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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005
OR
     
o   ANNUAL 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 of incorporation)   (I.R.S. Employer Identification No.)
7616 LBJ Freeway, Suite 300, Dallas, Texas 75251
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (972) 367-3600
Securities registered pursuant to Section 12 (b) of the Act:
     
Title of each class   Name of each exchange on which registered
     
Common Stock, par value   New York Stock Exchange
$0.01 per share    
Securities registered pursuant to Section 12 (g) of the Act: None
     Indicate by check mark if the registrant is a well-known, seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
     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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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.
     Large Accelerated Filer o      Accelerated Filer o      Non-Accelerated Filer þ
     Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes o No þ
     The Registrant completed the initial public offering of its common stock in July 2005. Accordingly, there was no public market for the Registrant’s common stock as of June 30, 2005, the last day of the Registrant’s most recently completed second fiscal quarter.
     As of March 1, 2006, 46,809,857 shares of the registrant’s common stock, $0.01 par value, were outstanding.
     Documents incorporated by reference: Proxy statement of the registrant relating to the annual meeting of stockholders to be held on May 9, 2006, which is incorporated into Part III of this Form 10-K.
 
 

 


 

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 Management Employment Agreement
 Amendment to Executive/Management Employment Agreement
 List of Subsidiaries
 Consent of KPMG LLP
 Certifications of CEO Pursuant to Section 302
 Certification of CFO Pursuant to Section 302
 Certification of CEO and CFO Pursuant to Section 906

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PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES.
Statements in this Annual Report on Form 10-K, including those in Items 1 and 2, “Business and Properties,” and Item 3, “Legal Proceedings,” that are not historical in nature should be deemed forward looking statements that are inherently uncertain. See “Forward-Looking Statements” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of forward looking statements and of factors that could cause actual outcomes and results to differ materially from those projected.
Company Overview
     In this document, the words “we,” “our” and “us” refer to Alon USA Energy, Inc. and its consolidated subsidiaries or to Alon USA Energy, Inc. or an individual subsidiary, and not to any other person.
     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, which we expanded in March 2005 from a crude oil throughput capacity of 62,000 barrels per day (“bpd”) to 70,000 bpd. We refine crude oil into petroleum products, including gasoline, diesel, jet fuel, petrochemicals, feedstocks, asphalts and other petroleum products, which we market primarily 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 motor fuels produced at our Big Spring refinery. We distribute our fuel products through a product pipeline and terminal network of seven product pipelines totaling approximately 840 miles and six product terminals, which we own or access through leases or long-term throughput agreements. Our physically integrated system includes more than 550 of the approximately 1,250 FINA branded retail sites that we supply, including our retail segment convenience stores.
     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. We also market unbranded gasoline, diesel, jet fuel and other refinery products, and we are one of the largest suppliers of asphalt in West Texas, New Mexico and Arizona.
     Retail Segment. We operate 167 7-Eleven branded convenience stores in West Texas and New Mexico. Our convenience stores typically offer merchandise, food products and motor fuels under the 7-Eleven and FINA brand names. 7-Eleven, Inc. has advised us that we are the largest 7-Eleven licensee in the United States, and we are one of the top three convenience store operators, based on number of stores, in the cities of El Paso, Midland, Odessa, Big Spring and Lubbock, Texas. We also have a significant presence in Wichita Falls, Texas and Albuquerque, New Mexico. We supply our stores with substantially all of their motor fuel needs with gasoline and diesel produced at our Big Spring refinery.
     Operating segment and geographical information are discussed further in Note 5 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
     We are a controlled company under the rules and regulations of the New York Stock Exchange because Alon Israel Oil Company, Ltd. (“Alon Israel”) owns approximately 74.3% of our outstanding common stock. Alon Israel, an Israeli limited liability company, is the largest services and trade company in Israel. Alon Israel entered the gasoline marketing and convenience store business in Israel in 1989 and has grown to become a leading marketer of petroleum products and one of the largest operators of retail gasoline and convenience stores in Israel. Alon Israel is a controlling shareholder of Blue Square Israel, Ltd., a leading retailer in Israel, which is listed on the New York Stock Exchange and the Tel Aviv Stock Exchange.
     We are a Delaware corporation formed in 2000 to acquire the Big Spring refinery and related pipeline, terminal and marketing assets from Atofina Petrochemicals, Inc., or FINA. We maintain our principal corporate offices at 7616 LBJ Freeway, Suite 300, Dallas, Texas 75251-1100. Our telephone number is 972-367-3600. We

 


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file annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). Our SEC filings are available to the public over the Internet at the SEC’s web site at http://www.sec.gov. In addition, we make available free of charge through our internet website at http://www.alonusa.com, our annual, quarterly and current reports, proxy statements and certain other information filed by us with the SEC, as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC. In addition, we will provide copies of our filings free of charge to our stockholders upon request. On July 28, 2005, our stock began trading on the New York Stock Exchange under the trading symbol “ALJ.”
2005 Highlights and Recent Developments
     In February 2005, we completed the contribution of certain of our product pipeline and terminal assets to Holly Energy Partners, L.P. (“HEP”). In exchange for this contribution we received $120.0 million in cash, prior to closing cost of approximately $2.0 million, and 937,500 subordinated Class B limited partnership units of HEP. Simultaneously with this transaction, we entered into a Pipelines and Terminal Agreement with HEP with an initial term of 15 years and three subsequent five year renewal terms exercisable at our sole discretion. Pursuant to the Pipelines and Terminal Agreement, we have agreed to transport and store minimum volumes of refined products in these pipelines and terminals and to pay specified tariffs and fees for such transportation and storage during the term of the agreement.
     In March 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. The cost of the expansion project was approximately $6.4 million, or $800 per bpd of additional throughput capacity.
     On August 2, 2005, we completed an initial public offering of 11,730,000 shares of our common stock at a price of $16.00 per share for an aggregate offering price of $187.7 million. The initial public offering represented the sale by us of a 25.1% interest in our company. On July 28, 2005, our stock began trading on the New York Stock Exchange under the trading symbol “ALJ.”
     On January 19, 2006, we made a payment of approximately $103.9 million in satisfaction of our outstanding borrowings under our term loan agreement scheduled to mature in January 2009. Of this amount, $100.0 million represented a voluntary prepayment of our outstanding principal under the term loan, approximately $0.9 million represented accrued and unpaid interest on the principal balance, and $3.0 million represented a prepayment premium.
     On February 15, 2006, our Board of Directors announced a regular quarterly cash dividend of $0.04 per share and a special cash dividend of $0.37 per share on our common stock, payable on March 21, 2006 to stockholders of record at the close of business on March 1, 2006. In connection with our cash dividend payment to shareholders on March 21, 2006, the minority interest owners in two of our subsidiaries, Alon Assets Inc., and Alon USA Operating Inc., will receive aggregate cash dividends of approximately $1.1 million.
     On February 15, 2006, we entered into an amended revolving credit agreement. The total commitment under our revolving credit facility was increased from $141.6 million to $240.0 million and is available for, among other things, working capital, acquisitions and other general corporate purposes. The initial size of the facility is $160.0 million with options to increase the size to $240.0 million. 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 our retail subsidiaries have been excluded from the facility. The facility is secured by cash, short-term investments, accounts receivable, inventory and related assets. All fixed assets previously securing the facility have been released.
     On March 1, 2006, we sold our Amdel and White Oil crude pipelines, which had been inactive since December 2002, to an affiliate of Sunoco Logistics Partners L.P. (“Sunoco”), for a total consideration of approximately $68.0 million. In conjunction with the sale of the Amdel and White Oil pipelines, we entered into a 10-year pipeline Throughput and Deficiency Agreement, with

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an option to extend the agreement by four additional thirty month periods. The Throughput and Deficiency Agreement will allow us to retain crude oil transportation rights on the Amdel and White Oil pipelines from the Gulf Coast. Pursuant to the Throughput and Deficiency Agreement, we have agreed to ship a minimum of 15,000 barrels per day on the pipelines during the term of the agreement.
Refining and Marketing Segment
Refinery Operations
     Our Big Spring refinery has a crude oil throughput capacity of 70,000 bpd and is located on 1,306 acres in the Permian Basin in West Texas. In industry terms, our refinery is characterized as a “cracking refinery.” Our Big Spring refinery has the capability to process substantial volumes of less expensive high-sulfur, or sour, crude oils to produce a high percentage of light, high-value refined products. Typically, sour crude oil has accounted for over 90% of our crude oil input. We also have access to domestic and foreign crude oils available on the Gulf Coast, which we are able to deliver to our Big Spring refinery through the Amdel and White Oil pipelines.
     Our Big Spring refinery produces gasoline, distillates, petrochemicals, petrochemical feedstocks, asphalt and other petroleum products. Our refinery typically converts approximately 86% of its feedstock into higher value products such as gasoline, diesel, jet fuel and petrochemicals, with the remaining 14% primarily converted to asphalt and liquefied petroleum gas.
     During each full year of operations since our acquisition from FINA, we have averaged approximately 96% utilization of our Big Spring refinery’s crude oil throughput capacity. The following table summarizes historical throughput and production data for our Big Spring refinery:
                                                 
    Year Ended December 31,  
    2005     2004     2003  
    Bpd     %     Bpd     %     Bpd     %  
Refinery throughput:
                                               
Sweet crude
    5,072       7.8       4,321       7.0       5,398       8.4  
Sour crude
    55,643       86.0       53,646       87.0       55,676       86.5  
Blendstocks
    4,040       6.2       3,697       6.0       3,280       5.1  
 
                                   
Total refinery throughput (1)(2)
    64,755       100.0       61,664       100.0       64,354       100.0  
 
                                   
 
                                               
Refinery production:
                                               
Gasoline
    29,499       45.8       28,711       46.8       30,700       47.7  
Diesel/jet
    21,903       34.0       19,939       32.5       21,554       33.5  
Asphalt
    5,824       9.1       5,781       9.4       5,746       8.9  
Petrochemicals
    4,256       6.6       4,492       7.3       4,536       7.1  
Other
    2,911       4.5       2,449       4.0       1,804       2.8  
 
                                   
Total refinery production (2)(3)
    64,393       100.0       61,372       100.0       64,340       100.0  
 
                                   
 
                                               
Refinery utilization (4)
    94.3 %             95.0 %             99.3 %        
 
(1)   Total refinery throughput represents the total of crude oil and blendstock inputs in the refinery production process.
 
