )
Changes in operating assets and liabilities:
               
Accounts and other receivables, net
    (40,471 )     (23,241 )
Inventories
    (34,212 )     (6,015 )
Prepaid expenses and other current assets
    340       (1,369 )
Other assets
    1,903       930  
Accounts payable
    (21,072 )     35,113  
Accrued liabilities
    9,518       1,427  
Other non-current liabilities
    (324 )     (1,057 )
 
           
Net cash (used in) provided by operating activities
    (4,710 )     49,388  
 
           
 
               
Cash flows from investing activities:
               
Capital expenditures
    (23,165 )     (16,459 )
Turnaround and chemical catalyst expenditures
    (2,925 )     (10,781 )
Proceeds from disposition of assets, net
    68,000       118,000  
Escrow deposits and costs relating to acquisitions
    (31,868 )      
Sale of short-term investments, net
    185,320        
Dividends from investment in HEP (net of equity earnings in HEP)
    432       104  
Minority interest shares purchased
    (186 )     (2,717 )
 
           
Net cash provided by investing activities
    195,608       88,147  
 
           
 
               
Cash flows from financing activities:
               
Dividends paid to minority interest stockholders
    (1,078 )     (1,482 )
Dividends paid to stockholders
    (21,065 )      
Additions to long-term debt
          2,932  
Payments on long-term debt
    (101,227 )     (33,796 )
 
           
Net cash used in financing activities
    (123,370 )     (32,346 )
 
           
 
               
Net change in cash and cash equivalents
    67,528       105,189  
Cash and cash equivalents, beginning of period
    136,820       63,357  
 
           
Cash and cash equivalents, end of period
  $ 204,348     $ 168,546  
 
           
The accompanying footnotes are an integral part of these financial statements.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, dollars in thousands)
                 
    For the Six Months Ended  
    June 30,  
    2006     2005  
Supplemental cash flow information:
               
Cash paid for interest
  $ 6,617     $ 7,782  
 
           
Cash paid for income tax
  $ 17,596     $ 12,447  
 
           
 
               
Non-cash activities:
               
Investing activity — receipt of Class B HEP subordinated units as proceeds from disposition of assets
  $     $ 30,000  
 
           
The accompanying footnotes are an integral part of these financial statements.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
(1) Basis of Presentation and Certain Significant Accounting Policies
     (a) Basis of Presentation
     The consolidated financial statements include the accounts of Alon USA Energy, Inc. and its subsidiaries (collectively, “Alon”). All significant intercompany balances and transactions have been eliminated. These consolidated financial statements of Alon are unaudited and have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements. In the opinion of Alon’s management, the information included in these consolidated financial statements reflects all adjustments, consisting of normal and recurring adjustments, which are necessary for a fair presentation of Alon’s consolidated financial position and results of operations for the interim periods presented. The results of operations for the interim periods are not necessarily indicative of the operating results that may be obtained for the year ending December 31, 2006.
     The consolidated balance sheet as of December 31, 2005 has been derived from the audited financial statements as of that date. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in Alon’s Annual Report on Form 10-K for the year ended December 31, 2005.
     (b) Revenue Recognition
     In September 2005, the Emerging Issues Task Force, (“EITF”) reached a consensus concerning the accounting for linked purchase and sale arrangements in EITF Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. The EITF concluded that non-monetary exchanges of finished goods inventory within the same line of business be recognized at the carrying value of the inventory transferred. Alon began applying this consensus for new buy/sell arrangements beginning January 1, 2006.
     Alon occasionally enters into refined product buy/sell arrangements, which involve linked purchases and sales related to refined product sales contracts entered into to address location, quality or grade requirements. As of January 1, 2006, these buy/sell transactions are included on a net basis in sales in the consolidated statements of operations and profits are recognized when the exchanged product is sold. Prior to the adoption of EITF Issue No. 04-13, the results of these linked refined product buy/sell transactions were recorded separately in sales and cost of sales in the consolidated statements of operations. In the ordinary course of business, logistical and refinery production schedules necessitate the occasional sale of crude oil to third parties. All purchases and sales of crude oil, currently and historically, are recorded on a net basis, in cost of sales in the consolidated statements of operations.
     Sulfur credits purchased to meet federal gasoline sulfur regulations are recorded in inventory at the lower of cost or market. Cost is computed on an average cost basis. Purchased sulfur credits are removed from inventory and charged to cost of sales in the consolidated statements of operations as they are utilized. Sales of excess sulfur credits are recognized currently in earnings and included in net sales in the consolidated statements of operations.
     (c) New Accounting Standards
     Effective January 1, 2006, Alon adopted Statement of Financial Accounting Standards No. 123R, Share-Based Payment (“SFAS No. 123R”), which requires use of the fair-value based method and expensing of stock options and other share-based compensation payments to employees, net of estimated forfeitures, over the requisite service period and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing pro-forma disclosure only. As a private company, Alon used the minimum value method of measuring equity share options for pro-forma disclosure purposes under SFAS No. 123. Accordingly, Alon applied SFAS No. 123R prospectively to new awards and to awards modified, repurchased or forfeited after January 1, 2006. Alon applied the modified prospective transition method to any unvested stock-based awards issued after the initial public

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
offering (“IPO”). The adoption of SFAS No. 123R did not have a significant effect on Alon’s financial position or results of operations.
     Alon previously accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations (“Opinion 25”). Accordingly, compensation cost for stock options was measured as the excess of the estimated fair value of the common stock over the exercise price and was recognized over the scheduled vesting period on an accelerated basis. Stock compensation expense is presented as selling, general and administrative expenses in the accompanying consolidated statements of operations. All pre-IPO stock-based awards will continue to be accounted for under Opinion 25.
     In November 2004, the Financial Accounting Standards Board (“FASB”) issued Statement No. 151, Inventory Costs, which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material and requires that those items be recognized as current-period charges. Statement No. 151 also requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. Statement No. 151 is effective for fiscal years beginning after June 15, 2005. The adoption of Statement No. 151 did not have a material effect on Alon’s financial position or results of operations.
     In December 2004, the FASB issued FASB Staff Position (“FSP”) FAS 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004 (“Jobs Creation Act”) which requires a company that qualifies for the deduction for domestic production activities under the Jobs Creation Act to account for it as a special deduction under FASB Statement No. 109, Accounting for Income Taxes, as opposed to an adjustment of recorded deferred tax assets and liabilities.
     In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (“FIN No. 48”). This interpretation prescribes a “more-likely-than-not” recognition threshold and measurement attribute (the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement with tax authorities) for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provided guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. Alon will adopt the provisions of FIN No. 48 on January 1, 2007 and does not expect these provisions to have a material effect on Alon’s results of operations, financial condition or liquidity.
(2) Sale of Amdel and White Oil Pipelines
     On March 1, 2006, Alon sold its Amdel and White Oil pipelines, which had been inactive since December 2002, to an affiliate of Sunoco Logistics Partners L.P. (“Sunoco”) for total consideration of approximately $68,000. In conjunction with this transaction, Alon entered into a 10-year pipeline Throughput and Deficiency Agreement with options to extend the agreement by four additional 30-month periods. The Throughput and Deficiency Agreement will allow Alon to maintain its physically integrated system by retaining crude oil transportation rights in the pipelines from the Gulf Coast. Pursuant to the Throughput and Deficiency Agreement, Alon has agreed to ship, starting June 1, 2006, a minimum of 15,000 barrels per day (“bpd”) in the pipelines during the term of the agreement. Alon recognized a $52,500 pre-tax gain on disposition of assets in connection with this transaction in the first quarter of 2006.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
(3) Segment Data
     Alon’s revenues are derived from two operating segments: (i) Refining and Marketing and (ii) Retail. The operating segments adhere to the accounting policies used for Alon’s consolidated financial statements as described in Note 1. The reportable operating segments are strategic business units that offer different products and services. The segments are managed separately as each segment requires unique technology, marketing strategies and distinct operational emphasis. Each operating segment’s performance is evaluated primarily based on operating income.
     (a) Refining and Marketing Segment
     The refining and marketing segment includes a sophisticated sour crude oil refinery, crude oil and refined products pipeline systems and refined products terminalling operations. Alon’s refinery produces petroleum products including various grades of gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum-based products. In addition, finished products are acquired through exchange agreements and third-party suppliers. Alon primarily markets gasoline and diesel under the FINA brand name, through a network of approximately 1,215 locations. Finished products and blendstocks are also marketed through sales and exchanges with other major oil companies, state and federal governmental entities, unbranded wholesale distributors and various other third parties.
     (b) Retail Segment
     Alon’s retail segment operates 167 owned and leased 7-Eleven branded convenience store sites operating primarily in West Texas and New Mexico. These convenience stores typically offer various grades of gasoline, diesel fuel, general merchandise, food and beverage products to the general public under the 7-Eleven and FINA brand names.
     On July 3, 2006, Alon completed the purchase of 40 convenience stores in West Texas. Since that date, the retail segment has operated 207 owned and leased 7-Eleven branded convenience stores (see Note 15).
     (c) Corporate
     Operations that are not included in either of the two segments are included in the category Corporate. These operations consist primarily of corporate headquarter operating and depreciation expenses.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
     Segment data as of and for the three-month and six-month periods ended June 30, 2006 and 2005 are presented below.
                                 
    Refining and            
Three Months ended June 30, 2006   Marketing   Retail   Corporate   Total
Net sales to external customers
  $ 585,447     $ 86,815     $     $ 672,262  
Intersegment sales/purchases
    39,084       (39,084 )            
Depreciation and amortization
    3,801       1,110       497       5,408  
Operating income (loss)
    69,299       1,219       (592 )     69,926  
Total assets
    661,143       71,144       14,314       746,601  
Turnaround, chemical catalyst and capital expenditures
    18,141       1,951       57       20,149  
                                 
    Refining and            
Three Months ended June 30, 2005   Marketing   Retail   Corporate   Total
Net sales to external customers
  $ 503,182     $ 87,184     $     $ 590,366  
Intersegment sales/purchases
    39,592       (39,592 )            
Depreciation and amortization
    3,489       1,051       478       5,018  
Operating income (loss)
    49,379       702       (606 )     49,475  
Total assets
    529,673       70,884       12,325       612,882  
Turnaround, chemical catalyst and capital expenditures
    4,723       1,021       16       5,760  
                                 
    Refining and            
Six Months ended June 30, 2006   Marketing   Retail   Corporate   Total
Net sales to external customers
  $ 1,097,533     $ 159,430     $     $ 1,256,963  
Intersegment sales/purchases
    70,474       (70,474 )            
Depreciation and amortization
    7,646       2,264       1,021       10,931  
Operating income (loss)
    165,919       1,263       (1,243 )     165,939  
Total assets
    661,143       71,144       14,314       746,601  
Turnaround, chemical catalyst and capital expenditures
    23,840       2,174       76       26,090  
                                 
    Refining and            
Six Months ended June 30, 2005   Marketing   Retail   Corporate   Total
Net sales to external customers
  $ 837,260     $ 161,080     $     $ 998,340  
Intersegment sales/purchases
    72,448       (72,448 )            
Depreciation and amortization
    6,800       2,103       949       9,852  
Operating income (loss)
    94,167       791       (1,205 )     93,753  
Total assets
    529,673       70,884       12,325       612,882  
Turnaround, chemical catalyst and capital expenditures
    25,050       2,030       160       27,240  
     Operating income for each segment consists of net sales less cost of sales, direct operating expenses, selling, general and administrative expenses, depreciation and amortization and gain on disposition of assets. Sales between segments are transferred at current market prices. Consolidated totals presented are after intersegment eliminations.
     Total assets of each segment consist of property, plant and equipment, net of accumulated depreciation, investment in subsidiaries, inventories, accounts receivables, short-term investments, cash and cash equivalents and other assets directly associated with the segment’s operations. Corporate assets consist primarily of corporate headquarters information technology and administrative equipment, net of accumulated depreciation.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
(4) Cash, Cash Equivalents and Short-Term Investments
     All highly-liquid instruments with a short-term maturity of three months or less at the time of purchase are considered to be cash equivalents.
     Short-term investments primarily consist of highly-rated auction rate securities (“ARS”). Although ARS may have long-term stated maturities, generally 10 to 30 years, Alon has designated these securities as available-for-sale and has classified them as current assets because it views them as available to support its current operations. ARS may be liquidated at par on the rate reset date, which is in intervals of 7 to 49 days, depending on the terms of the security. These securities are carried at cost, which approximates market value.
     For the six months ended June 30, 2006, significant transactions affecting Alon’s cash balance included Alon’s January 19, 2006 payment of approximately $100,000 in satisfaction of its outstanding borrowings under the secured term loan agreement (see Note 10), Alon’s sale of its Amdel and White Oil pipelines for total consideration of approximately $68,000 (see Note 2) and escrow deposits and costs relating to acquisitions of $31,868 (see Note 15).
(5) Derivatives and Hedging Activities
     (a) Fair Value of Financial Instruments
     The carrying amounts of Alon’s cash and cash equivalents, short-term investments, receivables, payables and accrued expenses approximate fair value due to the short-term maturities of these assets and liabilities. The reported amount of long-term debt approximates fair value. Derivative financial instruments are carried at fair value, which is based on quoted market prices.
     (b) Derivative Financial Instruments
     Alon selectively utilizes commodity derivatives to manage its exposure to commodity price fluctuations and interest rate-related derivative instruments to manage its exposure on its debt instruments. Alon does not enter into derivative instruments for any purpose other than cash flow hedging purposes. Accordingly, Alon does not speculate using derivative instruments. Alon has elected not to designate derivative instruments as cash flow hedges for financial accounting purposes. Therefore, changes in the fair value of the derivative instruments are included in income in the period of the change. There is not a significant credit risk on Alon’s derivative instruments which are transacted through counterparties meeting established collateral and credit criteria.
     Alon occasionally uses crude oil and refined product commodity derivative contracts to reduce financial exposure related to price changes on anticipated transactions. Crude oil and refined product forward contracts are used to facilitate the supply of crude oil to the refinery and the sale of refined products while managing price exposure.
     At June 30, 2006, Alon held net forward contracts for purchases of 25,000 barrels of refined products at an average price of $90.55 per barrel with a total contract fair market value (“FMV”) of $2,287. These forward contracts were not designated as hedges for accounting purposes. Accordingly, the contracts were recorded at FMV and an unrealized gain of $24 was recorded as an adjustment to net sales in the consolidated statements of operations for the three and six months ended June 30, 2006.
     At June 30, 2005, Alon held net forward contracts for sales of 5,000 barrels of refined products at an average price of $63.61 per barrel with a total contract FMV of $309. Alon also held net future commitments for sales of 140,000 barrels of refined products at an average price of $61.34 per barrel with a total contract FMV of $9,676. These derivatives were not designated as hedges for accounting purposes. Accordingly, the derivatives were recorded at FMV and a net unrealized loss of $1,079 was recorded as an adjustment to net sales in the consolidated statements of operations for the three and six months ended June 30, 2005.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
     In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, all commodity derivative contracts are recorded at fair value and any changes in fair value between periods are recorded in the consolidated statements of operations.
(6) Inventories
     Inventories for Alon are stated at the lower of cost or market. Cost is determined under the last-in, first-out (“LIFO”) method for crude oil, refined products, and blendstock inventories. Materials and supplies are stated at average cost. Cost for convenience store fuel inventories is determined under the first-in, first-out method (“FIFO”) and cost for the convenience store merchandise inventories is determined under the retail inventory method at FIFO.
     Carrying value of inventories consisted of the following:
                 