(2)   2005 throughput reflects the effect of the downtime associated with the planned major turnaround in the first quarter 2005. Refinery throughput increased to an average of 70,419 bpd for the last three quarters of 2005, compared to an average throughput of 47,447 bpd for the first quarter 2005. Refinery production increased to an average of 70,065 bpd for the last three quarters of 2005, compared to average production of 47,060 bpd for the first quarter 2005.
 
(3)   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 Alon’s refinery.
 
(4)   Refinery utilization represents average daily crude oil throughput divided by crude capacity, excluding planned periods of downtime for maintenance and turnarounds.
Raw Material Supply
     Sour crude oil has typically accounted for over 90% of our crude oil input, of which approximately 99% has been West Texas Sour, or WTS, crude oil. We receive WTS crude oil and West Texas Intermediate, or WTI, a light sweet crude oil, primarily from regional common carrier pipelines. Approximately 47% of our crude oil input

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requirements are purchased through term contracts with several suppliers, including major oil companies. These term contracts are generally short-term in nature with arrangements that contain market-responsive pricing provisions and provisions for renegotiation or cancellation by either party. The remainder of our crude oil input requirements are purchased on the spot market. In addition, access to the Amdel pipeline gives us the ability to optimize our refinery crude slate by transporting foreign and domestic crude oils to our refinery from the Gulf Coast when the economics for processing those crude oils are more favorable than processing locally sourced crude oils. Other feedstocks, including butane, isobutane and asphalt blending components, are delivered by truck and railcar, and a majority of our natural gas is delivered by a pipeline in which we own a 63.0% interest.
Big Spring Refinery Production
     Gasoline. Gasoline has typically accounted for approximately 46% of our refinery’s production. We produce various grades of gasoline, ranging from 84 sub-octane regular unleaded to 93 octane premium unleaded, and use a computerized component blending system to optimize gasoline blending. Our refinery is capable of producing specially formulated fuels, such as those required in the El Paso, Dallas/Fort Worth and Arizona markets.
     Distillates. Diesel and jet fuel has typically accounted for approximately 34% of our refinery’s production. All of the diesel fuel we produce is low-sulfur, while our jet fuel production conforms to the JP-8 grade military specifications required by the Air Force bases to which we market our jet fuel.
     Asphalt. Asphalt has typically accounted for approximately 9% of our refinery’s production. Approximately 60% of our asphalt production is paving grades and 40% is asphalt blendstocks. Our refinery’s asphalt facilities are capable of producing up to 23 different grades of asphalt base stock, including both polymer modified asphalt (“PMA”) and ground tire rubber (“GTR”) asphalt.
     Petrochemical Feedstocks and Other. We produce propane, propylene, certain aromatics, specialty solvents and benzene for use as petrochemical feedstocks, along with other by-products such as sulfur and carbon black oil. We have sulfur processing capabilities of approximately two tons per thousand bpd of crude oil capacity, which is above the average for cracking refineries and aids in our ability to produce low-sulfur motor fuels with relatively low investment while continuing to process significant amounts of sour crude oil.
Transportation Fuel Marketing
     Our refining and marketing segment sales includes sales of refined products in both the wholesale rack and bulk markets. Our marketing of transportation fuels is focused on five states in the Southwestern and South Central regions of the United States through our physically integrated and non-integrated systems.
     Branded Transportation Fuel Marketing. Our branded fuels are marketed through our retail segment and to independently-owned FINA branded retail distributors. During 2005 we sold over 39,000 bpd of gasoline and diesel fuel as branded fuels. Approximately 70% of our branded fuel sales are in West Texas and Central Texas.
     The FINA brand is a recognized trade name in the Southwestern and South Central United States, where motor fuels have been marketed under the FINA brand since 1963. Our retail segment operates up to 20% of the convenience stores selling motor fuels in several key cities in these regions. We have an exclusive license through July 2012 to use the FINA name and related trademarks in connection with the production and sale (including resale by distributors) of gasoline, diesel and other fuels within Texas, Oklahoma, New Mexico, Arizona, Arkansas, Louisiana, Colorado and Utah. Prior to the expiration of this license, we intend to review our alternatives for branding our transportation fuel, including seeking to extend our license with FINA or developing our own brand.
     Unbranded Transportation Fuel Marketing. We presently sell a majority of our diesel fuel, and a nominal volume of gasoline, on an unbranded basis. During 2005, we sold over 18,700 bpd of diesel fuel and gasoline as unbranded fuels, which were largely sold through our physically integrated system.
     Jet Fuel Marketing. We market substantially all our jet fuel as JP-8 grade to the Defense Energy Supply Center (“DESC”). All DESC contracts are for a one-year term and are awarded through a competitive bidding process. We have traditionally bid for contracts to supply Dyess Air Force Base in Abilene, Texas and Sheppard Air

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Force Base in Wichita Falls, Texas. Jet fuel production in excess of existing contracts is sold on the spot market or, alternatively as diesel fuel.
     Product Supply Sales. We sell transportation fuel production in excess of our branded and unbranded marketing needs through bulk sales and exchange channels. These bulk sales and exchange arrangements are entered into with various oil companies and traders and are transported through our product pipeline network or truck deliveries. Our petrochemical feedstock and other petroleum product production is sold to a wide customer base and is transported through truck and railcars.
Asphalt Marketing
     The Texas Department of Transportation has advised us that we are the second largest supplier of asphalt to the State of Texas, which is the largest asphalt consuming state in the United States. Our Big Spring refinery produces an average of approximately 5,750 bpd of asphalt that is sold in up to 23 different product formulations, including both PMA and GTR, which are paving grade asphalt formulations. We have increased our production capabilities for latex and rubber modified grades that meet the stringent and varied state highway road paving specifications for use in Texas, New Mexico and Arizona. Paving grades are predominantly sold from April through October for government road projects. Our asphalt blendstocks are shipped to roofing companies and asphalt blenders throughout the United States, including our asphalt blending facility in Bakersfield, California, which we acquired in 2004. In 2005, the Bakersfield facility produced approximately 1,139 bpd of blended asphalt. In 2006, we plan to increase production capacity at the Bakersfield facility by approximately 800 bpd, and we expect blended asphalt sales at our Bakersfield facility to increase in 2006 due to increases in the 2006 California Transportation Department budget.
     We have an exclusive license to use FINA’s asphalt blending technology in West Texas, Arizona, New Mexico and Colorado and a non-exclusive license in Idaho, Montana, Nevada, North Dakota, Utah and Wyoming. Exclusivity under this fully-paid license remains in effect as long as we continue to purchase our rubber modifiers from FINA, although we may purchase rubber modifiers from other sources and maintain such exclusivity if FINA does not provide competitive pricing on these products.
Pipelines and Product Terminals
     We obtain crude oil and distribute refined products through a pipeline and terminal network consisting of approximately 500 miles of crude oil pipelines, nearly 840 miles of product pipelines and six product terminals. These pipelines and terminals allow us to optimize our inventory by allowing us to control the movement and the timing of our refinery’s feedstock supply and the distribution of our refined products. Specifically, this network provides us with the flexibility to (1) access a variety of crude oils, thereby allowing us to optimize our refinery’s crude supply at any given time, (2) efficiently distribute our transportation fuel products to markets in West Texas, Central Texas and Oklahoma and (3) access other markets, including New Mexico and Arizona, through interconnections with third-party transportation systems.

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(MAP)
     Crude Oil and Natural Gas Pipelines. The crude oil pipelines we utilize provide our refinery access to Permian Basin crude oil and foreign and domestic crude oil from the Gulf Coast and consists of the following pipelines:
                 
Crude Oil Pipelines   Status   Miles   Connections
Amdel
  Sunoco Throughput     504     Midland and Nederland
White Oil
  Sunoco Throughput     25     Garden City (Amdel) and Big Spring
Mesa Interconnect
  Owned     4     Mesa pipeline and Big Spring
     The 504 mile bi-directional Amdel pipeline and the 25 mile White Oil pipeline connect our refinery to Nederland, Texas, which is located on the Gulf Coast and to Midland, Texas. Permian Basin crude oil is delivered to our refinery through the four-mile long, 16-inch diameter Mesa Interconnect pipeline which is connected to the Mesa pipeline system, a common carrier. Because prices for WTS and other locally sourced crude oils have been favorable compared to crude oils available from the Gulf Coast over the last four years, we have not utilized our Amdel pipeline for crude oil shipments since December 2002. We recently received notice from the operator of the Mesa system that this pipeline system may cease operations at the end of June 2006 as a result of a dispute among the owners of the system. In order to replace a portion of the crude oil supply available from the Mesa system, should that system cease operations, we intend to re-commence shipping on the Amdel pipeline in June 2006.
     Sunoco Transaction. On March 1, 2006, we sold our Amdel and White Oil crude pipelines, which had been inactive since December 2002, to an affiliate of Sunoco for a total consideration of approximately $68.0 million. In conjunction with the sale of the Amdel and White Oil pipelines, we entered into a 10-year pipeline Throughput and Deficiency Agreement, with an option to extend the agreement by four additional thirty month periods. The Throughput and Deficiency Agreement will allow us to maintain crude oil transportation rights on the pipelines from the Gulf Coast and from Midland, Texas. Pursuant to the Throughput and Deficiency Agreement, we have agreed to ship a minimum of 15,000 barrels per day on the pipelines during the term of the agreement.