    June 30,     December 31,  
    2006     2005  
Crude oil, refined products and blendstocks
  $ 90,110     $ 57,822  
Materials and supplies
    6,069       5,880  
Store merchandise
    13,074       12,977  
Store fuel
    4,140       2,502  
 
           
Total inventories
  $ 113,393     $ 79,181  
 
           
Market values exceeded LIFO costs by $76,006 and $52,198 at June 30, 2006 and December 31, 2005, respectively.
(7) Property, Plant and Equipment
     Property, plant and equipment consisted of the following:
                 
    June 30,     December 31,  
    2006     2005  
Refining facilities
  $ 190,661     $ 171,346  
Pipelines and terminals
    10,836       27,237  
Retail
    65,876       63,486  
Other
    10,588       10,691  
 
           
Property, plant and equipment, gross
    277,961       272,760  
Less accumulated depreciation
    (66,028 )     (61,350 )
 
           
Property, plant and equipment, net
  $ 211,933     $ 211,410  
 
           
On March 1, 2006, Alon sold its Amdel and White Oil pipelines to an affiliate of Sunoco (see Note 2).

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
(8) Other Assets
     Other assets consisted of the following:
                 
    June 30,     December 31,  
    2006     2005  
Escrow deposits and costs relating to acquisitions *
  $ 31,868     $  
Deferred turnaround and chemical catalyst expenditures
    10,706       9,865  
Deferred debt issuance costs
    2,666       6,529  
Other
    11,903       11,108  
 
           
Total other assets
  $ 57,143     $ 27,502  
 
           
 
*   (see Note 15)
(9) Employee and Postretirement Benefits
     Alon has two defined benefit pension plans covering substantially all of its refining and marketing segment employees. Alon’s policy is to make contributions annually of not less than the minimum funding requirements under the Employee Retirement Income Security Act of 1974. Alon’s anticipated contributions to its pension plans during 2006 have not changed significantly from amounts previously disclosed in Alon’s consolidated financial statements for the year ended December 31, 2005. For the six months ended June 30, 2006 and 2005, Alon contributed $1,180 and $1,148, respectively, to its qualified pension plan.
     The components of net periodic benefit cost related to Alon’s benefit plans were as follows for the three and six months ended June 30, 2006 and 2005.
                                 
    For the Three Months Ended     For the Six Months Ended  
    June 30,     June 30,  
    2006     2005     2006     2005  
Components of net periodic benefit cost:
                               
Service cost
  $ 478     $ 347     $ 956     $ 693  
Interest cost
    608       478       1,216       957  
Expected return on plan assets
    (593 )     (414 )     (1,186 )     (827 )
Amortization of net loss
    83       166       166       332  
 
                       
Net periodic benefit cost
  $ 576     $ 577     $ 1,152     $ 1,155  
 
                       
(10) Long-Term Debt
     (a) Revolving Credit Facility
     On February 15, 2006, Alon entered into an amended revolving credit agreement with its lenders. The total commitment under the facility was increased from $141,600 to $240,000 and is available for, among other things, working capital, acquisitions and general corporate purposes. The initial size of the facility is $160,000 with options to increase the size to $240,000 if crude oil prices increase above certain levels or Alon increases its throughput capacity.
     Under this amended facility, the term has been extended through January 2010; existing borrowing costs and letter of credit fees have been reduced; most covenants have been eased; there are substantially no limitations on incurrence of debt, distribution of dividends or investment activities absent existing or resulting default; and the retail subsidiaries have been excluded from the facility. The facility is secured by cash, accounts receivables, inventories and related assets. All fixed assets previously securing the facility have been released.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
     No borrowings were outstanding under the revolving credit facility at June 30, 2006 and December 31, 2005. As of June 30, 2006 and December 31, 2005, there were $96,883 and $131,727, respectively, of outstanding letters of credit under the revolving credit facility.
     (b) Debt Repayment
     On January 19, 2006, Alon made a payment of approximately $103,900 in satisfaction of its outstanding borrowings under its secured term loan agreement, including applicable accrued interest and prepayment premiums, with available cash on hand. $100,000 represented a voluntary prepayment of the outstanding principal under the term loan agreement, approximately $3,000 represented a prepayment premium and $900 represented accrued and unpaid interest on the principal balance. The $3,000 prepayment premium and $3,894 of unamortized debt issuance costs are included as interest expense in Alon’s consolidated statements of operations for the six months ended June 30, 2006.
(11) Stock Based Compensation
     Alon has two employee incentive compensation plans, (i) the 2005 Incentive Compensation Plan and (ii) the 2000 Incentive Stock Compensation Plan.
     (a) 2005 Incentive Compensation Plan
     The 2005 Incentive Compensation Plan was approved by the Board of Directors in November 2005, and is a component of Alon’s overall executive incentive compensation program. The 2005 Incentive Compensation Plan permits the granting of awards in the form of options to purchase common stock, stock appreciation rights, restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses to Alon’s directors, officers and key employees. Other than the restricted stock grants discussed below, there have been no other awards granted under the 2005 Incentive Compensation Plan.
     In August 2005, Alon granted awards of 10,791 shares of restricted stock and in November 2005 Alon granted an award of 12,500 shares of restricted stock, in each case to certain directors, officers and key employees in connection with Alon’s IPO in July 2005. The participants were allowed to acquire shares at a discounted price of $12.00 per share with a grant date fair value of $16.00 per share for the August 2005 awards and $20.42 per share for the November 2005 award. In November 2005, Alon granted an award of 52,672 shares of restricted stock to certain directors, officers and key employees with a grant date fair value of $20.42 per share. Non-employee directors are awarded an annual grant of Alon’s common stock valued at $25,000. In August 2005, 2,774 shares of restricted stock were awarded to Alon’s non-employee directors with a grant date fair value of $18.03 per share. In May 2006, 2,253 shares of restricted stock were awarded to non-employee directors with a grant date fair value of $33.29 per share. Additionally, restricted shares of 5,667 were forfeited and 2,833 shares were accelerated to vest from the November 2005 issuance. All restricted shares granted under the Incentive Compensation Plan vest over a period of three years, assuming continued service at vesting.
     Compensation expense for the restricted stock grants amounted to $258 for the six months ended June 30, 2006. There is no material difference between intrinsic value under Opinion 25 and fair value under SFAS No. 123R for pro forma disclosure purposes.
                 
            Weighted-Average  
Nonvested Shares   Shares     Grant-Date Fair Value  
Nonvested at January 1, 2006
    78,737     $ 19.73  
Granted
    2,253       33.29  
Vested
    (2,833 )     20.42  
Forfeited
    (5,667 )     20.42  
 
           
Nonvested at June 30, 2006
    72,490     $ 20.07  
 
           

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
     As of June 30, 2006, there was $588 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the 2005 Incentive Compensation Plan. That cost is expected to be recognized over a weighted-average period of 2.4 years.
     (b) 2000 Incentive Stock Compensation Plan
     On August 1, 2000, Alon Assets, Inc. (“Alon Assets”) and Alon USA Operating, Inc. (“Alon Operating”), majority owned, fully consolidated subsidiaries of Alon, adopted an Incentive Stock Compensation Plan pursuant to which Alon’s Board of Directors may grant stock options to certain officers and members of executive management. The 2000 Incentive Stock Compensation Plan authorized grants of options to purchase up to 16,154 shares of common stock of Alon Assets and 6,066 shares of common stock of Alon Operating. All authorized options were granted in 2000 and there have been no additional options granted under this plan. All stock options have ten-year terms. The remaining contractual term for these options is approximately 4 years. The options are subject to accelerated vesting and become fully exercisable if Alon achieves certain financial performance and debt service criteria. Upon exercise, Alon will reimburse the option holder for the exercise price of the shares and under certain circumstances the related federal and state taxes payable as a result of such exercises (gross-up liability). This plan was closed to new participants subsequent to August 1, 2000, the initial grant date. Total compensation expense recognized under this plan was $1,162 and $191 for the six months ended June 30, 2006 and 2005, respectively.
     The following table summarizes the stock option activity for Alon Assets and Alon Operating for the six months ended June 30, 2006 and for the years ended December 31, 2005 and 2004:
                                 
    Alon Assets     Alon Operating  
            Weighted             Weighted  
    Number of     Average     Number of     Average  
    Options     Exercise     Options     Exercise  
    Outstanding     Price     Outstanding     Price  
Outstanding at January 1, 2004
    12,217     $ 100       4,587     $ 100  
Granted
                       
Exercised
    (1,212 )     100       (455 )     100  
Forfeited and expired
    (1,733 )     100       (650 )     100  
 
                       
Outstanding at December 31, 2004
    9,272       100       3,482       100  
Granted
                       
Exercised
    (1,212 )     100       (455 )     100  
 
                       
Outstanding at December 31, 2005
    8,060       100       3,027       100  
Granted
                       
Exercised
    (1,212 )     100       (455 )     100  
 
                       
Outstanding at June 30, 2006
    6,848     $ 100       2,572     $ 100  
 
                       
(12) Stockholders’ Equity
     (a) Stock Split
     On July 6, 2005, Alon (i) increased its authorized shares of common stock to 100,000,000 and (ii) effected a 33,600-for-1 share split of its common stock, resulting in 35,001,120 shares of common stock outstanding. The earnings per share information and all common stock information have been retroactively restated for the 2005 periods presented to reflect this stock split.
     (b) Common Stock Dividends
     On March 21, 2006, Alon paid a regular quarterly cash dividend of $0.04 per share and a special cash dividend of $0.37 per share on Alon’s common stock, to stockholders of record at the close of business on March 1, 2006. In connection with Alon’s cash dividend payment to stockholders on March 21, 2006, the minority interest owners of

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
Alon Assets and Alon Operating received an aggregate cash dividend of approximately $1,078. On June 14, 2006, Alon paid a regular quarterly cash dividend of $0.04 per share on Alon’s common stock, to stockholders of record at the close of business on June 1, 2006.
(13) Earnings Per Share
     Basic earnings per share are calculated as net income divided by the average number of shares of common stock outstanding. Diluted earnings per share include the dilutive effect of restricted shares using the treasury stock method.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2006     2005     2006     2005  
Net income
  $ 43,091     $ 27,482     $ 97,255     $ 49,918  
Average number of shares of common stock outstanding
    46,733       35,001       46,732       35,001  
Effect of dilutive restricted shares
    45             37        
 
                       
Average number of shares of common stock outstanding assuming dilution
    46,778       35,001       46,769       35,001  
 