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     Our refinery is the closest in proximity to Midland, Texas, which is the largest origination terminal for West Texas crude oil. We believe this location provides us with the lowest transportation cost differential for West Texas crude oil of any refinery. A small amount of locally gathered crude oil is also delivered directly to our refinery. We own a 63% interest in the pipeline that supplies a majority of the natural gas to our refinery.
     Product Pipelines. The product pipelines we utilize are linked to the major third-party product pipelines in the geographic area around our refinery, which provides us flexibility to optimize product flows into multiple regional markets. This product pipeline network can also (1) receive additional transportation fuel products from the Gulf Coast through the Pride Product terminal and Magellan pipelines, (2) deliver and receive products to and from the Magellan system, our connection to the Group III, or mid-continent markets, and (3) deliver products to the New Mexico and Arizona markets through third-party systems. The following table describes the product pipelines which we utilize:
                         
                    Termination
Product Pipelines   Access   Miles   Connections   Date (a)
Chevron(a)
  Lease     38     Coahoma and Midland     2006  
Fin-Tex
  HEP throughput     137     Midland and Orla (Holly)     2020  
Holly
  Lease     133     Orla and El Paso     2018  
Trust
  HEP throughput     332     Big Spring/Abilene/Wichita Falls     2020  
Dyess JP-8
  HEP throughput     2     Abilene and Dyess Air Force Bases     2020  
River
  HEP throughput     47     Wichita Falls and Duncan (Magellan)     2020  
Carswell
  Owned     148     Abilene and Fort Worth     N/A  
 
(a)   The Chevron pipeline description does not include a four-mile pipeline that we own that connects Big Spring and Coahoma. This lease currently expires in December 2006.
     The Chevron, Fin-Tex and Holly pipelines make up the Fin-Tex system. Our access to the Chevron and Holly pipelines is secured by long-term leases, while our access to the Fin-Tex pipeline is provided through our Pipelines and Terminals Agreement with HEP. The Fin-Tex system transports product from our refinery to El Paso, Texas and allows it to be placed in Tucson and Phoenix, Arizona through the third-party Kinder Morgan pipeline. The Fin-Tex system also gives us access to the Albuquerque and Bloomfield, New Mexico markets. We deliver physical barrels to El Paso and receive, through an exchange agreement with Navajo Refining Company, physical barrels in Albuquerque and Bloomfield, New Mexico.
     The Trust pipeline connects our refinery to terminals in Abilene and Wichita Falls, while the River pipeline connects the terminal in Wichita Falls to our Duncan terminal. At Duncan, the River pipeline connects into the Magellan pipeline system for sales into Group III markets. The Trust and River pipeline system is a bi-directional pipeline system which we access through our Pipelines and Terminals Agreement with HEP.
     The Dyess JP-8 pipeline connects the Abilene terminal to Dyess Air Force Base. Our access to this pipeline is also provided through our Pipelines and Terminals Agreement with HEP.
     Our Carswell pipeline system runs from Abilene, Texas to Fort Worth, Texas. The Carswell pipeline is currently inactive.
     Product Terminals. We primarily utilize the following six product terminals, of which three are owned and three are accessed through our Pipelines and Terminal Agreement with HEP:
                     
        Working          
Terminals   Access   Capacity(a)     Supply Source   Mode of Delivery
Big Spring, Texas(b)
  Owned     331     Pipeline/refinery   Pipeline/truck
Abilene, Texas
  HEP     111     Pipeline   Pipeline/truck
Wichita Falls, Texas
  HEP     155     Pipeline   Truck
Duncan, Oklahoma
  Owned(c)     154     Pipeline   Pipeline
Orla, Texas
  HEP     116     Pipeline   Pipeline
Southlake, Texas
  Owned     212     Pipeline   Truck
 
                   
Total
        1,079          
 
                   

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(a)   Measured in thousands of barrels.
 
(b)   Includes the tankage located at our refinery.
 
(c)   The terminal is owned but the underlying real property is leased.
     Five of the six terminals we access are physically integrated with our Big Spring refinery through the product pipelines we utilize. Three of the five terminals in our physically integrated system, Big Spring, Abilene and Wichita Falls, Texas, are also equipped with truck loading racks. The other two terminals in our physically integrated system, Duncan, Oklahoma and Orla, Texas, are used for delivering shipments into third-party pipeline systems. Our Southlake, Texas terminal is located between Fort Worth and Dallas, part of our non-integrated system, and is supplied with purchased or exchanged products. Our Southlake terminal is equipped with a truck loading rack and operates as a wholesale outlet for our distributors in the Dallas/Fort Worth area. We also directly access four other terminals located in Wichita Falls and El Paso, Texas and Tucson and Phoenix, Arizona.
     HEP Transaction. In February 2005, we completed the contribution of certain of our product pipeline and terminal assets to HEP. In exchange for this contribution we received $120 million in cash and 937,500 subordinated Class B limited partnership units in HEP. Simultaneously with this transaction, we entered into a Pipelines and Terminal Agreement with HEP with an initial term of 15 years and three subsequent five year renewal terms exercisable at our sole discretion. Pursuant to the Pipelines and Terminal Agreement, we have agreed to transport and store minimum volumes of refined products in the pipelines and terminals and to pay specified tariffs and fees for such transportation and storage during the term of the agreement. See Note 4 of our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
Retail Segment
     As of December 31, 2005, we operated 167 owned and leased convenience store sites operating primarily in West Texas and New Mexico. Our convenience stores typically offer various grades of gasoline, diesel fuel, food products, tobacco products, non-alcoholic and alcoholic beverages and general merchandise to the public under the 7-Eleven and FINA brand names. Substantially all of the motor fuel sold though our retail segment is supplied by our Big Spring refinery.
     We are one of the top three independent convenience store chains in each of the cities of El Paso, Midland, Odessa, Big Spring and Lubbock, Texas, with approximately 20% of the convenience stores in each city. We also have a significant presence in Wichita Falls, Texas and Albuquerque, New Mexico.
                         
Location   Owned   Leased   Total
Big Spring, Texas
    6       1       7  
El Paso, Texas
    13       36       49  
Lubbock, Texas
    17       5       22  
Midland, Texas
    9       10       19  
Odessa, Texas
    10       25       35  
Wichita Falls, Texas
    8       4       12  
Albuquerque, New Mexico
    12       11       23  
 
                       
Total stores
    75       92       167  
 
                       
     Convenience Store Management and Employees. Each of our stores has a store manager who supervises a staff of full-time and part-time employees. The number of employees at each convenience store varies based on the store’s size, sales volume and hours of operation. Typically, a geographic group of six to 10 stores is managed by a supervisor who reports to a district manager. Five district managers are responsible for a varying number of stores depending on the geographic size of each market and the experience of each district manager. These district managers report to our retail management headquarters in Odessa, Texas. Our retail segment’s headquarters, located in Odessa, Texas, consists of 45 employees.
     Distribution and Supply. The merchandise requirements of our convenience stores are serviced at least weekly by over 100 direct-store delivery, or DSD, vendors. In order to minimize costs and facilitate deliveries, we utilize a single wholesale distributor, McLane Company Inc., for non-DSD products. We purchase the products