                       
Earnings per share – basic
  $ .92     $ .79     $ 2.08     $ 1.43  
 
                       
Earnings per share – diluted
  $ .92     $ .79     $ 2.08     $ 1.43  
 
                       
(14) Commitments and Contingencies
     (a) Other Commitments
     In the normal course of business, Alon has long-term commitments to purchase services such as natural gas, electricity and water for use by its refinery, terminals, pipelines and retail locations. Alon is also party to various refined product and crude oil supply and exchange agreements. These agreements are short-term in nature or provide terms for cancellation.
     (b) Other Contingencies
     Alon is involved in various other claims and legal actions arising in the ordinary course of business. Alon believes the ultimate disposition of these matters will not have a material adverse effect on Alon’s financial position, results of operations or liquidity.
     (c) Environmental
     Alon is subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These laws and regulations regulate the discharge of materials into the environment and may require Alon to incur future obligations (i) to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites, (ii) to remediate or restore these sites, (iii) to compensate others for damage to property and natural resources, and (iv) for remediation and restoration costs. These possible obligations relate to sites owned by Alon and associated with past or present operations. Alon is currently participating in environmental investigations, assessments, and cleanups under these regulations at service stations, pipelines and terminals. In the future, Alon may be involved in additional environmental investigations, assessments and cleanups. The magnitude of future costs will depend on factors such as the unknown nature and contamination at many sites, the unknown timing, extent and method of the remedial actions which may be required, and the determination of Alon’s liability in proportion to other responsible parties. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
Substantially all amounts accrued are expected to be paid out over the next five to ten years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.
     Alon had accrued environmental remediation obligations of $4,161 ($1,750 current payable and $2,411 non-current liability) at June 30, 2006 and $4,736 ($1,750 current payable and $2,986 non-current liability) at December 31, 2005.
(15) Subsequent Events
     (a) Retail Convenience Stores Acquisition
     On July 3, 2006, Alon completed the purchase of 40 Good Time Stores in El Paso, Texas. The purchase price for the 40 stores acquired was approximately $26,000 in cash, including approximately $2,000 for inventory. Alon had previously announced its intention to purchase up to 55 stores; however, Alon purchased only 40 stores due to certain rights of first refusal and purchase options applicable to 15 of the 55 stores.
     In conjunction with the Good Time Stores acquisition, Alon, through a wholly-owned subsidiary, completed a draw down of $50,000 under a new credit agreement dated June 6, 2006. Of this $50,000, $19,800 was used to finance the acquisition and $30,200 was used to refinance existing debt.
     (b) Refinery Acquisitions
     Paramount Acquisition
     On April 28, 2006, Alon entered into an agreement to purchase Paramount Petroleum Corporation (“Paramount”), excluding certain real estate assets. The acquisition includes Paramount’s 54,000 bpd crude oil refinery located in Paramount, California; its 12,000 bpd heavy crude oil refinery in Portland, Oregon; seven asphalt terminals located in Seattle, Washington, Elk Grove and Mojave, California, Phoenix, Fredonia and Flagstaff, Arizona and Fernley, Nevada (50% interest); and Paramount’s 50% interest in Wright Asphalt Products Company, which specializes in patented tire rubber and modified asphalt products. In conjunction with the agreement to purchase Paramount, Alon had in escrow $25,000 as of June 30, 2006.
     On August 4, 2006, Alon completed the acquisition of Paramount with an effective date of July 31, 2006. Paramount’s assets on July 31, 2006 included approximately $8,000 in cash and approximately $50,000 of excess working capital. The purchase price for the outstanding capital stock of Paramount consisted of approximately $314,000 in cash (subject to post-closing adjustments) and the assumption of approximately $155,000 of funded debt, all of which was repaid simultaneously with the completion of the acquisition.
     Edgington Acquisition
     On April 28, 2006, Alon entered into an agreement to purchase the assets of Edgington Oil Company (“Edgington”), a heavy crude oil refining company located in Long Beach, California. The acquisition includes Edgington’s topping refinery with a nameplate capacity of approximately 40,000 bpd of crude oil. Total consideration for the acquisition consists of $52,000 in cash plus an amount to be determined for the value of certain inventories at closing. The transaction is expected to close during the third quarter of 2006, subject to regulatory approvals and other standard closing conditions. In conjunction with the agreement to purchase the assets of Edgington, Alon had in escrow $5,000 as of June 30, 2006.
     Federal Trade Commission Requests
     On June 30, 2006, the Federal Trade Commission (“FTC”) issued requests for additional information in connection with its review of Alon’s pending acquisitions of Paramount and Edgington. Requests of this nature,

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
referred to as “second requests”, are not unusual in connection with refinery transactions. The parties have been working closely with the FTC staff in responding to the second requests. On August 1, 2006, Alon received notice from the FTC that it had closed its investigation of Alon’s acquisition of Paramount. As of the date of this report, the FTC’s review of Alon’s pending acquisition of Edgington is ongoing.
     The Edgington purchase agreement becomes terminable at the option of either party on August 14, 2006. If FTC approval is not obtained prior to August 14, 2006, Alon has the option to extend the date on which the purchase agreement becomes terminable by either party until September 29, 2006 for an additional $5,000. Alon’s current intent is to pay the $5,000 if FTC approval is not received prior to August 14, 2006.
     Credit Suisse Credit Facility
     On June 22, 2006, Alon entered into a Credit Agreement with Credit Suisse (the “Credit Suisse Credit Facility”) with an aggregate available amount of $450,000. On August 4, 2006, Alon borrowed $400,000 as a term loan upon consummation of the acquisition of Paramount. Borrowings of an additional $50,000 are available until September 30, 2006 to finance the acquisition of Edgington. The loans under the Credit Suisse Credit Facility will mature on August 2, 2013.
     Declaration of Cash Dividends
     On August 7, 2006, Alon declared its regular quarterly cash dividend of $0.04 per share and a special cash dividend of $2.50 per share on Alon’s common stock, payable on September 14, 2006 to stockholders of record at the close of business on September 1, 2006 for a total payment of approximately $117,000. In connection with Alon’s cash dividend payment to stockholders on September 14, 2006, the minority interest owners of Alon Assets and Alon Operating would receive an aggregate cash dividend of approximately $6,600.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
     The following discussion of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and notes thereto included in Alon’s Annual Report on Form 10-K for the year ended December 31, 2005. “Alon,” “the Company,” “we” and “our” refer to Alon USA Energy, Inc. and its subsidiaries.
FORWARD-LOOKING STATEMENTS
     Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.
     Forward-looking statements reflect our current expectations regarding future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows.
     Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:
    changes in general economic conditions and capital markets;
 
    changes in the underlying demand for our products;
 
    the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;
 
    changes in the sweet/sour crude oil spread;
 
    actions of customers and competitors;
 
    changes in fuel and utility costs incurred by our facilities;
 
    disruptions due to equipment interruption, pipeline disruptions or failure at our or third-party facilities;
 
    the execution of planned capital projects;
 
    adverse changes in the credit ratings assigned to our trade credit and debt instruments;
 
    the effects of and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;
 
    operating hazards, natural disasters, casualty losses and other matters beyond our control; and
 
    the other factors discussed in our annual report on Form 10-K for the year ended December 31, 2005, under the caption “Risk Factors.”
     Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.

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Company Overview
     We are an independent refiner and marketer of petroleum products operating primarily in the Southwestern and South Central regions of the United States. Our business consists of two operating segments: (1) refining and marketing and (2) retail.
     Refining and Marketing Segment. We own and operate a sophisticated sour crude oil refinery in Big Spring, Texas, with a crude oil throughput capacity of 70,000 barrels per day (“bpd”). We refine and market petroleum products, including gasoline, diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum products, primarily in the Southwestern and South Central regions of the United States.
     We conduct the majority of our operations in West Texas, Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in this region as our physically integrated system because we supply our branded and unbranded distributors in this region with refined products produced at our Big Spring refinery and distributed through a network of product pipelines and terminals which we own or access through leases or long-term throughput agreements. We also operate in East Texas and Arkansas. We refer to our operations in this region as our non-integrated system because we supply our branded and unbranded distributors in this region with motor fuels obtained from third parties.
     Retail Segment. Alon’s retail segment operates 167 owned and leased 7-Eleven branded convenience store sites operating primarily in West Texas and New Mexico. These convenience stores typically offer various grades of gasoline, diesel fuel, general merchandise and food and beverage products to the general public under the 7-Eleven and FINA brand names.
     On July 3, 2006, Alon completed the purchase of 40 convenience stores in West Texas. Since that date, the retail segment has operated 207 owned and leased 7-Eleven branded convenience stores (see Third Quarter 2006 Developments).
Current 2006 Results and Third Quarter 2006 Developments
Current 2006 Results
     The second quarter of 2006 continued to reflect the positive refinery fundamentals experienced in the first quarter of 2006. These positive fundamentals, including strong refining margins and favorable differentials between West Texas Intermediate (“WTI”) and West Texas Sour (“WTS”) crude oil, resulted in significantly enhanced results of operations reported for the six month period ended June 30, 2006 compared to the six month period ended June 30, 2005. See “— Factors Affecting Comparability” for additional information. Results of our operations are further described below and under “— Results of Operations” and “— Liquidity and Capital Resources”:
  §   Net income for the three months ended June 30, 2006 was $43.1 million. Net income included $1.4 million of after-tax gain on disposition of assets (“after-tax gain”) associated with the pipeline and terminal assets contributed to Holly Energy Partners, L.P. (“HEP”). Net income excluding the after-tax gain was $41.7 million, a record quarter for Alon.
 
  §   In the second quarter of 2006, we successfully completed a scheduled turnaround at the Big Spring refinery that enables the refinery to meet the new ultra low sulfur diesel standard of 15 parts per million (“ppm”) for a total investment of $17.5 million. This new standard was promulgated by the U.S. Environmental Protection Agency (“EPA”) regulations related to the Clean Air Act. Refinery production was reduced during the second quarter of 2006, to an average refinery production of 55,720 bpd, while work was completed to meet this new standard. Even with work performed during the second quarter of 2006, refinery production for the six month period ended June 30, 2006 averaged 62,623 bpd compared to 59,399 bpd for the six month period ended June 30, 2005. This was possible as a result of the 8,000 bpd crude oil capacity expansion completed in the first quarter of 2005.
 
  §   Our refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. The average sweet/sour spread for the three months ended June 30, 2006 was $4.72 per barrel compared to $3.74 per barrel for the three months ended June 30, 2005. The

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      average sweet/sour spread for the first six months of 2006 was $5.63 per barrel compared to $4.41 per barrel for the first six months of 2005.
 
  §   Our average refinery operating margin increased $7.30 per barrel to $19.13 per barrel for the three months ended June 30, 2006, compared to the three months ended June 30, 2005. Our average refinery operating margin increased $3.69 per barrel to $15.02 per barrel for the first six months of 2006, compared to the first six months of 2005.
 
  §   Our capital expenditures and turnaround spending for the three months ended June 30, 2006 totaled approximately $20.1 million, of which approximately $9.3 million was related to the ultra low sulfur diesel turnaround and $1.6 million was spent on a chemical catalyst. Our capital expenditures and turnaround spending for the six months ended June 30, 2006 totaled approximately $26.1 million, of which approximately $12.0 million related to the ultra low sulfur diesel turnaround and $3.0 million was spent on a chemical catalyst.
     On January 19, 2006, we prepaid our $100 million term loan due January 14, 2009 with available cash on hand. This loan bore an interest rate of 10.6% per annum.
     On February 15, 2006, we entered into an amended revolving credit agreement which increased our borrowing capacity from $142 million to $160 million with an option to further increase our borrowing capacity up to $240 million if we increase our throughput capacity or experience prolonged increased crude oil prices. Pursuant to this amendment, we extended the term of our revolving facility to January 2010, reduced our borrowing costs and letter of credit fees and obtained greater flexibility by significantly relaxing covenant restrictions.
     On March 1, 2006, we sold our Amdel and White Oil pipelines, which had been inactive since December 2002, to an affiliate of Sunoco Logistics Partners L.P. (“Sunoco”) for total consideration of approximately $68 million. In conjunction with this transaction, we entered into a 10-year pipeline Throughput and Deficiency Agreement with Sunoco, with an option to extend the agreement by four additional 30-month periods. The Throughput and Deficiency Agreement will allow us to maintain our physically integrated system by retaining crude oil transportation rights in the pipelines from the Gulf Coast. Pursuant to the Throughput and Deficiency Agreement, we have agreed to ship, starting June 1, 2006, a minimum of 15,000 bpd in the pipelines during the term of the agreement.
     On March 21, 2006, Alon paid a regular quarterly cash dividend of $0.04 per share and a special cash dividend of $0.37 per share on Alon’s common stock, to stockholders of record at the close of business on March 1, 2006. In connection with Alon’s cash dividend payment to stockholders on March 21, 2006, the minority interest owners of Alon Assets and Alon Operating received an aggregate cash dividend of approximately $1.1 million. On June 14, 2006, Alon paid a regular quarterly cash dividend of $0.04 per share on Alon’s common stock, to stockholders of record at the close of business on June 1, 2006.
Third Quarter 2006 Developments
     Retail Convenience Stores Acquisition
     On July 3, 2006, Alon completed the purchase of 40 Good Time Stores in El Paso, Texas. The purchase price for the 40 stores acquired was approximately $26 million in cash, including approximately $2 million for inventory. Alon had previously announced its intention to purchase up to 55 stores; however, Alon purchased only 40 stores due to certain rights of first refusal and purchase options applicable to 15 of the 55 stores.
     In conjunction with the Good Time Stores acquisition, Alon, through a wholly-owned subsidiary, Southwest Convenience Stores, LLC, (“SCS”), completed a draw down of $50 million under a new credit agreement dated June 6, 2006. Of this $50 million, $19.8 million was used to finance the acquisition and $30.2 million was used to refinance existing debt.
     On June 6, 2006, SCS entered into a Credit Agreement (the “Credit Facility”) by and among SCS, as Borrower, and Wachovia Bank. Borrowings under the Credit Facility are available in the form of (i) a term loan commitment in an aggregate principal amount of $30 million maturing on June 30, 2016 and (ii) a revolving credit commitment