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from McLane at cost plus an agreed upon percentage mark-up. Our current contract with McLane expires at the end of November 2006. We purchase approximately 55% to 60% of our merchandise for resale from McLane. We typically do not have contracts with our DSD vendors.
     7-Eleven License Agreement. We are party to a license agreement with 7-Eleven, Inc., which gives us a license to use the 7-Eleven trademark, service name and trade name in connection with our convenience store operations in West Texas and a majority of the counties in New Mexico. This license agreement may be terminated by 7-Eleven if we fail to perform our obligations under the agreement.
     Technology and Store Automation. We are in the process of installing a point of sale checkout system for our convenience stores. This system includes scanning, pump control, peripheral device integration and daily operations reporting. This system will enhance our ability to offer a greater variety of promotions with a high degree of flexibility with regard to definition (store, group of stores, region, etc.) and duration. We will also be able to receive enhanced management reports that will assist our decision-making processes. We believe this system will allow our convenience store managers to spend less time preparing reports and more time analyzing these reports to improve convenience store operations. This system also includes shortage-control tools. This system will be used as the platform to support other marketing technology projects, including interactive video at the pump and bar code coupons at the pump.
Competition
     The petroleum refining and marketing industry continue, to be highly competitive. Many of our principal competitors are integrated, multi-national oil companies (e.g., Valero, Chevron, ExxonMobilShell and ConocoPhillips) and other major independent refining and marketing entities that operate in our market areas. Because of their diversity, integration of operations and larger capitalization, these major competitors may have greater financial and other resources and may have a greater ability to bear the economic risks and volatile market conditions associated with the petroleum industry. Financial returns in the refining and marketing industry depend on the difference between refined product prices and the prices for crude oil and other feedstock, also referred to as refining margins. Refining margins are impacted by among other things, levels of crude and refined product inventories, balance of supply and demand, utilization rates of refineries and global economic and political events.
     All of our crude oil and feedstocks are purchased from third-party sources, while some of our competitors have proprietary sources of crude available for their own refineries. However, as our refinery is in close proximity to Midland, Texas, which is the largest origination terminal for West Texas crude oil, we believe that our location provides us with transportation cost advantages over many of our competitors. The Amdel pipeline provides us with supply alternatives through access to Gulf Coast and foreign crude oils.
     The majority of our refined fuel products are shipped to wholesale distributors within our principal geographic regions of West Texas, Central Texas, Oklahoma, New Mexico and Arizona or to our retail sites within West Texas and New Mexico. Production in excess of our wholesale and retail sales is sold on the spot market and either shipped northeast via the Trust and River pipeline system to distribution points in North Texas and Oklahoma or west via the Fin-Tex pipeline system to El Paso, Texas and distribution points in New Mexico and Arizona. The market for refined products in these regions is also supplied by a number of refiners, including large integrated oil companies or independent refiners that either have refineries located in the regions or have pipeline access to these regions. These larger companies typically have greater resources and may have greater flexibility in responding to volatile market conditions or absorbing market changes. The principal competitive factors affecting our wholesale marketing business are price and quality of products, reliability and availability of supply and location of distribution points.
     The Longhorn pipeline runs approximately 700 miles from the Houston area of the Gulf Coast to El Paso and has an estimated maximum capacity of 225,000 bpd. This pipeline provides Gulf Coast refiners and other shippers with improved access to markets in West Texas and New Mexico. We anticipate that any additional supply provided by this pipeline will lower prices and increase price volatility in El Paso and could adversely affect our sales and profitability in this market. We do not expect our remaining shipments of refined products to be affected, since they are shipped directly for distribution through our retail segment or to other FINA

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branded customers or are exchange paybacks for sales in the Albuquerque and Bloomfield, New Mexico, markets to which the Longhorn pipeline does not have access.
     Our major retail competitors include Valero, Chevron, ConocoPhillips and Shell. The principal competitive factors affecting our retail segment are location of stores, product price and quality, appearance and cleanliness of stores and brand identification. We expect to continue to face competition from large, integrated oil companies, as well as from other convenience stores that sell motor fuels. Increasingly, grocery and dry goods retailers such as Albertson’s, Wal-Mart and HEB, a Texas-based regional grocer, are entering the motor fuel retailing business. Many of these competitors are substantially larger than we are. Because of their diversity, integration of operations and greater resources, these companies may be better able to withstand volatile market conditions and lower profitability as a result of competitive pricing and lower operating costs.
     We compete with Valero, Chevron, Holly and Paramount in the regional asphalt market. The principal factors affecting competitiveness in asphalt markets are consistency of product quality, transportation cost and capability to produce the range of high performance products necessary to meet the requirements of customers.
Government Regulation and Legislation
Environmental Controls and Expenditures
     Our operations are subject to extensive and frequently changing federal, state, regional and local laws, regulations and ordinances relating to the protection of the environment, including those governing emissions or discharges to the air and water, the handling and disposal of solid and hazardous waste and the remediation of contamination. While we believe our operations are generally in substantial compliance with current requirements, over the next several years our operations will have to meet new requirements being promulgated by the U.S. Environmental Protection Agency (“EPA”) and the states and jurisdictions in which we operate.
     Environmental Expenditures. The EPA regulations related to the Clean Air Act require significant reductions in the sulfur content in gasoline and diesel fuel. These regulations required most refineries to reduce sulfur content in gasoline to 30 ppm by January 1, 2004. The regulations allow small refiners to meet the 30 ppm gasoline standard by January 2008, or January 2011 if the small refiner implements the new diesel sulfur content standard of 15 ppm by June 1, 2006, which we intend to do. Otherwise, the new diesel standard allows small refiners to delay implementation of the 15 ppm standard until June 1, 2010. We have been certified by the EPA as a small refiner for both gasoline and diesel. We could lose our small refiner certification if, as the result of a merger or acquisition, we employ more than 1,500 employees or increase our production capacity to more than 155,000 bpd. We anticipate that the new gasoline and diesel standards will require capital expenditures of approximately $25.3 million through 2010, of which approximately $9.9 million is expected to be spent in 2006. If we lose our status as a small refiner, we would be required to incur the capital expenditures for the gasoline and diesel standards at an earlier date than would otherwise be required for a small refiner.
     As of December 31, 2005, we had substantially completed our expenditures required for compliance with the Voluntary Emissions Reduction Program, or VERP, sponsored by the Texas Commission on Environmental Quality, or TCEQ, including regulations establishing Maximum Achievable Control Technologies for petroleum refineries, or MACT II.
     Conditions may develop that cause additional future capital expenditures at our refinery, product terminals and retail gasoline stations (operating and closed locations) for compliance with the Federal Clean Air Act and other federal, state and local requirements. We cannot currently determine the amounts of such future expenditures.
     Remediation Efforts. We are currently investigating and remediating historical soil and groundwater contamination at our Big Spring refinery pursuant to a compliance plan issued by the TCEQ. The compliance plan requires us to investigate and, if necessary, remediate fifty-nine potentially contaminated areas on our refinery property. We expect to complete the investigation of these areas by the end of 2006.

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     The compliance plan also requires us to monitor and treat contaminated groundwater at our Big Spring refinery and some of our terminals, which is currently underway. We estimate that we will be required to spend approximately $4.7 million with respect to the investigation and remediation of our Big Spring refinery and our terminals. The costs incurred to comply with the compliance plan are covered, with certain limitations, by an environmental indemnity provided by FINA, which we discuss below.
     In addition, we operate convenience stores with underground gasoline and diesel fuel storage tanks in various states. Compliance with federal and state regulations that govern these storage tanks can be costly. The operation of underground storage tanks also poses various risks, including soil and groundwater contamination. We are currently investigating and remediating leaks from underground storage tanks at some of our convenience stores, and it is possible that we may identify more leaks or contamination in the future that could result in fines or civil liability for us. We have established reserves in our financial statements in respect of these matters to the extent that the associated costs are both probable and reasonably estimable. We cannot assure you, however, that these reserves will prove to be adequate.
     Environmental Indemnity from FINA. In connection with the acquisition of our Big Spring refinery and other operating assets from FINA in August 2000, FINA agreed, within prescribed limitations, to indemnify us against costs incurred in connection with any remediation that is required as a result of environmental conditions that existed on the acquired properties prior to the closing date of our acquisition. FINA’s indemnification obligations for these remediation costs run through August 2010, have a ceiling of $5.0 million per year (with carryover of unused ceiling amounts and unreimbursed environmental costs into subsequent years) and have an aggregate indemnification cap of $20.0 million. Thereafter, we are solely responsible for all additional remediation costs. As of December 31, 2005, the remediation of the properties is on schedule, and we have expended approximately $12.3 million in connection with that remediation and approximately $3.0 million in environmental insurance premiums, all of which has been covered by the FINA indemnity. Subject to a $25,000 deductible per claim up to an aggregate deductible of $2.0 million, FINA is additionally obligated to indemnify us for third-party claims with respect to environmental matters received by us within ten years of the closing date to the extent such matters relate to FINA’s operations on the acquired properties prior to the closing date. FINA is further obligated to indemnify us for environmental fines imposed as a result of FINA’s operations on the acquired properties prior to the closing date, provided that such claims are asserted no later than the earlier of ten years from the closing date and the date that the applicable statute of limitations expires. FINA’s aggregate indemnification obligations for environmental fines and third-party claims are not subject to a monetary cap. Excluding liabilities retained by FINA as described above, we assumed the environmental liabilities associated with the acquired properties and agreed to indemnify FINA for any environmental claims or costs in connection with our operations at the acquired properties after the closing date.
     Environmental Insurance. We have also purchased two environmental insurance policies to cover expenditures not covered by the FINA indemnification agreement, the premiums for which have been prepaid in full. Under an environmental clean-up cost containment, or cost cap, policy, we are insured for remediation costs for known conditions at the time of our acquisition of our assets from FINA. This policy has a $20.0 million deductible during the first ten years after the acquisition (coinciding with the FINA indemnity) and a $1.0 million annual deductible for the remainder of the term of the policy. Under an environmental response, compensation and liability insurance policy, or ERCLIP, we are covered for bodily injury, property damage, clean-up costs, legal defense expenses and civil fines and penalties relating to unknown conditions and incidents. The ERCLIP policy is subject to a $1.0 million sublimit on liability for civil fines and penalties and a deductible of $150,000, or $100,000 in the case of civil fines or penalties, per incident. Both the cost cap and ERCLIP policies have a term of twenty years and share a maximum aggregate coverage of $40.0 million. The insurer under these policies is The Kemper Insurance Companies, which has experienced significant downgrades of its credit ratings in recent years. Our insurance broker has advised us that environmental insurance policies with terms in excess of ten years are not currently generally available and that policies with shorter terms are available only at premiums substantially in excess of the premiums paid for our policies with Kemper.
     Environmental Indemnity to HEP. In connection with the HEP transaction, we entered into an Environmental Agreement with HEP pursuant to which we agreed to indemnify HEP against costs and liabilities incurred by HEP to the extent resulting from the existence of environmental conditions at the pipelines or terminals prior to February 28, 2005 or from violations of environmental laws with respect to the pipelines and terminals

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occurring prior to February 28, 2005. Our environmental indemnification obligations under the Environmental Agreement expire after February 28, 2015. In addition, our indemnity obligations are subject to HEP first incurring $0.1 million of damages as a result of pre-existing environmental conditions or violations. Our environmental indemnity obligations are further limited to an aggregate indemnification amount of $20.0 million, including any amounts paid by us to HEP with respect to indemnification for breaches of our representations and warranties under the Contribution Agreement.
     With respect to any remediation required for environmental conditions existing prior to February 28, 2005, we have the option under the Environmental Agreement to perform such remediation ourselves in lieu of indemnifying HEP for their costs of performing such remediation. Pursuant to this option, we are continuing to perform the ongoing remediation at the Wichita Falls terminal which is subject to our environmental indemnity from FINA. Any remediation required under the terms of the Environmental Agreement is limited to the standards under the applicable environmental laws as in effect at February 28, 2005.
     Environmental Indemnity to Sunoco. In connection with the sale of the Amdel and White Oil crude pipelines, which had been inactive since December 2002, we entered into a Purchase and Sale Agreement with Sunoco pursuant to which we agreed to indemnify Sunoco against costs and liabilities incurred by Sunoco to the extent resulting from the existence of environmental conditions at the pipelines prior to March 1, 2006 or from violations of environmental laws with respect to the pipelines occurring prior to March 1, 2006. With respect to any remediation required for environmental conditions existing prior to March 1, 2006, we have the option under the Purchase and Sale Agreement to perform such remediation ourselves in lieu of indemnifying Sunoco for their costs of performing such remediation.
Other Government Regulation
     The pipelines owned or operated by us are regulated by Department of Transportation rules and our intrastate pipelines are regulated by the Texas Railroad Commission. Within the Texas Railroad Commission, the Pipeline Safety Section of the Gas Services Division administers and enforces the federal and state requirements on our intrastate pipelines. All of our pipelines within Texas are permitted and certified by the Texas Railroad Commission’s Gas Services Division.
     Both the State of Texas and the Federal Department of Transportation have recently promulgated new regulations on pipeline safety. These regulations require pipelines that are located in populated or environmentally sensitive areas to prepare and implement a program for managing the integrity of these pipelines, including the repair of any defects identified as a result of ongoing pipeline integrity assessments. We estimate that compliance with these new regulations will require us to invest $1.2 million over the next five years.
     The petroleum Marketing Act, or PMPA, is a federal law that governs the relationship between a refiner and a distributor pursuant to which the refiner permits a distributor to use a trademark in connection with the sale or distribution of motor fuel. We are subject to the provisions of the PMPA because we sublicense the FINA brand to our distributors in connection with their distribution and sale of motor fuels. The PMPA provides that we may not terminate or fail to renew our distributor contracts unless certain enumerated preconditions or grounds for termination or nonrenewal are met and we also comply with the prescribed notice requirements. The PMPA provides that our distributors may enforce the provisions of the act through civil actions against us. If we terminate or fail to renew one or more of our distributor contracts in the absence of the specific grounds permitted by the PMPA, or fail to comply with the prescribed notice requirements in effecting a termination or nonrenewal, those distributors may file lawsuits against us to compel continuation of their contracts or to recover damages from us.
Employees
     As of December 31, 2005, we had approximately 1,415 employees. Approximately 250 employees worked in our refining and marketing segment, of which 170 were employed at our refinery and approximately 80 were employed at our corporate offices in Dallas, Texas. Approximately 120 of the 170 employees at our refinery are covered by collective bargaining agreements that expire on March 31, 2006. Approximately 1,165 employees worked in our retail segment. None of the employees in our retail segment or in our corporate offices are represented by a union. We consider our relations with our employees to be satisfactory.

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Properties
     Our principal properties are described above under the captions “Refining and Marketing Segment” and “Retail Segment” in Item 1. We believe that our facilities are generally adequate for our operations and are maintained in a good state of repair. As of December 31, 2005 we were the lessee under a number of cancelable and non-cancelable leases for certain properties. Our leases are discussed more fully in Note 19 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
Executive Officers of the Registrant
     Our current executive officers and key employees, their ages as of January 31, 2006, and their business experience during at least the past five years are set forth below.
             
Name   Age   Position
David Wiessman
    51     Executive Chairman of the Board of Directors
Jeff D. Morris
    54     Director, President and Chief Executive Officer
Claire A. Hart
    50     Senior Vice President
Shai Even
    37     Vice President, Chief Financial Officer and Treasurer
Joseph A. Concienne
    55     Vice President of Refining and Transportation
Jimmy C. Crosby
    46     Vice President of Supply and Planning
Joseph Israel
    34     Vice President of Mergers and Acquisitions
Harlin R. Dean
    39     Vice President, General Counsel and Secretary
Joseph Lipman
    60     President and Chief Executive Officer of SCS
     Set forth below is a brief description of the business experience of each of our executive officers and key employees listed above. Prior to our initial public offering, our executive officers, other than Messrs. Wiessman and Dean, served with our wholly-owned subsidiary, Alon USA, Inc., which has historically managed our operations. In May 2005, in contemplation of our initial public offering, each of the executive officers of Alon USA, Inc., was elected to the same office or appointed to the same position with Alon USA Energy, Inc. in which he served with Alon USA, Inc.
     David Wiessman has served as Executive Chairman of the Board of Directors of Alon since July 2000 and served as President and Chief Executive Officer of Alon USA Energy, Inc. from its formation in 2000 until May 2005. Mr. Wiessman has over 25 years of oil industry and marketing experience. Since 1994, Mr. Wiessman has been Chief Executive Officer, President and a director of Alon Israel. In 1992, Bielsol Investments (1987) Ltd. acquired a 50% interest in Alon Israel. In 1987, Mr. Wiessman became Chief Executive Officer of, and a stockholder in, Bielsol Investments (1987) Ltd., a sister company of Bielsol Ltd. In 1976, after serving in the Israeli Air Force, he became Chief Executive Officer of Bielsol Ltd., a privately owned Israeli company that owns and operates gasoline stations and owns real estate in Israel. Mr. Wiessman is also Chairman of the Board of Directors of Blue Square Israel, Ltd., which is listed on the New York Stock Exchange and the Tel Aviv Stock Exchange, and Deputy Chairman of the Board of Directors of Blue Square Chain Properties and Investments, Ltd., which is listed on the New York Stock Exchange and the Tel Aviv Stock Exchange. Mr. Wiessman also has served as Chairman of the Board and President of Dor Alon Energy, the energy segment of the Alon Group in Israel, since January 2005.
     Jeff D. Morris has served as a director and as our President and Chief Executive Officer since May 2005 and has served as the President and Chief Executive Officer of our subsidiary Alon USA since its inception in August 2002 and of our other operating subsidiaries since July 2000. Prior to joining Alon, he held various positions at FINA, where he began his career in 1974. Mr. Morris served as Vice President of FINA’s SouthEastern Business Unit from 1998 to 2000 and as Vice President of its SouthWestern Business Unit from 1995 to 1998. In these capacities, he was responsible for both the Big Spring refinery and FINA’s Port Arthur refinery and had responsibility for crude gathering assets and marketing activities for both business units.
     Claire A. Hart has served as our Senior Vice President since January 2004 and served as our Chief Financial Officer and Vice President from August 2000 to January 2004. Prior to joining Alon, he held various positions in the Finance, Accounting and Operations departments of FINA for 13 years, serving as Treasurer from 1998 to August 2000 and as General Manager of Credit Operations from 1997 to 1998.

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     Shai Even has served as a Vice President since May 2005, as our Chief Financial Officer since December 2004 and as our Treasurer since August 2003. Prior to joining Alon, Mr. Even served as the Chief Financial Officer of DCL Technologies, Ltd. from 1996 to July 2003 and prior to that worked for KPMG from 1993 to 1996.
     Joseph A. Concienne has served as our Vice President of Refining and Transportation since March 2001. His primary role is as site manager for our Big Spring refinery. Prior to joining Alon, Mr. Concienne served as Director of Operations/General Manager for Polyone Corporation in Seabrook, Texas from 1998 to 2001. He served as Vice President/General Manager for Valero Refining and Marketing, Inc. in 1998 and as Manager of Refinery Operations and Refinery Manager for Phibro Energy Refining, which became Valero Refining and Marketing, Inc. in 1998, from 1985 to 1998.
     Jimmy C. Crosby has served as our Vice President of Supply and Planning since March 2005, with responsibility for all terminal and refinery supply for our marketing and refinery operations. Mr. Crosby served as our General Manager of Business Development and Planning from August 2000 to March 2005. Prior to joining Alon, Mr. Crosby worked with FINA from 1996 to August 2000 where he last held the position of Manager of Planning and Economics for the Big Spring refinery.
     Joseph Israel has served as our Vice President of Mergers & Acquisitions since March 2005. Mr. Israel served as our General Manager of Economics and Commerce from September 2000 to March 2005. Prior to joining Alon, Mr. Israel held positions with several Israeli government entities beginning in 1998, including the Israeli Land Administration, the Israeli Fuel Administration and most recently as Commerce Vice President of Israel’s Petroleum Energy Infrastructure entity.
     Harlin R. Dean has served as our General Counsel and Secretary since October 2002 and as Vice President since May 2005. Prior to joining Alon, Mr. Dean practiced corporate and securities laws, with a focus on public and private merger and acquisition transactions and public securities offerings, at Brobeck, Phleger & Harrison LLP, from April 2000 to September 2002, and at Weil, Gotshal & Manges, L.L.P., from September 1992 to March 2000.
     Joseph Lipman has served as President and Chief Executive Officer of Southwest Convenience Stores, LLC., or SCS, our subsidiary conducting our Retail operations since July 2001. From 1997 to July 2001, Mr. Lipman served as General Manager of Cosmos, a chain of supermarkets in Israel owned by Super-Sol Ltd., where he was responsible for marketing and store operations. Mr. Lipman also held general managerial posts at Tuoro College, in Jerusalem in 1997.
ITEM 1A. RISK FACTORS.
     You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report on Form 10-K or in any other of our filings with the SEC could have a material adverse effect on our business, financial position, results of operations and cash flows. In evaluating us, you should consider carefully, among other things, the factors and the specific risks set forth below. This annual report contains forward-looking statements that involve risks and uncertainties. See “Forward-Looking Statements” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of the factors that could cause actual results to differ materially from those projected.
The price volatility of crude oil, other feedstocks, refined products and fuel and utility services may have a material adverse effect on our earnings, profitability and cash flows.
     Our refining and marketing earnings, profitability and cash flows from operations depend on the margin above fixed and variable expenses (including the cost of refinery feedstocks, such as crude oil) at which we are able to sell refined products. We enjoyed historically high refining margins throughout 2005. However, refining margins historically have been volatile, and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services. Prices of crude oil, other feedstocks and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline and other refined products. Such supply and demand are affected by, among other things:

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    changes in global and local economic conditions;
 
    domestic and foreign demand for fuel products;
 
    worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa and Venezuela;
 
    the level of foreign and domestic production of crude oil and refined products and the level of crude oil, feedstock and refined products imported into the U.S.;
 
    utilization rates of U.S. refineries;
 
    development and marketing of alternative and competing fuels;
 
    U.S. government regulations; and
 
    local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our markets.
     If the margin between refined product prices and crude oil and other feedstock prices contracts, it could negatively affect our earnings and profitability.
     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. Our inventory is valued at the lower of cost or market value under the LIFO inventory valuation methodology; therefore, if the market value of our inventory were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of sales.
     In addition, the volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refinery and other operations affect our operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Future increases in fuel and utility prices may have a negative effect on our results of operations.
Our profitability is linked to the sweet/sour crude oil price spread, which increased significantly in 2005. A decrease in this spread could negatively affect our profitability.
     Our profitability is linked to the price spread between sweet crude oil and sour crude oil, which we refer to as the sweet/sour spread. We prefer to refine sour crude oils because they have historically provided wider refining margins than sweet crude oils. During 2005, relatively high demand for sweet crude oils due to increasing demand for lower sulfur fuels resulted in a wider sweet/sour spread. However, a tightening of the sweet/sour spread could adversely affect our profitability, particularly if there is a worldwide softening of product demand that lessens the demand for sweet crude oils.
The dangers inherent in our operations could cause disruptions and could expose us to potentially significant losses, costs or liabilities. We are particularly vulnerable to disruptions in our operations because all of our refining operations are conducted at a single facility.
     Our operations are subject to significant hazards and risks inherent in refining operations and in transporting and storing crude oil, intermediate products and refined products. These hazards and risks include, but are not limited to, natural disasters, fires, explosions, pipeline ruptures and spills, third party interference and mechanical failure of equipment at our or third-party facilities, any of which could result in production and distribution difficulties and disruptions, environmental pollution, personal injury or wrongful death claims and other damage to our properties and the properties of others.
     Because all of our refining operations are conducted at a single refinery, any such events at our refinery could significantly disrupt our production and distribution of refined products, and any sustained disruption could have a material adverse effect on our business, financial condition and results of operations.

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We are subject to interruptions of supply as a result of our reliance on pipelines for transportation of crude oil and refined products.
     Our refinery receives substantially all of its crude oil and delivers a substantial percentage of its refined products through pipelines. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, governmental regulation, terrorism, other third-party action or any of the types of events described in the preceding risk factor. Our prolonged inability to use any of the pipelines that we use to transport crude oil or refined products could have a material adverse effect on our business, financial condition and results of operations.
     In January 2006, we received notice from the operator of the Mesa Pipeline (“Mesa”) system, which currently supplies over 90% of our Big Spring refinery’s crude oil requirements, that operations of this system may cease on June 30, 2006 due to a dispute among the owners of the system. While we have begun to implement plans for alternative sources of supply should a shut down of this system occur, any disruption of supply resulting from a cessation of operations of the Mesa system could cause us to be unable to operate the Big Spring refinery at full capacity, which would negatively affect our profitability and cash flows.
If the price of crude oil increases significantly, it could limit our ability to purchase enough crude oil to operate our refinery at full capacity.
     We rely in part on borrowings and letters of credit under our revolving credit facility to purchase crude oil for our refinery. If the price of crude oil increases significantly, we may not have sufficient capacity under our revolving credit facility to purchase enough crude oil to operate our refinery at full capacity. A failure to operate our refinery at full capacity could adversely affect our profitability and cash flows.
Changes in our credit profile could affect our relationships with our suppliers, which could have a material adverse effect on our liquidity and our ability to operate our Big Spring refinery at full capacity.
     Changes in our credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms of their invoices with us. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our creditors of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This in turn could cause us to be unable to operate our Big Spring refinery at full capacity. A failure to operate our refinery at full capacity could adversely affect our profitability and cash flows.
Covenants and events of default in our debt instruments could limit our ability to undertake certain types of transactions and adversely affect our liquidity.
     Our revolving credit agreement dated February 15, 2006, contains negative and financial covenants and events of default that may limit our financial flexibility and ability to undertake certain types of transactions. For instance, we are subject to negative covenants that restrict our activities, including restrictions on creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, providing guaranties, engaging in different businesses, making loans and investments, entering into certain lease obligations, making certain capital expenditures, making certain dividend, debt and other restricted payments, in each case, based on certain financial covenants, compromising or adjusting receivables, engaging in certain transactions with affiliates and amending or waiving certain material agreements. We are also subject to financial covenants that require us to maintain specified financial ratios and to satisfy other financial tests. In addition, under our revolving credit facility, a change of control will be deemed to occur, if Alon Israel ceases to have the power to exercise, directly or indirectly, a controlling influence over our management or policies or cease to own and control at least 25% of the aggregate voting power represented by our outstanding capital stock. If we fail to satisfy the covenants set forth in our revolving credit facility or another event of default occurs under this facility, the maturity of the loan could be accelerated or we could be prohibited from borrowing for our working capital needs. If our borrowings are accelerated and we do not have sufficient cash on hand to pay all amounts due, we could be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all. If we cannot borrow under the revolving credit facility, we would need to seek additional financing, if available, or curtail our operations.

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Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.
     We compete with a broad range of companies in our refining and marketing operations. Many of these competitors are integrated, multinational oil companies that are substantially larger than we are. Because of their diversity, integration of operations, larger capitalization, larger and more complex refineries and greater resources, these companies may be better able to withstand volatile market conditions, to compete on the basis of price and to obtain crude oil in times of shortage.
     The Longhorn pipeline runs approximately 700 miles from the Houston area of the Gulf Coast to El Paso and has an estimated maximum capacity of 225,000 bpd. This pipeline provides Gulf Coast refiners and other shippers with improved access to markets in West Texas and New Mexico. We anticipate that any additional supply provided by this pipeline will lower prices and increase price volatility in the El Paso market and could adversely affect our sales and profitability in this market.
Competition in the retail industry is intense, and an increase in competition in the markets in which our retail businesses operate could adversely affect our earnings and profitability.
     Our retail operations compete with numerous convenience stores, gasoline service stations, supermarket chains, drug stores, fast food operations and other retail outlets. Increasingly, high-volume grocery and dry-goods retailers, such as Albertson’s, Wal-Mart and HEB are entering the gasoline retailing business. Many of these competitors are substantially larger than we are. Because of their diversity, integration of operations and greater resources, these companies may be better able to withstand volatile market conditions or levels of low or no profitability in the retail segment. In addition, these retailers may use promotional pricing or discounts, both at the pump and in the store, to encourage in-store merchandise sales. These activities by our competitors could adversely affect our profit margins. Additionally, our convenience stores could lose market share, relating to both gasoline and merchandise, to these and other retailers, which could adversely affect our sales and profitability.
     Our convenience stores compete in large part based on their ability to offer convenience to customers. Consequently, changes in traffic patterns and the type, number and location of competing stores could result in the loss of customers and reduced sales and profitability at affected stores.
We may incur significant costs to comply with new or changing environmental laws and regulations.
     Our operations are subject to extensive regulatory controls on air emissions, water discharges, waste management and the clean-up of contamination that can require costly compliance measures. We anticipate that compliance with new regulations lowering the permitted level of sulfur in gasoline and highway diesel fuel will require us to spend approximately $25.3 million through 2010. Actual costs could, however, significantly exceed current estimates, and we may be required to incur such costs at an earlier date than planned, particularly if we were to lose our small refiner status. If we fail to meet environmental requirements, we may be subject to administrative, civil and criminal proceedings by state and federal authorities, as well as civil proceedings by environmental groups and other individuals, which could result in substantial fines and penalties against us as well as governmental or court orders that could alter, limit or stop our operations.
     In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. We are not able to predict the impact of new or changed laws or regulations or changes in the ways that such laws or regulations are administered, interpreted or enforced. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. To the extent that the costs associated with meeting any of these requirements are substantial and not adequately provided for, our earnings and cash flows could suffer.
We may incur significant costs and liabilities with respect to environmental lawsuits and proceedings and any investigation and remediation of existing and future environmental conditions.
     We are currently investigating and remediating, in some cases pursuant to government orders, soil and groundwater contamination at our refinery, terminals and convenience stores. Since August 2000, we have spent