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(available in the form of revolving loans and letters of credit) in an aggregate principal amount of $20 million maturing on June 30, 2009. Revolving loans may be converted by SCS at any time to a term loan maturing on the tenth anniversary of conversion. At the request of SCS, the revolving credit commitment may be increased by an amount not to exceed $10 million. The aggregate amount of the lenders’ commitments under the entire Credit Facility may not exceed $60 million.
     Refinery Acquisitions
     Paramount Acquisition
     On April 28, 2006, Alon entered into an agreement to purchase Paramount Petroleum Corporation (“Paramount”), excluding certain real estate assets. The acquisition includes Paramount’s 54,000 bpd crude oil refinery located in Paramount, California; its 12,000 bpd heavy crude oil refinery in Portland, Oregon; seven asphalt terminals located in Seattle, Washington, Elk Grove and Mojave, California, Phoenix, Fredonia and Flagstaff, Arizona and Fernley, Nevada (50% interest); and Paramount’s 50% interest in Wright Asphalt Products Company, which specializes in patented tire rubber and modified asphalt products. In conjunction with the agreement to purchase Paramount, Alon had in escrow $25 million as of June 30, 2006.
     On August 4, 2006, Alon completed the acquisition of Paramount with an effective date of July 31, 2006. Paramount’s assets on July 31, 2006 included approximately $8 million in cash and approximately $50 million of excess working capital. The purchase price for the outstanding capital stock of Paramount consisted of approximately $314 million in cash (subject to post-closing adjustments) and the assumption of approximately $155 million of funded debt, all of which was repaid simultaneously with the completion of the acquisition.
     Edgington Acquisition
     On April 28, 2006, Alon entered into an agreement to purchase the assets of Edgington Oil Company (“Edgington”), a heavy crude oil refining company located in Long Beach, California. The acquisition includes Edgington’s topping refinery with a nameplate capacity of approximately 40,000 bpd of crude oil. Total consideration for the acquisition consists of $52 million in cash plus an amount to be determined for the value of certain inventories at closing. The transaction is expected to close during the third quarter of 2006, subject to regulatory approvals and other standard closing conditions. In conjunction with the agreement to purchase the assets of Edgington, Alon had in escrow $5 million as of June 30, 2006.
     Federal Trade Commission Requests
     On June 30, 2006, the Federal Trade Commission (“FTC”) issued requests for additional information in connection with its review of Alon’s pending acquisitions of Paramount and Edgington. Requests of this nature, referred to as “second requests”, are not unusual in connection with refinery transactions. The parties have been working closely with the FTC staff in responding to the second requests. On August 1, 2006, Alon received notice from the FTC that it had closed its investigation of Alon’s acquisition of Paramount. As of the date of this report, the FTC’s review of Alon’s pending acquisition of Edgington is ongoing.
     The Edgington purchase agreement becomes terminable at the option of either party on August 14, 2006. If FTC approval is not obtained prior to August 14, 2006, Alon has the option to extend the date on which the purchase agreement becomes terminable by either party until September 29, 2006 for an additional $5 million. Alon’s current intent is to pay the $5 million if FTC approval is not received prior to August 14, 2006.
     Credit Suisse Credit Facility
     On June 22, 2006, Alon entered into a Credit Agreement with Credit Suisse (the “Credit Suisse Credit Facility”) with an aggregate available amount of $450 million. On August 4, 2006, Alon borrowed $400 million as a term loan upon consummation of the acquisition of Paramount. Borrowings of an additional $50 million are available until September 30, 2006 to finance the acquisition of Edgington. The loans under the Credit Suisse Credit Facility will mature on August 2, 2013.

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     Declaration of Cash Dividends
     On August 7, 2006, Alon declared its regular quarterly cash dividend of $0.04 per share and a special cash dividend of $2.50 per share on Alon’s common stock, payable on September 14, 2006 to stockholders of record at the close of business on September 1, 2006 for a total payment of approximately $117 million. In connection with Alon’s cash dividend payment to stockholders on September 14, 2006, the minority interest owners of Alon Assets and Alon Operating would receive an aggregate cash dividend of approximately $6.6 million.
     Crude Pipeline Arrangement
     Alon and Centurion Pipeline L.P. (“Centurion”) have agreed to a 15-year arrangement pursuant to which Centurion will provide Alon with pipeline capacity and Alon will ship a minimum of 21,500 bpd of crude oil from Midland, Texas to Alon’s Big Spring refinery. The arrangement is expected to become effective during September 2006.
Major Influences on Results of Operations
Refining and Marketing
     Refining and Marketing Margins. Our earnings and cash flow from our refining and marketing segment are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire crude oil and other feedstocks and the price of the refined products we ultimately sell depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, and not necessarily fluctuations in those prices that affects our earnings.
     3/2/1 Crack Spread. In order to measure our operating performance, we compare our per barrel refinery operating margin to certain industry benchmarks, specifically the Gulf Coast and Group III, or mid-continent, 3/2/1 crack spreads. A 3/2/1 crack spread in a given region is calculated assuming that three barrels of a benchmark crude oil are converted, or cracked, into two barrels of gasoline and one barrel of diesel. We calculate our per barrel refinery operating margin by dividing the margin between net sales (exclusive of sale of sulfur credits) and cost of sales attributable to our refining and marketing segment, exclusive of net sales and cost of sales relating to our non-integrated system, by our Big Spring refinery’s throughput volumes.
     Sweet/Sour Spread. Our refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. We measure the cost advantage of refining sour crude oil by calculating the difference between the values of WTI crude oil less the value of WTS crude oil. We refer to this differential as the sweet/sour spread. A widening of the sweet/sour spread can favorably influence our refinery operating margin.
     Operating Costs. The results of operations from our refining and marketing segment are also significantly affected by our Big Spring refinery’s operating costs, particularly the cost of natural gas used for fuel and the cost of electricity. Natural gas prices have historically been volatile. For example, natural gas prices ranged between $5.89 and $10.63 per MMBTU in the first six months of 2006. Over the first six months of 2005, natural gas prices ranged between $5.79 and $7.75 per MMBTU. Typically, electricity prices fluctuate with natural gas prices.
     Seasonality. Demand for gasoline and asphalt products is generally higher during summer months than during winter months due to seasonal increases in highway traffic and road construction work. As a result, the operating results for our refining and marketing segment for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters. The effects of seasonal demand for gasoline and asphalt are partially offset by seasonality in demand for diesel, which in our region is generally higher in winter months as east-west trucking traffic moves south to avoid winter conditions on northern routes.
     Safety and Reliability. Safety, reliability and the environmental performance of our refinery operations are critical to our financial performance. The financial impact of planned downtime, such as a turnaround or major

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maintenance project, is mitigated through a diligent planning process that considers product availability, margin environment and the availability of resources to perform the required maintenance.
     Inventory. The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Because crude oil and refined products are essentially commodities, we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value under the LIFO inventory valuation methodology, price fluctuations generally have little effect on our financial results.
Retail
     Our earnings and cash flows from our retail segment are primarily affected by the sales and margins of retail merchandise and the sales volumes and margins of motor fuels at our convenience stores. The gross margin of our retail merchandise is retail merchandise sales less the delivered cost of the retail merchandise, net of vendor discounts, measured as a percentage of total retail merchandise sales. Our retail merchandise sales are driven by convenience, branding and competitive pricing. Motor fuel margin is sales less the delivered cost of fuel and motor fuel taxes, measured on cents per gallon, or cpg, basis. Our motor fuel margins are driven by local supply, demand and competitor pricing. Our retail sales are seasonal and peak in the second and third quarters of the year, while the first and fourth quarters usually experience lower overall sales.
Factors Affecting Comparability
     Our financial condition and operating results over the three and six months ended June 30, 2006 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.
     Refinery Turnaround. In the second quarter of 2006, we successfully completed a scheduled turnaround at the Big Spring refinery that enables the refinery to meet the new ultra low sulfur diesel standard of 15 parts per million (“ppm”) for a total investment of $17.5 million. The average refinery production was reduced during the second quarter of 2006 to 55,720 bpd, while work was completed to meet this new standard. The average refinery production during the second quarter of 2005 was 71,602 bpd.
     Increased Crude Oil Throughput Capacity. In the first quarter of 2005, we successfully completed a major turnaround at our Big Spring refinery. In connection with this turnaround, we expanded our crude oil throughput capacity from 62,000 bpd to 70,000 bpd. Our expanded crude oil processing capability enables us to spread our fixed costs over a higher production base and, consequently, should lower our per barrel direct operating expense. In addition, the increased throughput capacity resulted in increased production and higher sales volumes, which should affect the comparability of our future operating results to periods prior to the expansion. Our average refinery production was 62,623 bpd for the first six months of 2006, reflecting effects of the crude oil throughput expansion completed in the first quarter of 2005. Average refinery production was 59,399 bpd for the first six months of 2005.
     Amdel and White Oil Pipeline Transaction. The sale of assets in connection with the Amdel and White Oil pipeline transaction on March 1, 2006, reduced property, plant and equipment, net of accumulated depreciation by approximately $15.2 million.
     In connection with the Amdel and White Oil transaction we recognized pre-tax gain of $52.5 million in the six months ended June 30, 2006. Gain on disposition of assets for the six months ended June 30, 2005 included the $26.7 million initial pre-tax gain and four month’s recognition of deferred gain recorded in connection with the contribution of certain pipeline and terminal assets to HEP.

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Results of Operations
     Net Sales. Net sales consist primarily of sales of refined petroleum products through our refining and marketing segment and sales of merchandise, including food products and motor fuels, through our retail segment. For the refining and marketing segment, net sales consist of gross sales, net of customer rebates, discounts and excise taxes. Net sales for our refining and marketing segment include intersegment sales to our retail segment, which are eliminated through consolidation of our financial statements. Retail net sales consist of gross merchandise sales, less rebates, commissions and discounts, and gross fuel sales, including motor fuel taxes. For our petroleum products, net sales are mainly affected by refined product prices and volume changes caused by operations. Our merchandise sales are affected primarily by competition and seasonal influences.
     Cost of Sales. Refining and marketing cost of sales includes crude oil and other raw materials, inclusive of transportation costs. Retail cost of sales includes cost of sales for motor fuels and for merchandise. Motor fuel cost of sales represents the net cost of purchased fuel, including transportation costs and associated motor fuel taxes. Merchandise cost of sales includes the delivered cost of merchandise purchases, net of merchandise rebates and commissions.
     Direct Operating Expenses. Direct operating expenses, all of which relate to our refining and marketing segment, include costs associated with the actual operations of our refinery, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs. Environmental compliance costs, including monitoring and routine maintenance, are expensed as incurred. All operating costs associated with our crude oil and product pipelines are considered to be transportation costs and are reflected as cost of sales.
     Selling, General and Administrative Expenses. Selling, general and administrative, or SG&A, expenses consist primarily of costs relating to the operations of our convenience stores, including labor, utilities, maintenance and retail corporate overhead costs. Refining and marketing segment corporate overhead and marketing expenses are also included in SG&A expenses.

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ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED
     Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for Alon and our two operating segments for the three and six months ended June 30, 2006 and 2005. The summary financial data for our two operating segments does not include certain SG&A expenses and depreciation and amortization related to our corporate headquarters. The following data should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q.
                                 
    For the Three Months Ended     For the Six Months Ended  
    June 30,     June 30,  
    2006     2005     2006     2005  
    (dollars in thousands, except per share data)  
STATEMENT OF OPERATIONS DATA:
                               
Net sales
  $ 672,262     $ 590,366     $ 1,256,963     $ 998,340  
Operating costs and expenses:
                               
Cost of sales
    556,689       498,047       1,054,516       849,601  
Direct operating expenses
    22,164       20,373       45,435       38,709  
Selling, general and administrative expenses (1)
    20,354       18,983       37,807       35,648  
Depreciation and amortization (2)
    5,408       5,018       10,931       9,852  
 
                       
Total operating costs and expenses
    604,615       542,421       1,148,689       933,810  
 
                       
Gain on disposition of assets (3)
    2,279       1,530       57,665       29,223  
 
                       
Operating income
    69,926       49,475       165,939       93,753  
Interest expense (4)
    (1,349 )     (4,745 )     (10,396 )     (9,752 )
Equity earnings in HEP
    176       277       753       412  
Other income, net
    2,174       830       4,101       1,080  
 
                       
Income before income tax expense and minority interest in income of subsidiaries
    70,927       45,837       160,397       85,493  
Income tax expense
    25,607       16,354       58,133       32,009  
 
                       
Income before minority interest in income of subsidiaries
    45,320       29,483       102,264       53,484  
Minority interest in income of subsidiaries
    2,229       2,001       5,009       3,566  
 
                       
Net income
  $ 43,091     $ 27,482     $ 97,255     $ 49,918  
 
                       
 
                               
Earnings per share, basic and diluted (5)
  $ .92     $ .79     $ 2.08     $ 1.43  
 
                       
 
                               
Weighted average shares outstanding (5)
    46,733,009       35,001,120       46,732,064       35,001,120  
 
                       
Cash dividends per share
  $ .04     $     $ .45     $  
 
                       
 
                               
CASH FLOW DATA:
                               
Net cash provided by (used in):
                               
Operating activities
  $ 5,013     $ 65,825     $ (4,710 )   $ 49,388  
Investing activities
    66,221       (5,656 )     195,608       88,147  
Financing activities
    (3,710 )     (612 )     (123,370 )     (32,346 )
 
                               
OTHER DATA:
                               
Adjusted EBITDA (6)
  $ 75,405     $ 54,070     $ 124,059     $ 75,874  
Capital expenditures (7)
    18,527     5,361     23,165     16,459
Capital expenditures for turnaround and chemical catalyst
    1,622     399     2,925     10,781
 
                               
 
                  June 30,   December 31,
 
                    2006       2005  
 
                           
BALANCE SHEET DATA (end of period):
                               
Cash, cash equivalents and short-term investments
                  $ 204,348     $ 322,140  
Working capital
                    248,059       275,996  
Total assets
                    746,601       758,780  
Total debt
                    31,163       132,390  
Total stockholders’ equity
                    355,941       279,493  

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(1)   Includes corporate headquarters selling, general and administrative expenses of $95 and $128 for the three months ended June 30, 2006 and 2005, respectively, and $222 and $256 for the six months ended June 30, 2006 and 2005, respectively.
 
(2)   Includes corporate depreciation and amortization of $497 and $478 for the three months ended June 30, 2006 and 2005, respectively, and $1,021 and $949 for the six months ended June 30, 2006 and 2005, respectively.
 
(3)   Gain on disposition of assets reported in the six months ended June 30, 2006, reflects the $52.5 million pre-tax gain on disposition of assets, recorded in connection with the Amdel and White Oil transaction and the recognition of $5.2 million deferred gain recorded in connection with the HEP transaction. Gain on disposition of assets reported in the six months ended June 30, 2005, reflects the $26.7 million initial pre-tax gain and $2.5 million deferred gain recorded in connection with the HEP transaction.
 
(4)   Interest expense for the six months ended June 30, 2006, includes $3.0 million prepayment premium and $3.9 million of unamortized debt issuance costs written off as a result of the prepayment of the $100 million term loan in January 2006.
 
(5)   Weighted average common shares outstanding and earnings per common share amounts for the three and six months ended June 30, 2005 have been restated to reflect the effect of the 33,600-for-one split of our common stock which was effective on July 6, 2005.
 
(6)   EBITDA represents earnings before minority interest in income of subsidiaries, income tax expense, interest expense, depreciation and amortization. Adjusted EBITDA represents EBITDA, exclusive of gain on disposition of assets. EBITDA and Adjusted EBITDA are not recognized measurements under GAAP; however, the amounts included in EBITDA and Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of minority interest in income of subsidiaries, income tax expense, interest expense, gain on disposition of assets and the accounting effects of capital expenditures and acquisitions, items which may vary for different companies for reasons unrelated to overall operating performance. EBITDA is the basis for calculating selected financial ratios as required in the debt covenants in our revolving credit agreement. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Cash Position and Indebtedness.”
 
    Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:
    Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
 
    Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;
 
    Adjusted EBITDA does not reflect the prior claim that minority stockholders have on the income generated by non-wholly-owned subsidiaries;
 
    Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and
 
    Our calculation of Adjusted EBITDA may differ from the EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.
Because of these limitations, EBITDA and Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only supplementally.

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     The following table reconciles net income to Adjusted EBITDA for the three and six months ended June 30, 2006 and 2005, respectively:
                                 
    For the Three Months Ended     For the Six Months Ended  
    June 30,     June 30,  
    (dollars in thousands)  
    2006     2005     2006     2005  
Net income
  $ 43,091     $ 27,482     $ 97,255     $ 49,918  
Minority interest in income of subsidiaries
    2,229       2,001       5,009       3,566  
Income tax expense
    25,607       16,354       58,133       32,009  
Interest expense
    1,349       4,745       10,396       9,752  
Depreciation and amortization
    5,408       5,018       10,931       9,852  
 
                       
EBITDA
    77,684       55,600       181,724       105,097  
Gain on disposition of assets
    (2,279 )     (1,530 )     (57,665 )     (29,223 )
 
                       
Adjusted EBITDA
  $ 75,405     $ 54,070     $ 124,059     $ 75,874  
 
                       
(7)   Includes corporate capital expenditures of $57 and $16 for the three months ended June 30, 2006 and 2005, respectively, and $76 and $160 for the six months ended June 30, 2006 and 2005, respectively, which are not included in the capital expenditures of our other two operating segments.

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REFINING AND MARKETING SEGMENT
                                 
    For the Three Months Ended     For the Six Months Ended  
    June 30,     June 30,  
    2006     2005     2006     2005  
    (dollars in thousands, except per barrel data and pricing statistics)  
STATEMENTS OF OPERATIONS DATA:
                               
Net sales (1) (2)
  $ 624,531     $ 542,774     $ 1,168,007     $ 909,708  
Operating costs and expenses:
                               
Cost of sales (2)
    524,317       464,656       994,567       788,170  
Direct operating expenses
    22,164       20,373       45,435       38,709  
Selling, general and administrative expenses
    7,229       6,407       12,105       11,085  
Depreciation and amortization
    3,801       3,489       7,646       6,800  
 
                       
Total operating costs and expenses
    557,511       494,925       1,059,753       844,764  
 
                       
Gain on disposition of assets (3)
    2,279       1,530       57,665       29,223  
 
                       
Operating income
  $ 69,299     $ 49,379     $ 165,919     $ 94,167  
 
                       
 
                               
KEY OPERATING STATISTICS:
                               
Total sales volume (bpd)
    80,419       95,217       82,881       83,799  
Non-integrated marketing sales volume (bpd) (4)
    19,411       20,543       19,379       20,304  
Non-integrated marketing margin (per barrel sales volume) (4)
  $ (.67 )   $ .26     $ (.61 )   $ (.32 )
Per barrel of throughput:
                               
Refinery operating margin (5)
  $ 19.13     $ 11.83     $ 15.02     $ 11.33  
Refinery direct operating expenses
    4.32       3.10       3.96       3.57  
Capital expenditures
    16,519       4,324       20,915       14,269  
Capital expenditures for turnaround and chemical catalyst
    1,622       399       2,925       10,781  
 
                               
PRICING STATISTICS:
                               
WTI crude oil (per barrel)
  $ 70.41     $ 53.00     $ 66.89     $ 51.39  
WTS crude oil (per barrel)
    65.69       49.26       61.26       46.98  
Crack spreads (3/2/1) (per barrel):
                               
Gulf Coast
  $ 18.22     $ 10.18     $ 13.98     $ 8.44  
Group III
    19.44       11.62       14.58       9.80  
Crude oil differentials (per barrel):
                               
WTI less WTS
  $ 4.72     $ 3.74     $ 5.63     $ 4.41  
Product price (per gallon):
                               
Gulf Coast unleaded gasoline
    210.7 ¢     147.8 ¢     190.6 ¢     140.2 ¢
Gulf Coast low-sulfur diesel
    211.6       155.8       196.5       147.0  
Group III unleaded gasoline
    212.7       151.3       191.8       143.7  
Group III low-sulfur diesel
    216.5       158.9       198.4       149.8  
Natural gas (per MMBTU)
  $ 6.65     $ 6.95     $ 6.11     $ 6.73  

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THROUGHPUT AND YIELD DATA:
                                                                 
    For the Three Months Ended   For the Six Months Ended
    June 30,   June 30,
    2006   2005   2006   2005
    bpd   %   bpd   %   bpd   %   bpd   %
Refinery crude throughput:
                                                               
Sour crude
    49,040       93.9       61,572       89.7       55,842       94.6       51,391       91.2  
Sweet crude
    3,186       6.1       7,033       10.3       3,188       5.4       4,943       8.8  
 
                                                               
Total crude throughput
    52,226       100.0       68,605       100.0       59,030       100.0       56,334       100.0  
 
                                                               
Blendstocks
    4,109               3,502               4,362               3,511          
 
                                                               
Total refinery throughput (6)
    56,335               72,107               63,392               59,845          
 
                                                               
Refinery production (7):
                                                               
Gasoline
    24,250       43.5       31,340       43.8       28,524       45.5       26,478       44.6  
Diesel/jet
    16,361       29.4       25,867       36.1       20,011       32.0       20,579       34.6  
Asphalt
    5,715       10.3       6,374       8.9       6,077       9.7       5,341       9.0  
Petrochemicals
    3,759       6.7       5,145       7.2       4,011       6.4       4,386       7.4  
Other
    5,635       10.1       2,876       4.0       4,000       6.4       2,615       4.4  
 
                                                               
Total refinery production
    55,720       100.0       71,602       100.0       62,623       100.0       59,399       100.0  
 
                                                               
 
                                                               
Refinery Utilization (8)
            85.7 %             98.0 %             90.2 %             94.2 %
 
(1)   Net sales include intersegment sales to our retail segment at prices which approximate market price. These intersegment sales are eliminated through consolidation of our financial statements. Net sales for the three and six months ended June 30, 2006, includes $3.3 million for the sale of sulfur credits.
 
(2)   Our buy/sell arrangements involve linked purchases and sales related to refined product contracts entered into to address location or grade requirements. As of January 1, 2006, such buy/sell transactions are included on a net basis in sales in the consolidated statements of operations and profits are recognized when the exchanged product is sold. Prior to January 1, 2006, the results of buy/sell transactions were recorded separately in sales and cost of sales in the consolidated statements of operations.
 
(3)   Gain on disposition of assets reported in the six months ended June 30, 2006, reflects the $52.5 million pre-tax gain on disposition of assets, recorded in connection with the Amdel and White Oil transaction and the recognition of $5.2 million deferred gain recorded in connection with the HEP transaction. Gain on disposition of assets reported in the six months ended June 30, 2005, reflects the $26.7 million initial pre-tax gain and $2.5 million of deferred gain recorded in connection with the HEP transaction.
 
(4)   The non-integrated marketing sales volume represents refined products sales to our wholesale marketing customers located in our non-integrated region. The refined products we sell in this region are obtained from third-party suppliers. The non-integrated marketing margin represents the margin between the net sales and cost of sales attributable to our non-integrated refined products sales volume, expressed on a per barrel basis.
 
(5)   Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales (exclusive of sale of sulfur credits) and cost of sales attributable to our refining and marketing segment, exclusive of net sales and cost of sales relating to our non-integrated system, by our Big Spring refinery’s throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margin to these crack spreads to assess our operating performance relative to other participants in our industry.
 
(6)   Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.
 
(7)   Total refinery production represents the barrels per day of various finished products produced from processing crude and other refinery feedstocks through the crude units and other conversion units at the refinery.
 
(8)   Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.

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RETAIL SEGMENT   For the Three Months Ended     For the Six Months Ended  
    June 30,     June 30,  
    2006     2005     2006     2005  
            (dollars in thousands, except per gallon data)          
STATEMENTS OF OPERATIONS DATA:
                               
Net sales
  $ 86,815     $ 87,184     $ 159,430     $ 161,080  
Operating costs and expenses:
                               
Cost of sales (1)
    71,456       72,983       130,423       133,879  
Selling, general and administrative expenses
    13,030       12,448       25,480       24,307  
Depreciation and amortization
    1,110       1,051       2,264       2,103  
 
                       
Total operating costs and expenses
    85,596       86,482       158,167       160,289  
 
                       
Operating income
  $ 1,219     $ 702     $ 1,263     $ 791  
 
                       
 
                               
KEY OPERATING STATISTICS:
                               
Number of stores (end of period)
    167       167       167       167  
Fuel sales (thousands of gallons)
    17,450       24,678       34,583       48,066  
Fuel sales (thousands of gallons per site per month)
    35       49       35       48  
Fuel margin (cents per gallon) (2)
    17.4 ¢     10.3 ¢     17.3 ¢     11.5 ¢
Fuel sales price (dollars per gallon) (3)
  $ 2.72     $ 2.12     $ 2.56     $ 2.00  
Merchandise sales
  $ 36,968     $ 34,860     $ 69,382     $ 64,855  
Merchandise sales (per site per month)
    74       70       69       65  
Merchandise margin (4)
    31.3 %     33.5 %     32.2 %     33.4 %
Capital expenditures
  $ 1,951     $ 1,021     $ 2,174     $ 2,030  
 
(1)   Cost of sales includes intersegment purchases of motor fuels from our refining and marketing segment at prices which approximate market prices. These intersegment purchases are eliminated through consolidation of our financial statements.
 
(2)   Fuel margin represents the difference between motor fuel sales revenue and the net cost of purchased motor fuel, including transportation costs and associated motor fuel taxes, expressed on a cents per gallon basis. Motor fuel margins are frequently used in the retail industry to measure operating results related to motor fuel sales.
 
(3)   Fuel sales price per gallon represents the average sales price for motor fuels sold through our retail segment.
 