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approximately $12.3 million with respect to the investigation and remediation of our Big Spring refinery and our terminals. We anticipate spending an additional $4.7 million in investigation and remediation expenses over the next five years. There can be no assurances, however, that we will not have to spend more than this amount. Our handling and storage of petroleum and hazardous substances may lead to additional contamination at our facilities and facilities to which we send or sent wastes or by-products for treatment or disposal, in which case we may be subject to additional cleanup costs, governmental penalties, and third-party suits alleging personal injury and property damage. Although we have sold three of our pipelines and three of our terminals pursuant to the HEP transaction and two of our pipelines pursuant to the Sunoco transaction, we have agreed, subject to certain limitations, to indemnify HEP and Sunoco for costs and liabilities that may be incurred by them as a result of environmental conditions existing at the time of the sale. See Items 1 and 2 “Business and Properties — Government Regulation and Legislation — Environmental Indemnity to HEP and — Environmental Indemnity to Sunoco.” If we are forced to incur costs or pay liabilities in connection with such proceedings and investigations, such costs and payments could be significant and could adversely affect our profitability.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
     From time to time, we have been sued or investigated for alleged violations of health, safety, environmental and other laws. If a lawsuit or enforcement proceeding were commenced or resolved against us, we could incur significant costs and liabilities. In addition, our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our earnings and cash flows.
Our insurance policies do not cover all losses, costs or liabilities that we may experience.
     We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage does not apply unless a business interruption exceeds 45 days. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
We are exposed to risks associated with the credit-worthiness of our insurers.
     The insurer under three of our environmental policies is The Kemper Insurance Companies, which has experienced significant downgrades of its credit ratings in recent years. Of these three policies, two are 20-year policies that were purchased to protect us against expenditures not covered by our indemnification agreement with FINA, and the third policy is a ten-year policy covering our operations subsequent to our acquisition from FINA. Our insurance brokers have advised us that environmental insurance policies with terms in excess of ten years are not currently generally available and that policies with shorter terms are available only at premiums substantially in excess of the premiums paid for our policies with Kemper. Accordingly, we are currently subject to the risk that Kemper will be unable to comply with its obligations under these policies and that comparable insurance may not be available or, if available, only at substantially higher premiums than our current premiums with Kemper.
If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively impacted.
     Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel. We do not currently maintain key man life insurance with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel would be unavailable to us for any reason, we would be required to hire other personnel to manage and operate our company and to develop our

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products and technology. We cannot assure you that we would be able to locate or employ such qualified personnel on acceptable terms or at all.
A substantial portion of our refining workforce is unionized, and we may face labor disruptions that would interfere with our operations.
     As of December 31, 2005, we employed approximately 170 people at our refinery, approximately 120 of whom were covered by a collective bargaining agreement. The collective bargaining agreement expires March 31, 2006. We may not be able to renegotiate our collective bargaining agreement on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreement may not prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse affect on our results of operation and financial condition.
We conduct our convenience store business under a license agreement with 7-Eleven, and the loss of this license could adversely affect the results of operations of our retail segment.
     All of our convenience store operations are currently conducted under the 7-Eleven name pursuant to a license agreement between 7-Eleven, Inc. and us. 7-Eleven may terminate the agreement if we default on our obligations under the agreement. This termination would result in our convenience stores losing the use of the 7-Eleven brand name, the accompanying 7-Eleven advertising and certain other brand names used exclusively by 7-Eleven. Termination of the license agreement could have a material adverse affect on our convenience store operations.
We may not be able to successfully execute our strategy of growth through acquisitions.
     A component of our growth strategy is to selectively acquire refining and marketing assets and retail assets in order to increase cash flow and earnings. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth and many other factors beyond our control. Risks associated with acquisitions include those relating to:
    diversion of management time and attention from our existing business;
 
    challenges in managing the increased scope, geographic diversity and complexity of operations;
 
    difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;
 
    liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;
 
    greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for investments to improve operating results;
 
    difficulties in achieving anticipated operational improvements;
 
    incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and
 
    issuance of additional equity, which could result in further dilution of the ownership interest of existing stockholders.
     We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.
Terrorist attacks, threats of war or actual war may negatively affect our operations, financial condition, results of operations and prospects.
     Terrorist attacks, threats of war or actual war, as well as events occurring in response to or in connection with them, may adversely affect our operations, financial condition, results of operations and prospects. Energy-related assets (which could include refineries, terminals and pipelines such as ours) may be at greater risk of future

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terrorist attacks than other possible targets in the United States. A direct attack on our assets or assets used by us could have a material adverse effect on our operations, financial condition, results of operations and prospects. In addition, any terrorist attack, threats of war or actual war could have an adverse impact on energy prices, including prices for our crude oil and refined products, and an adverse impact on the margins from our refining and marketing operations. In addition, disruption or significant increases in energy prices could result in government-imposed price controls.
If the price of crude oil increases significantly, it could reduce our profit on our fixed-price asphalt supply contracts.
     We enter into fixed-price supply contracts pursuant to which we agree to deliver asphalt to customers at future dates. We set the pricing terms in these agreements based, in part, upon the price of crude oil at the time we enter into each contract. If the price of crude oil increases from the time we enter into the contract to the time we produce the asphalt, our profits from these sales could be adversely affected.
Our operating results are seasonal and generally lower in the first and fourth quarters of the year.
     Demand for gasoline and asphalt products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. Seasonal fluctuations in highway traffic also affect motor fuels and merchandise sales in our retail stores. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year.
We depend upon our subsidiaries for cash to meet our obligations and pay any dividends, and we do not own 100% of the stock of our operating subsidiaries.
     We are a holding company. Our subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or pay dividends to our stockholders depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends, tax sharing payments or otherwise. Our subsidiaries’ ability to make any payments will depend on their earnings, the terms of their indebtedness, tax considerations and legal restrictions.
     Three of our executive officers, Messrs. Morris, Hart and Concienne, own shares of non-voting stock of two of our subsidiaries, Alon Assets, Inc., or Alon Assets and Alon USA Operating, Inc., or Alon Operating. As of March 1, 2006, the shares owned by these executive officers represent 5.32% of the aggregate equity interest in these subsidiaries. In addition, these executive officers hold options vesting through 2010 which, if exercised, could increase their aggregate ownership to 8.34% of Alon Assets and Alon Operating. To the extent these two subsidiaries pay dividends to us, Messrs. Morris, Hart and Concienne will be entitled to receive pro rata dividends based on their equity ownership. For additional information, see Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”
     Messrs. Morris, Hart and Concienne are parties to stockholders’ agreements with Alon Assets and Alon Operating, pursuant to which we may elect or be required to purchase their shares in connection with put/call rights or rights of first refusal contained in those agreements. The purchase price for the shares is generally determined pursuant to certain formulas set forth in the stockholders’ agreements, but after July 31, 2010, the purchase price, under certain circumstances involving a termination of, or resignation from, employment would be the fair market value of the shares. For additional information, see Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”

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It may be difficult to serve process on or enforce a United States judgment against certain of our directors.
     All of our directors, other than Messrs. Ron Haddock and Jeff Morris, reside outside the United States. In addition, a substantial portion of the assets of these directors are located outside of the United States. As a result, you may have difficulty serving legal process within the United States upon any of these persons. You may also have difficulty enforcing, both in and outside the United States, judgments you may obtain in United States courts against these persons in any action, including actions based upon the civil liability provisions of United States federal or state securities laws. Furthermore, there is substantial doubt that the courts of the State of Israel would enter judgments in original actions brought in those courts predicated on United States federal or state securities laws.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
     None.
ITEM 3. LEGAL PROCEEDINGS.
     In the ordinary conduct of our business, we are subject to periodic lawsuits, investigations and claims, including environmental claims and employee related matters. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, results of operations, cash flows or financial condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
     There were no matters submitted to a stockholder vote during the third and fourth quarter of 2005.

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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASE OF EQUITY SECURITIES.
Market Information
     Our common stock is traded on the New York Stock Exchange under the symbol “ALJ.”
     The following table sets forth the quarterly high and low sales prices of our common stock for each quarterly period since our common stock began trading on the New York Stock Exchange on July 28, 2005:
                 
2005   HIGH   LOW
Fourth Quarter
  $ 25.05     $ 18.05  
Third Quarter
    26.50       17.05  
Holders
     As of March 1, 2006, there were approximately 26 common stockholders of record.
Dividends
     Except with respect to the dividend of approximately $68.4 million paid on August 2, 2005 to our stockholders of record prior to our initial public offering, and the dividend of approximately $4.7 million paid on August 2, 2005 to the minority interest stockholders of record of Alon Operating, we have not paid dividends on our common stock. On February 15, 2006, our Board of Directors announced a regular quarterly cash dividend of $0.04 per share and a special cash dividend of $0.37 per share of our common stock, payable on March 21, 2006 to stockholders of record at the close of business on March 1, 2006. In connection with our cash dividend payment to shareholders on March 21, 2006, the minority interest owners of Alon Assets and Alon Operating will receive an aggregate cash dividend of approximately $1.1 million. We intend to continue to pay quarterly cash dividends on our common stock at an initial annual rate of $0.16 per share. The declaration and payment of future dividends to holders of our common stock will be at the discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, legal requirements, restrictions in our debt agreements and other factors our board of directors deems relevant.
Recent Sales of Unregistered Securities
     None.
Use of Proceeds from Registered Securities
     On July 27, 2005, the SEC declared effective our registration statements on Form S-1 (Registration Nos. 333-124797 and 333-126952) related to our sale of 11,730,000 shares of our common stock. On August 2, 2005, we completed an initial public offering of all 11,730,000 registered shares at a price of $16.00 per share for an aggregate offering price of approximately $187.7 million. Of the aggregate gross proceeds, approximately $2.4 million was used to pay offering expenses related to the initial public offering, and $13.1 million was used to pay underwriting discounts and commissions. None of the expenses incurred and paid by us in this offering were direct or indirect payments (i) to our directors, officers, general partners or their associates, (ii) to persons owning 10% or more of any class of our equity securities, or (iii) to our affiliates. Net proceeds of the offering after payment of expenses and underwriting discounts and commission were approximately $172.2 million.
     The offering was made through an underwriting syndicate led by Credit Suisse, LLC., Deutsche Bank Securities Inc. and Lehman Brothers Inc. as joint book-running managers.
     We used the net proceeds from the offering as follows:
    payment of a dividend in the amount of approximately $65.7 million to Alon Israel, a stockholder of the Company;