(4)   Merchandise margin represents the difference between merchandise sales revenue and the delivered cost of merchandise purchases, net of rebates and commissions, expressed as a percentage of merchandise sales revenues. Merchandise margins, also referred to as in-store margins, are commonly used in the retail industry to measure in-store, or non-fuel, operating results.
Three Months Ended June 30, 2006 Compared to the Three Months Ended June 30, 2005
Net Sales
     Consolidated. Net sales for the three months ended June 30, 2006 were $672.3 million, compared to $590.4 million for the three months ended June 30, 2005, an increase of $81.9 million or 13.9%. This increase was primarily due to significantly higher than average refined product prices over the comparable period in 2005. The continued strength of refined product prices for the second quarter of 2006 was primarily due to increased foreign and U.S. demand. Partially offsetting the effect of the increase of refined product prices on net sales was lower sales volume due primarily to reduced refinery production during a planned turnaround to bring the ultra low sulfur diesel unit online during the second quarter of 2006.
     Refining and Marketing Segment. Net sales for our refining and marketing segment were $624.5 million for the three months ended June 30, 2006, compared to $542.8 million for the three months ended June 30, 2005, an increase of $81.7 million or 15.0%. This increase was primarily due to significantly higher refined product prices. The average price of Gulf Coast unleaded gasoline for the second quarter of 2006 increased 62.9 cents per gallon

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(“cpg”) to 210.7 cpg, compared to 147.8 cpg in the second quarter of 2005, an increase of 42.5%. The average Gulf Coast low-sulfur diesel price increased by approximately 55.8 cpg to 211.6 cpg in the second quarter of 2006 as compared to 155.8 cpg in the second quarter of 2005, an increase of 35.8%. In addition, net sales for the second quarter of 2006 included $3.3 million for sales of excess sulfur credits related to federal gasoline sulfur regulations. The increase in sales was partially offset by reduced refinery production for the second quarter which decreased our sales volume. Our average refinery production decreased by 15,882 bpd to 55,720 bpd in the second quarter of 2006 compared to 71,602 bpd during the second quarter of 2005. The decrease in refinery production was due to a scheduled turnaround to bring the ultra low sulfur diesel unit online during the second quarter of 2006.
     Retail Segment. Net sales for our retail segment were $86.8 million for the three months ended June 30, 2006 compared to $87.2 million for the three months ended June 30, 2005, a decrease of $0.4 million or 0.5%. This decrease was primarily attributable to lower fuel sales volume as a result of competition from our high volume competitors.
Cost of Sales
     Consolidated. Cost of sales was $556.7 million for the three months ended June 30, 2006, compared to $498.0 million for the three months ended June 30, 2005, an increase of $58.7 million or 11.8%. The increase was due to significantly higher crude oil costs during the second quarter of 2006 as compared to the second quarter of 2005.
     Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $524.3 million for the three months ended June 30, 2006, compared to $464.7 million for the three months ended June 30, 2005, an increase of $59.6 million or 12.8%. This increase was primarily due to the increase in crude oil prices during the second quarter of 2006 compared to the second quarter of 2005. The average price per barrel of WTS crude oil for the second quarter of 2006 increased $16.43 per barrel to $65.69 per barrel, compared to $49.26 per barrel for the second quarter of 2005, an increase of 33.4%.
     Retail Segment. Cost of sales for our retail segment was $71.5 million for the three months ended June 30, 2006, compared to $73.0 million for the three months ended June 30, 2005, a decrease of $1.5 million or 2.1%. This decrease was primarily due to lower fuel sales.
Direct Operating Expenses
     Direct operating expenses were $22.2 million for the three months ended June 30, 2006, compared to $20.4 million for the three months ended June 30, 2005, an increase of $1.8 million or 8.8%. This increase was primarily attributable to maintenance work performed during the ultra low sulfur diesel turnaround in the second quarter of 2006.
Selling, General and Administrative Expenses
     Consolidated. SG&A expenses for the three months ended June 30, 2006 were $20.4 million, compared to $19.0 million for the three months ended June 30, 2005, an increase of $1.4 million or 7.4%.
     Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the three months ended June 30, 2006 were $7.2 million, compared to $6.4 million for the three-month period ended June 30, 2005, an increase of $0.8 million or 12.5%. This increase resulted from higher corporate costs associated with becoming a public company which significantly increased audit expenditures and added costs associated with becoming Sarbanes Oxley compliant. These costs were partially offset by lower selling and advertising expenses.
     Retail Segment. SG&A expenses for our retail segment for the three months ended June 30, 2006 were $13.0 million, compared to $12.4 million for the three months ended June 30, 2005, an increase of $0.6 million or 4.8%. This increase was primarily attributable to higher maintenance and credit card costs.
Depreciation and Amortization
     Depreciation and amortization for the three months ended June 30, 2006 was $5.4 million, compared to $5.0 million for the three months ended June 30, 2005. This increase was primarily attributable to the completion of the

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various capital projects in late 2005 and the first six months of 2006. Partially offsetting this increase was the reduction in depreciation due to the disposition of assets in the HEP and Amdel and White Oil transactions.
Operating Income
     Consolidated. Operating income for the three months ended June 30, 2006 was $69.9 million, compared to $49.5 million operating income for the three months ended June 30, 2005, an increase of $20.4 million or 41.2%. This increase was primarily attributable to higher operating income in our refining and marketing segment.
     Refining and Marketing Segment. Operating income for our refining and marketing segment for the three months ended June 30, 2006 was $69.3 million compared to operating income of $49.4 million for the three months ended June 30, 2005, an increase of $19.9 million or 40.3%. Our refinery operating margin for the second quarter of 2006 increased $7.30 per barrel to $19.13 per barrel, compared to $11.83 per barrel in the second quarter of 2005. This increase was attributable, in part, to higher differentials between refined product prices and crude oil prices resulting from continued concern over adequate refinery capacity to meet demand and supply. Also contributing to the higher refinery margins were the supply constraints associated with the logistics of the introduction of new reformulated fuels in the first quarter of 2006. The Gulf Coast 3/2/1 crack spread increased by 79.0% to an average of $18.22 per barrel in the second quarter of 2006 compared to an average of $10.18 per barrel in the second quarter of 2005. In addition, our refinery operating margins benefited from a widening of the sweet/sour crude oil spread. The average sweet/sour crude oil spread increased $0.98 per barrel to $4.72 per barrel for the second quarter of 2006 compared to the average sweet/sour crude oil spread of $3.74 per barrel for the second quarter of 2005, an increase of 26.2%.
     Retail Segment. Operating income for our retail segment was $1.2 million for the three months ended June 30, 2006, compared to $0.7 million, an increase of $0.5 million. This increase was primarily due to the higher fuel sales margins.
Interest Expense
     Interest expense was $1.3 million for the three months ended June 30, 2006, compared to $4.7 million for the three months ended June 30, 2005, a decrease of $3.4 million or 72.3%. This decrease was primarily attributable to payment of the $100 million term loan in January 2006.
Income Tax Expense
     Income tax expense was $25.6 million for the three months ended June 30, 2006, compared to $16.4 million for the three months ended June 30, 2005, an increase of $9.2 million. This increase resulted from our higher taxable income in the second quarter of 2006 compared to the second quarter of 2005. Our effective tax rate was 36.1% for the second quarter of 2006, compared to an effective tax rate of 35.7% for the second quarter of 2005.
Minority Interest In Income Of Subsidiaries
     Minority interest in income of subsidiaries represents the proportional share of net income related to non-voting common stock owned by minority stockholders in two of our subsidiaries, Alon Assets and Alon Operating. Minority interest in income of subsidiaries was $2.2 million for the three months ended June 30, 2006, compared to $2.0 million for the three months ended June 30, 2005, an increase of $0.2 million. This increase was attributable to our increased after-tax income in the quarter as a result of the factors discussed above.
Net Income
     Net income was $43.1 million for the three months ended June 30, 2006, compared to $27.5 million for the three months ended June 30, 2005, an increase of $15.6 million or 56.7%. This increase was attributable to the factors discussed above.

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Six Months Ended June 30, 2006 Compared to the Six Months Ended June 30, 2005
Net Sales
     Consolidated. Net sales for the six months ended June 30, 2006 were $1,257.0 million, compared to $998.3 million for the six months ended June 30, 2005, an increase of $258.7 million or 25.9%. This increase was primarily due to higher than average refined product prices over the comparable period in 2005.
     Refining and Marketing Segment. Net sales for our refining and marketing segment were $1,168.0 million for the six months ended June 30, 2006, compared to $909.7 million for the six months ended June 30, 2005, an increase of $258.3 million or 28.4%. This increase was primarily due to significantly higher refined product prices. The increase in refined product prices that we experienced was similar to the price increases experienced in the Gulf Coast markets. The average price of Gulf Coast unleaded gasoline for the first six months of 2006 increased 50.4 cents per gallon (“cpg”) to 190.6 cpg, compared to 140.2 cpg in the first six months of 2005, an increase of 35.9%. The average Gulf Coast low-sulfur diesel price increased by approximately 49.5 cpg to 196.5 cpg in the first six months of 2006 as compared to 147.0 cpg in the first six months of 2005, an increase of 33.7%.
     Retail Segment. Net sales for our retail segment were $159.4 million for the six months ended June 30, 2006 compared to $161.1 million for the six months ended June 30, 2005, a decrease of $1.7 million or 1.1%. This decrease was primarily attributable to lower fuel sales volumes as a result of competition from our high volume competitors. Fuel sales volume decreased by 13.5 million gallons, or 28.1% to 34.6 million gallons for the six months ended June 30, 2006 compared to 48.1 million gallons for the six months ended June 30, 2005. Partially offsetting this decrease were the increases in fuel prices and in-store merchandise sales in the first six months of 2006, compared to the first six months of 2005. Average retail fuel prices were $2.56 per gallon for the first six months of 2006, compared to average retail fuel prices of $2.00 per gallon for the first six months of 2005. Merchandise sales increased by $4.5 million, or 6.9% to $69.4 million for the first six months of 2006, compared to $64.9 million for the first six months of 2005.
Cost of Sales
     Consolidated. Cost of sales was $1,054.5 million for the six months ended June 30, 2006, compared to $849.6 million for the six months ended June 30, 2005, an increase of $204.9 million or 24.1%. This increase was primarily from significantly higher crude oil prices and an increase in refinery production during the first six months of 2006.
     Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $994.6 million for the six months ended June 30, 2006, compared to $788.2 million for the six months ended June 30, 2005, an increase of $206.4 million or 26.2%. This increase was primarily due to higher crude oil prices and an increase in refinery production. The average price per barrel of WTS crude oil for the first six months of 2006 increased $14.28 per barrel to $61.26 per barrel, compared to $46.98 per barrel for the first six months of 2005, an increase of 30.4%. Average refinery production increased to 62,623 bpd, or 5.4% for the first six months of 2006, compared to an average refinery production of 59,399 bpd for the first six months of 2005.
     Retail Segment. Cost of sales for our retail segment was $130.4 million for the six months ended June 30, 2006, compared to $133.9 million for the six months ended June 30, 2005, a decrease of $3.5 million or 2.6%. This decrease was primarily due to lower fuel sales volume as a result of increased competition from our high volume competitors.
Direct Operating Expenses
     Direct operating expenses were $45.4 million for the six months ended June 30, 2006, compared to $38.7 million for the six months ended June 30, 2005, an increase of $6.7 million or 17.3%. This increase was primarily attributable to higher energy usage as a result of higher refinery throughput and maintenance work performed during the low sulfur diesel turnaround in the second quarter of 2006.
Selling, General and Administrative Expenses
     Consolidated. SG&A expenses for the six months ended June 30, 2006 were $37.8 million, compared to $35.6 million for the six months ended June 30, 2005, an increase of $2.2 million or 6.2%.

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     Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the six months ended June 30, 2006 were $12.1 million, compared to $11.1 million for the six month period ended June 30, 2005, an increase of $1.0 million or 9.0%. This increase resulted from higher corporate costs associated with becoming a public company which significantly increased audit expenditures and added costs associated with becoming Sarbanes Oxley compliant. These costs were partially offset by lower selling and advertising expenses.
     Retail Segment. SG&A expenses for our retail segment for the six months ended June 30, 2006 were $25.5 million, compared to $24.3 million for the six months ended June 30, 2005, an increase of $1.2 million or 4.9%. This increase was primarily attributable to higher energy costs as a result of the increase in electricity prices, which were partially offset by decreased healthcare and workers compensation costs.
Depreciation and Amortization
     Depreciation and amortization for the six months ended June 30, 2006 was $10.9 million, compared to $9.9 million for the six months ended June 30, 2005. This increase was primarily attributable to the completion of the various capital projects in late 2005 and the first six months of 2006. Partially offsetting this increase was the reduction in depreciation due to the disposition of assets in the HEP and Amdel and White Oil transactions.
Operating Income
     Consolidated. Operating income for the six months ended June 30, 2006 was $165.9 million. Excluding $52.5 million of net gain on disposition of assets resulting from the Amdel and White Oil transaction and $5.2 million amortization of deferred gain relating to the 2005 HEP transaction, operating income for the six months ended June 30, 2006 was $108.2 million, compared to $64.5 million operating income (excluding the $29.2 million for gain resulting from the HEP transaction) for the six months ended June 30, 2005, an increase of $43.7 million or 67.8%. This increase was primarily attributable to higher operating income in our refining and marketing segment.
     Refining and Marketing Segment. Operating income for our refining and marketing segment for the six months ended June 30, 2006 was $165.9 million compared to operating income of $94.1 million for the six months ended June 30, 2005. Excluding $52.5 million of net gain on disposition of assets resulting from the Amdel and White Oil transaction and $5.1 million amortization of deferred gain relating to the 2005 HEP transaction, operating income for the six months ended June 30, 2006 was $108.3 million, compared to $64.9 million (excluding the $29.2 million for gain resulting from the HEP transaction) for the six months ended June 30, 2005, an increase of $43.4 million or 66.9%. This increase was primarily attributable to the increase in our refinery operating margins. Our refinery operating margin for the first six months of 2006 increased $3.69 per barrel to $15.02 per barrel, compared to $11.33 per barrel in the first six months of 2005. This increase was attributable, in part, to higher differentials between refined product prices and crude oil prices resulting from continued concern over adequate refinery capacity to meet demand and supply. Also contributing to the higher refinery margins were the supply constraints associated with the logistics of the introduction of new reformulated fuels in the first six months of 2006. The Gulf Coast 3/2/1 crack spread increased by 65.6% to an average of $13.98 per barrel in the first six months of 2006 compared to an average of $8.44 per barrel in the first six months of 2005. In addition, our refinery operating margins benefited from a widening of the sweet/sour crude oil spread. The average sweet/sour spread increased $1.22 per barrel to $5.63 per barrel for the first six months of 2006 compared to the average sweet/sour spread of $4.41 per barrel for the first six months of 2005, an increase of 27.7%.
     Retail Segment. Operating income for our retail segment was $1.3 million for the six months ended June 30, 2006, compared to $0.8 million, an increase of $0.5 million. This increase was primarily attributable to higher fuel sales margins.
Interest Expense
     Interest expense was $10.4 million for the six months ended June 30, 2006, compared to $9.8 million for the six months ended June 30, 2005, an increase of $0.6 million or 6.1%. This increase was primarily attributable to a $3.0 million prepayment premium and the write-off of $3.9 million of unamortized debt issuance costs resulting from the prepayment of our $100 million term loan in January 2006. Partially offsetting this increase was the reduction of the regular interest expense associated with this term loan and interest from subordinated debt paid off in the third quarter of 2005.

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Income Tax Expense
     Income tax expense was $58.1 million for the six months ended June 30, 2006, compared to $32.0 million for the six months ended June 30, 2005, an increase of $26.1 million. This increase resulted from our higher taxable income in the six months ended June 30, 2006, compared to the six months ended June 30, 2005. Our effective tax rate was 36.2% for the six months ended June 30, 2006, compared to an effective tax rate of 37.4% for the six months ended June 30, 2005. This decrease in the effective tax rate is primarily related to expected tax credits associated with the American Jobs Creation Act of 2004.
Minority Interest In Income Of Subsidiaries
     Minority interest in income of subsidiaries represents the proportional share of net income related to non-voting common stock owned by minority stockholders in two of our subsidiaries, Alon Assets and Alon Operating. Minority interest in income of subsidiaries was $5.0 million for the six months ended June 30, 2006, compared to $3.6 million for the six months ended June 30, 2005, an increase of $1.4 million. This increase was attributable to our increased after-tax income in the first six months of 2006 as a result of the factors discussed above.
Net Income
     Net income was $97.3 million for the six months ended June 30, 2006, compared to $49.9 million for the six months ended June 30, 2005, an increase of $47.4 million or 95.0%. This increase was attributable to the factors discussed above.
Liquidity and Capital Resources
     Our primary sources of liquidity are cash on hand, cash generated from our operating activities and borrowings under our revolving credit facility. In addition, significant transactions affecting our liquidity included payment of approximately $100 million in satisfaction of our outstanding borrowings under our term loan, the receipt of $68.0 million net cash proceeds received from the sale of our inactive Amdel and White Oil pipelines and escrow deposits and costs relating to acquisitions of approximately $31.9 million. We believe that our cash on hand, cash flows from operations, borrowings under our revolving credit facility, and other capital resources will be sufficient to satisfy the anticipated cash requirements associated with our existing operations during the next 12 months. Our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control. In addition, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors, including any expansion of our business or acquisitions that we complete.
     Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or equity securities, or other possible capital market transactions, the proceeds of which could be used to refinance current indebtedness or for other corporate purposes. Pursuant to our growth strategy, we will also consider from time to time additional acquisitions of, and investments in, assets or businesses that complement our existing assets and businesses. Acquisition transactions, if any, are expected to be financed through cash on hand and from operations, bank borrowings, the issuance of debt or equity securities or a combination of two or more of those sources.
Cash Flows
     The following table sets forth our consolidated cash flows for the three and six months ended June 30, 2006 and 2005:
                                 
    For the Three Months Ended     For the Six Months Ended  
    June 30,     June 30,  
    2006     2005     2006     2005  
    (dollars in thousands)     (dollars in thousands)  
Cash provided by (used in):
                               
Operating activities
  $ 5,013     $ 65,825     $ (4,710 )   $ 49,388  
Investing activities
    66,221       (5,656 )     195,608       88,147  
Financing activities
    (3,710 )     (612 )     (123,370 )     (32,346 )
 
                       
Net increase in cash and cash equivalents
  $ 67,524     $ 59,557     $ 67,528     $ 105,189  
 
                       

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Cash Flows (Used In) Provided by Operating Activities
     Net cash used in operating activities during the six months ended June 30, 2006 was $4.7 million, compared to net cash provided by operating activities of $49.4 million during the six months ended June 30, 2005. The net change in cash used in operating activities was primarily due to changes in working capital. This change was primarily attributable to the net increase in accounts receivables and inventories as a result of higher prices and inventory quantities.
     Net cash provided by operating activities during the three months ended June 30, 2006 was $5.0 million, compared to net cash provided by operating activities of $65.8 million during the three months ended June 30, 2005. The net reduction of cash provided by operating activities was primarily due to changes in working capital. This decrease was primarily attributable to the net increase in accounts receivables and inventories and a decrease in accounts payable.
Cash Flows (Used In) Provided By Investing Activities
     Net cash provided by investing activities increased to $195.6 million during the six months ended June 30, 2006 from $88.1 million provided by investing activities during the six months ended June 30, 2005. This increase was primarily attributable to $68.0 million in net proceeds received in the Amdel and White Oil transaction and the proceeds from the sales of $185.3 million of short-term investments. Capital expenditures in the first six months of 2006 totaled $26.1 million and included $12.8 million for regulatory and compliance projects, $2.9 million for chemical catalyst and $10.4 million for various sustaining and capital improvement projects.
     Net cash provided by investing activities was $66.2 million during the three months ended June 30, 2006 compared to cash used in investing activities of $5.7 million for the three months ended June 30, 2005. This increase in cash provided by investing activities was attributable to the receipt of $118.0 million from sales of short-term investments, partially offset by capital expenditures and escrow deposits and related acquisition costs of $31.9 million. Capital expenditures for the second quarter of 2006 totaled $20.2 million and included $9.3 million for regulatory and compliance projects, $1.6 million for turnaround and chemical catalyst costs and $9.3 million for various sustaining and capital improvement projects.
Cash Flows Used In Financing Activities
     Net cash used in financing activities was $123.4 million during the six months ended June 30, 2006, compared to net cash used in financing activities of $32.3 million during the six months ended June 30, 2005. Cash used in financing activities in the first six months of 2006 included the prepayment of our $100.0 million term loan and $22.1 million of dividends paid to our stockholders.
     Net cash used in financing activities was $3.7 million for the three months ended June 30, 2006, compared to $0.6 used in the three months ended June 30, 2005. The cash used in the second quarter of 2006 included dividends paid to stockholders and minority interest stockholders of $3.0 million.
Cash Position and Indebtedness
     We consider all highly liquid instruments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value and are invested in conservative, highly rated instruments issued by financial institutions or government entities with strong credit standings. Short-term investments primarily consist of highly-rated auction rate securities, or ARS. Although ARS may have long-term stated maturities, generally 10 to 30 years, we have designated these securities as available-for-sale and have classified them as current assets because we view them as available to support our current operations. ARS may be liquidated at par on the rate reset date, which is in intervals of seven to 49 days, depending on the terms of the security. These securities are carried at cost, which approximates market value. As of June 30, 2006, our total cash and cash equivalents were $204.3 million and we had total debt of approximately $31.2 million. On January 19, 2006, we used cash of approximately $103.9 million to repay our term loan, including a $3.0 million prepayment premium and $0.9 million of accrued interest.

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     Summary of Indebtedness. The following table sets forth the principal amounts outstanding under our bank credit facilities, retail mortgages and equipment loans at June 30, 2006:
         
    As of June 30, 2006  
    (dollars in thousands)  
Debt, including current portion
       
Bank credit facilities:
       
Revolving credit facility
  $  
Retail mortgages and equipment loans
    31,163  
 
     
Total debt
  $ 31,163  
 
     
     Revolving Credit Facility. We entered into a revolving credit facility on July 31, 2000, which was amended and restated on January 14, 2004, further amended and restated on February 15, 2006, and again amended and restated on June 22, 2006. The Israel Discount Bank of New York, or Israel Discount Bank, acts as administrative agent, co-arranger, collateral agent and lender and Bank Leumi USA acts as co-arranger and lender under the revolving credit facility. The initial size of the revolving credit facility is $160.0 million with options to increase the size of the facility to $240.0 million if crude oil prices increase above certain levels or we increase our throughput capacity.
     Borrowing availability under the revolving credit facility is limited at any time to the lower of the total current size of the revolving credit facility at that time, which is initially $160.0 million or the amount of the borrowing base under the revolving credit agreement. As of June 30, 2006, the borrowing base under the revolving credit facility was $337 million. The entire revolving credit facility is available in the form of letters of credit and revolving loans. The borrowings under the revolving credit facility bear interest at the Eurodollar rate plus 1.50% per annum. The revolving credit facility is jointly and severally guaranteed by all of our subsidiaries except for our retail subsidiaries. The revolving credit facility is secured by a first priority lien on cash, accounts receivables, and inventories and a second priority lien on all other existing assets.
     No borrowings were outstanding under the revolving credit facility at June 30, 2006 and 2005. As of June 30, 2006 and 2005, there were $96.9 million and $141.1 million, respectively, of outstanding letters of credit under the revolving credit facility.
     Our revolving credit facility contains restrictive covenants, such as restrictions on change of control, creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, giving guaranties, engaging in different businesses, making loans and investments, entering into certain lease obligations, making certain capital expenditures and making certain dividend, debt and other restricted payments. However, these covenants do not restrict our activities so long as we maintain the financial covenants described below, on a pro-forma basis after giving effect to these activities. Our revolving credit facility also contains covenants that restrict us from compromising or adjusting receivables, engaging in certain transactions with affiliates and amending or waiving certain material agreements. The revolving credit facility contains financial covenants requiring Alon to maintain:
    a minimum consolidated tangible net worth equal to the sum of $106.0 million plus an amount determined on a cumulative basis equal to the sum of 50% of any positive net income for each fiscal year after December 31, 2004 (as of June 30, 2006, the minimum consolidated tangible net worth was $206.4 million and our actual consolidated tangible net worth was $274.4 million);
 
    a ratio of total consolidated indebtedness less freely transferable cash and permitted investments not subject to any lien (other than liens in favor of Israel Discount Bank) to consolidated EBITDA for the last four fiscal quarters of no greater than 4.0 to 1.0 (the ratio as of June 30, 2006 was (.2) to 1.00);
 
    a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0 (the ratio as of June 30, 2006 was 2.0 to 1.0); and
 
    a ratio of total consolidated EBITDA to consolidated interest expense, in each case as of the end of any period of four fiscal quarters, to be not less than 2.0 to 1.0 (the ratio as of June 30, 2006 was 14.5 to 1.0).

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     Compliance with these covenants is determined in the manner specified in the documentation governing the revolving credit facility. Consolidated EBITDA under our revolving credit facility represents net income plus minority interest, income tax expense, interest expense, depreciation and amortization and is measured each quarter on a rolling twelve-month basis. As of June 30, 2006, we were in compliance with all of these covenants.
     Wachovia Credit Facility. On June 6, 2006, we, through SCS, entered into a Credit Agreement (the “Wachovia Credit Facility”) by and among SCS, as Borrower, and Wachovia Bank. Borrowings under the Wachovia Credit Facility are available in the form of (i) a term loan commitment in an aggregate principal amount of $30 million maturing on June 30, 2016 and (ii) a revolving credit commitment (available in the form of revolving loans and letters of credit) in an aggregate principal amount of $20 million maturing on June 30, 2009. Revolving loans may be converted by SCS at any time to a term loan maturing on the tenth anniversary of conversion. At the request of SCS, the revolving credit commitment may be increased by an amount not to exceed $10 million. The aggregate amount of the lenders’ commitments under the entire Wachovia Credit Facility may not exceed $60 million. As of June 30, 2006, there were no borrowings or letters of credit outstanding under the Wachovia Credit Facility.
     Obligations under the Wachovia Credit Facility are jointly and severally guaranteed by us, our wholly-owned subsidiaries Alon USA Interests, LLC and Good Time Enterprise, LLC, and all of the subsidiaries of SCS and Good Time Enterprise, LLC. The obligations under the Wachovia Credit Facility are secured by a pledge of substantially all of the assets of SCS, Good Time Enterprise, LLC and their subsidiaries, including cash, accounts receivable and inventory.
     The Wachovia Credit Facility includes a financial covenant that requires us to maintain a ratio of total consolidated EBITDA less cash taxes to total consolidated scheduled principal payments of indebtedness plus interest expense, as of the end of each fiscal year, of not less than 1.25 to 1.0. Compliance with this covenant is determined in the manner specified in the documentation governing the credit facility. Consolidated EBITDA under the Wachovia Credit Facility represents net income plus depreciation, amortization, taxes, interest expense and minority interest. As of June 30, 2006, we were in compliance with this covenant.
     The Wachovia Credit Facility contains customary restrictive covenants on the activities of SCS, Good Time Enterprise, LLC and their subsidiaries, such as restrictions on creating liens, mergers, consolidations and sales of assets, incurring additional indebtedness, engaging in different businesses, entering into certain lease obligations, and making certain restricted payments.
     Credit Suisse Credit Facility. On June 22, 2006, Alon entered into a Credit Agreement with Credit Suisse (the “Credit Suisse Credit Facility”) with an aggregate available amount of $450 million. On August 4, 2006, Alon borrowed $400 million as a term loan upon consummation of the acquisition of Paramount. Borrowings of an additional $50 million are available until September 30, 2006 to finance the acquisition of Edgington. The loans under the Credit Suisse Credit Facility will mature on August 2, 2013.
     The borrowings under the Credit Suisse Credit Facility require a principal payment of 1% per annum to be paid in quarterly payments beginning September 30, 2006 with the balance due at maturity. The borrowings under the Credit Suisse Credit Facility bear interest at a Eurodollar rate plus 2.50% per annum. The interest rate may be reduced up to the Eurodollar rate plus 1.75% per annum based upon the ratings of the loans by Standard & Poor’s Rating Service and Moody’s Investors Service, Inc. The Credit Suisse Credit Facility is jointly and severally guaranteed by all of our subsidiaries except for our retail subsidiaries. The Credit Suisse Credit Facility is secured by a first lien on most of our assets except for cash, accounts receivable and inventory. The Credit Suisse Credit Facility is secured by a second lien on cash, accounts receivable and inventory.
     Alon may, from time to time, request an additional $100 million provided that the sum of the incremental loans and the outstanding loans under the Credit Suisse Credit Facility does not exceed $500 million (or $550 million, if $50 million is used to finance the Edgington acquisition).
     Alon may prepay at anytime a portion or all of the outstanding loan balance under the Credit Suisse Credit Facility with no prepayment premium.
     The Credit Suisse Credit Facility contains restrictive covenants, such as restrictions on creating liens, mergers, consolidations and sales of assets, incurring additional indebtedness, engaging in different businesses, entering into certain lease obligations, and making certain restricted payments. This facility does not contain any financial maintenance covenants.

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Capital Spending
     Each year our Board of Directors approves capital projects, including regulatory and planned turnaround projects that our management is authorized to undertake in our annual capital budget. Additionally, at times when conditions warrant or as new opportunities arise, other projects or the expansion of existing projects may be approved. Our total capital expenditure and turnaround/chemical catalyst budget for 2006 is $38.2 million, of which $12.8 million related to regulatory and compliance projects, $2.9 million related to turnaround and chemical catalyst, and $10.4 million for various improvement and sustaining projects, had been spent as of June 30, 2006.
     Clean Air Capital Expenditures. We expect to spend approximately $15.4 million over the next five years to comply with the Federal Clean Air Act regulations requiring a reduction in sulfur content in gasoline.
     Turnaround and Chemical Catalyst Costs. We completed a major turnaround on substantially all of our major processing units, including the crude unit and the fluid catalytic cracking unit and chemical catalyst replacement in the first week of March 2005, at a cost of approximately $10.4 million. We expect to spend approximately $4.4 million for chemical catalyst replacement in 2006, including the $1.3 million chemical catalyst expenditures as of June 30, 2006.
Contractual Obligations and Commercial Commitments
     There have been no material changes in the six months ended June 30, 2006, outside the ordinary course of business from our contractual obligations and commercial commitments detailed in our annual report on Form 10-K for the year ended December 31, 2005 with the exception of the following:
    the prepayment of our $100 million term loan due January 14, 2009 with available cash on hand on January 19, 2006; and
 
    our obligations under the Sunoco Throughput & Deficiency Agreement.
Off-Balance Sheet Arrangements
     We have no off-balance sheet arrangements.
Critical Accounting Policies
     We prepare our consolidated financial statements in conformity with GAAP. In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events, some of which we may have little or no control over.
     Our critical accounting policies are described under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies” in our annual report on Form 10-K for the year ended December 31, 2005. Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements are the use of LIFO method for valuing certain inventories and the deferral and subsequent amortization of costs associated with major turnarounds and chemical catalysts replacements. No significant changes to these accounting policies have occurred subsequent to December 31, 2005.
New Accounting Standards and Disclosures
     Effective January 1, 2006, Alon adopted Statement of Financial Accounting Standards No. 123R, Share-Based Payment (“SFAS No. 123R”), which requires use of the fair-value based method and expensing of stock options and other share-based compensation payments to employees, net of estimated forfeitures, over the requisite service period and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing pro-forma disclosure only. As a private company, Alon used the minimum value method of measuring equity share options for pro-forma disclosure purposes under SFAS No. 123. Accordingly, Alon applied SFAS No. 123R prospectively to new awards and to awards modified, repurchased or forfeited after January 1, 2006. Alon applied the modified prospective transition method to any unvested stock-based awards issued after the initial public offering (“IPO”). The adoption of SFAS No. 123R did not have a significant effect on Alon’s financial position or results of operations.

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     Alon previously accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations (“Opinion 25”). Accordingly, compensation cost for stock options was measured as the excess of the estimated fair value of the common stock over the exercise price and was recognized over the scheduled vesting period on an accelerated basis. Stock compensation expense is presented as selling, general and administrative expenses in the accompanying consolidated statements of operations. All pre-IPO stock-based awards will continue to be accounted for under Opinion 25.
     In November 2004, the Financial Accounting Standards Board (“FASB”) issued Statement No. 151, Inventory Costs, which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material and requires that those items be recognized as current-period charges. Statement No. 151 also requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. Statement No. 151 is effective for fiscal years beginning after June 15, 2005. The adoption of Statement No. 151 did not have a material effect on Alon’s financial position or results of operations.
     In December 2004, the FASB issued FASB Staff Position (“FSP”) FAS 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004 (“Jobs Creation Act”) which requires a company that qualifies for the deduction for domestic production activities under the Jobs Creation Act to account for it as a special deduction under FASB Statement No. 109, Accounting for Income Taxes, as opposed to an adjustment of recorded deferred tax assets and liabilities.
     In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (“FIN No. 48”). This interpretation prescribes a “more-likely-than-not” recognition threshold and measurement attribute (the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement with tax authorities) for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provided guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. Alon will adopt the provisions of FIN No. 48 on January 1, 2007 and does not expect these provisions to have a material effect on Alon’s results of operations, financial condition or liquidity.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
     Changes in commodity prices, purchased fuel prices and interest rates are our primary sources of market risk. Our risk management committee oversees all activities associated with the identification, assessment and management of our market risk exposure.
Commodity Price Risk
     We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels and governmental regulatory initiatives. Our risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations.
     In order to manage the uncertainty relating to inventory price volatility, we have consistently applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as timing of crude oil cargo deliveries, turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. Upon the review and approval of our risk management committee, we may utilize the commodity futures market to manage these anticipated inventory variances.

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     We maintain inventories of crude oil, feedstocks and refined products, the values of which are subject to wide fluctuations in market prices driven by world economic conditions, regional and global inventory levels and seasonal conditions. As of June 30, 2006, we held approximately 2.2 million barrels of crude and product inventories valued under the LIFO valuation method with an average cost of $39.17 per barrel. Market value exceeded carrying value of LIFO costs by $76.0 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced by $2.2 million.
     In accordance with SFAS No. 133, all commodity futures contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section of our consolidated financial statements. “Forwards” represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. “Futures” represent trades which have been executed on the New York Mercantile Exchange (“NYMEX”) which have not been closed or settled at the end of the reporting period. A “long” represents an obligation to purchase product and a “short” represents an obligation to sell product.
     The following table provides information about our derivative commodity instruments as of June 30, 2006:
                                                 
            Wtd Avg   Wtd Avg            
Description   Contract   Purchase   Sales   Contract   Fair   Gain
of Activity   Volume   Price/BBL   Price   Value   Value   (Loss)
                            (in thousands)
Futures-long
        $     $     $     $     $  
Futures-short
                                   
Forwards-long (refined products)
    25,000       90.55       91.50       2,263       2,287       24  
Forwards-short (refined products)
                                   
Interest Rate Risk.
     As of June 30, 2006, none of our outstanding debt was at floating interest rates.
ITEM 4. CONTROLS AND PROCEDURES
(1) Evaluation of disclosure controls and procedures.
     Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms.
(2) Changes in internal control over financial reporting.
     There has been no change in our internal control over financial reporting (as described in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION
ITEM 5. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
     The Annual Meeting of the Company’s stockholders was held on May 9, 2006. The Company’s stockholders voted on the following items at the Annual Meeting:
  (a)   The stockholders approved the election of ten (10) Directors for a one-year term expiring at the 2007 Annual Meeting of the Company’s stockholders. The votes for these elections were as follows:
                 
Director   For   Withheld
Itzhak Bader
    41,146,811       4,166,206  
 
               
Boaz Biran
    41,422,093       3,890,924  
 
               
Pinchas Cohen
    39,365,522       5,947,495  
 
               
Shaul Gliksberg
    41,147,330       4,165,687  
 
               
Ron W. Haddock
    39,860,748       5,452,269  
 
               
Jeff. D. Morris
    40,130,445       5,182,572  
 
               
Yeshayahu Pery
    41,420,627       3,892,390  
 
               
Zalman Segal
    44,939,531       373,486  
 
               
Avraham Shochat
    44,940,264       372,753  
 
               
David Wiessman
    40,129,712       5,183,305  
  (b)   The stockholders ratified the employment of KPMG LLP as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2006. The votes for ratification were 44,552,534, the votes against ratification were 745,618 and the votes abstained were 14,865. There were no broker non-votes.
 
  (c)   The stockholders approved the Alon USA Energy, Inc. 2005 Incentive Compensation Plan. The votes in favor of approval were 44,004,349, the votes against approval were 1,186,839, and the votes abstained were 121,829. There were no broker non-votes.

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ITEM 6. EXHIBITS
     
Exhibit    
Number   Description of Exhibit
 
   
3.1
  Amended and Restated Certificate of Incorporation of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.1 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
3.2
  Amended and Restated Bylaws of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.2 to Form S-1, filed by the Company on July 14, 2005, SEC File No. 333-124797).
 
   
4.1
  Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.1
  Form of Restricted Stock Award Agreement relating to Director Grants pursuant to Section 12 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on August 5, 2005, SEC File No. 001-32567).
 
   
10.2
  Stock Purchase Agreement by and among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy III and Mark R. Milano, dated April 28, 2006 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on May 2, 2006, SEC File No. 001-32567).
 
   
10.3
  Agreement and Plan of Merger by and among Alon USA Energy, Inc., Apex Oil Company, Inc., Edgington Oil Company, and EOC Acquisition, LLC, dated April 28, 2006 (incorporated by reference to Exhibit 10.2 to Form 8-K filed by the Company on May 2, 2006, SEC File No. 001-32567).
 
   
10.4
  Credit Agreement, dated June 6, 2006, by and among Southwest Convenience Stores, LLC, the lenders party thereto and Wachovia Bank, National Association (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on June 7, 2006, SEC File No. 001-32567).
 
   
10.5
  Credit Agreement, dated June 22, 2006, by and among Alon USA Energy, Inc., the lenders party thereto and Credit Suisse (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on June 26, 2006, SEC File No. 001-32567).
 
   
10.6
  Amended Revolving Credit Agreement, dated June 22, 2006, by and among Alon USA, LP, EOC Acquisition, LLC, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.2 to Form 8-K filed by the Company on June 26, 2006, SEC File No. 001-32567).
 
   
31.1*
  Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2*
  Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1*
  Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
 
*   Furnished herewith.

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SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
     
Date: August 11, 2006  By:   /s/ David Wiessman    
    David Wiessman   
    Executive Chairman   
 
     
Date: August 11, 2006  By:   /s/ Jeff D. Morris    
    Jeff D. Morris   
    Chief Executive Officer   
 
     
Date: August 11, 2006  By:   /s/ Shai Even    
    Shai Even   
    Chief Financial Officer   

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EXHIBITS
     
Exhibit    
Number   Description of Exhibit
 
   
3.1
  Amended and Restated Certificate of Incorporation of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.1 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
3.2
  Amended and Restated Bylaws of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.2 to Form S-1, filed by the Company on July 14, 2005, SEC File No. 333-124797).
 
   
4.1
  Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.1
  Form of Restricted Stock Award Agreement relating to Director Grants pursuant to Section 12 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on August 5, 2005, SEC File No. 001-32567).
 
   
10.2
  Stock Purchase Agreement by and among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy III and Mark R. Milano, dated April 28, 2006 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on May 2, 2006, SEC File No. 001-32567).
 
   
10.3
  Agreement and Plan of Merger by and among Alon USA Energy, Inc., Apex Oil Company, Inc., Edgington Oil Company, and EOC Acquisition, LLC, dated April 28, 2006 (incorporated by reference to Exhibit 10.2 to Form 8-K filed by the Company on May 2, 2006, SEC File No. 001-32567).
 
   
10.4
  Credit Agreement, dated June 6, 2006, by and among Southwest Convenience Stores, LLC, the lenders party thereto and Wachovia Bank, National Association (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on June 7, 2006, SEC File No. 001-32567).
 
   
10.5
  Credit Agreement, dated June 22, 2006, by and among Alon USA Energy, Inc., the lenders party thereto and Credit Suisse (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on June 26, 2006, SEC File No. 001-32567).
 
   
10.6
  Amended Revolving Credit Agreement, dated June 22, 2006, by and among Alon USA, LP, EOC Acquisition, LLC, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.2 to Form 8-K filed by the Company on June 26, 2006, SEC File No. 001-32567).
 
   
31.1*
  Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2*
  Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1*
  Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
 
*   Furnished herewith.

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