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    payment of a dividend in the amount of approximately $2.7 million to Tabris Investments Inc., a stockholder of the Company;
 
    payment of a dividend in the amount of approximately $4.7 million to the minority stockholders of Alon USA Operating, Inc., a subsidiary of the Company;
 
    approximately $20.7 million was used to repay debt due to our parent company, Alon Israel, and $3.6 million was used to repay debt due to Atofina Petrochemicals, Inc.
 
    approximately $2.5 million was used for general corporate purposes; and
 
    the remaining $72.3 million, along with $31.6 million of cash from operating activities was used to prepay our $100.0 million secured term loan, including prepayment premiums and accrued interest.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
     None.
ITEM 6. SELECTED FINANCIAL DATA.
     The following table sets forth selected historical consolidated financial and operating data for our company. The selected historical consolidated statement of operations and cash flows data for the two years ended December 31, 2002 and 2001, and the selected consolidated balance sheet data as of December 31, 2003, 2002 and 2001, are derived from our audited consolidated financial statements, which are not included in this Annual Report on Form 10-K. The selected historical consolidated statement of operations and cash flows data for the three years ended December 31, 2005, 2004 and 2003, and the selected consolidated balance sheet data as of December 31, 2005 and 2004, are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
     We acquired our business, including a 34.4% interest in our retail subsidiary, Southwest Convenience Stores, LLC., or SCS, and a 60% interest in our subsidiary, Alon USA Capital, Inc., or Alon Capital effective August 1, 2000. We acquired the remaining 65.6% of SCS effective May 1, 2001. A portion of the financing for our acquisition of our business from FINA was in the form of the purchase by investors of 40% of the common stock of Alon Capital, which, through its subsidiaries, holds our refining and other operating assets. On August 21, 2002, we acquired this 40% interest in Alon Capital, which we refer to as the Alon Capital minority interest acquisition. As a result of these transactions, the financial and operating data for periods prior to the effective dates of these transactions may not be comparable to the data for periods after the effective dates of these transactions.
     The following selected historical consolidated financial and operating data should be read in conjunction with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K.

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    Year Ended December 31,  
    2005     2004     2003     2002     2001  
    (dollars in thousands, except per share data)  
STATEMENT OF OPERATIONS DATA:
                                       
Net sales (1)
  $ 2,328,507     $ 1,707,564     $ 1,410,766     $ 1,207,723     $ 1,210,366  
Operating costs and expenses (1)
    2,178,335       1,638,300       1,368,473       1,182,663       1,162,142  
 
                             
Gain on disposition of assets (2)
    38,591       175                    
 
                             
Operating income
    188,763       69,439       42,293       25,060       48,224  
Net income
    103,988       25,132       14,068       4,352       17,627  
 
                                       
Earnings per share, basic and diluted (3)
  $ 2.61     $ .72     $ .40     $ .12     $ .50  
Dividends per share (4)
    1.72                          
Weighted average shares outstanding (3)
    39,889       35,001       35,001       35,001       35,001  
 
                                       
CASH FLOW DATA:
                                       
Net cash provided by (used in):
                                       
Operating activities
  $ 137,895     $ 76,743     $ 76,173     $ 5,001     $ 45,154  
Investing activities
    (106,962 )     (39,886 )     (34,664 )     (70,918 )     (37,927 )
Financing activities
    42,530       19,244       (39,667 )     62,238       (3,500 )
 
                                       
BALANCE SHEET DATA (end of period):
                                       
Cash, cash equivalents and short-term investments
  $ 322,140     $ 63,357     $ 7,256     $ 5,414     $ 9,093  
Working capital
    275,996       44,443       5,071       30,962       19,500  
Total assets
    758,780       472,516       386,982       392,066       281,753  
Total debt
    132,390       187,706       166,816       214,539       126,721  
Stockholders’ equity
    279,493       71,472       46,923       33,128       29,961  
 
(1)   Our buy/sell arrangements involve linked purchases and sales related to refined product contracts entered into to address location, or grade requirements. Included in cost of sales are amounts which approximate the revenues resulting from these transactions. See Note 2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
 
(2)   Gain on disposition of assets reported in 2005 reflects the initial pre-tax gain recognized in connection with assets contributed in the February 28, 2005 HEP transaction and recognition of deferred gain recorded in the ten months following the transaction. The transaction was recorded as a partial sale for accounting purposes.
 
(3)   Weighted average shares outstanding and earnings per share amounts for the periods presented reflect the effect of a 33,600-for-one split of our common stock which was effected on July 6, 2005. On August 2, 2005, we completed an initial public offering of 11,730,000 shares of our common stock. The shares issued in our initial public offering are included in the number of weighted average shares outstanding at December 31, 2005.
 
(4)   Dividends per share reflects the $68.4 million paid on August 2, 2005 to our stockholders of record prior to our initial public offering. These dividends were paid with a portion of the proceeds received in our initial public offering.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
     The following discussion of our financial condition and results of operations is provided as a supplement to, and should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this Annual Report on Form 10-K and the other sections of this Annual Report on Form 10-K, including Items 1 and 2 “Business and Properties,” and Item 6 “Selected Financial Data.”
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. See Item 1A “Risk Factors.”
     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 spread;
 
    the effects of transactions involving forward contracts and derivative instruments;
 
    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 under Item 1A “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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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 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 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. As of December 31, 2005, we operated 167 convenience stores in West Texas and New Mexico. Our convenience stores typically offer merchandise, food products and motor fuels under the 7-Eleven and FINA brand names. We supply our stores with substantially all of their motor fuel needs with gasoline and diesel produced at our Big Spring refinery.
Summary of 2005 Developments
     In February 2005, we completed the contribution of certain of our pipeline and terminal assets to HEP. In exchange for this contribution we received $120 million in cash and 937,500 subordinated Class B limited partnership units in HEP. Simultaneously with this transaction, we entered into a Pipelines and Terminal Agreement with HEP with an initial term of 15 years and three subsequent five year renewal terms exercisable at our sole discretion. Pursuant to the Pipelines and Terminal Agreement, we have agreed to transport and store minimum volumes of refined products in these pipelines and terminals and to pay specified tariffs and fees for such transportation and storage during the term of the agreement.
     In March 2005, we successfully completed a major turnaround at our Big Spring refinery. Other than the planned low sulfur diesel project scheduled for the second quarter 2006, we believe the completion of this project will enable us to operate our Big Spring refinery without significant planned maintenance shut downs for the next four to five years. In connection with this turnaround, we expanded our crude oil throughput capacity from 62,000 bpd to 70,000 bpd. The cost of the expansion project was approximately $6.4 million, or $800 per bpd of additional throughput capacity.
     On August 2, 2005, we completed an initial public offering of 11,730,000 shares of our common stock at a price of $16.00 per share for an aggregate offering price of approximately $187.7 million. We received approximately $172.2 million in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15.5 million or $1.32 per share. The initial public offering represented the sale by us of a 25.1% interest in our company. See “— Liquidity and Capital Resources” and “— Initial Public Offering” below for additional information.
     2005 continued to reflect the positive refinery fundamentals experienced in 2004. These positive fundamentals, including strong refining margins and favorable differentials between WTI and WTS crude oil, resulted in significantly enhanced results of operations reported in 2005 compared to 2004. The effects of the favorable refining margins and WTI/WTS crude oil differentials were partially offset by decreased production in the third quarter of 2005 as a result of the acceleration of a reformer catalyst regeneration that was previously scheduled for January 2006. See “— Factors Affecting Comparability” for additional information. Results of our operations are further described under “— Results of Operations” and “— Liquidity and Capital Resources.” Selected financial data is presented below:

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    Net sales increased $620.9 million to $2,328.5 million and operating income increased $119.4 million to $188.8 million for 2005, compared to net sales of $1,707.6 million and operating income of $69.4 million in 2004.
 
    Our average refinery operating margin increased $4.27 per barrel to $12.30 per barrel for 2005, compared to $8.03 per barrel for 2004.
 
    Our cash, cash equivalents and short-term investments increased $258.8 million to $322.1 million in 2005, compared to cash and cash equivalents of $63.4 million at December 31, 2004, as a result of cash of $137.9 million generated from operating activities, together with $118.0 million net proceeds from the HEP transaction and $72.3 net proceeds from our initial public offering. Total debt was reduced by $55.3 million to $132.4 million, compared to $187.7 million in 2004.
 
    Our capital expenditures and turnaround spending for 2005 totaled approximately $35.1 million, of which $13.9 million was spent on a major turnaround, catalyst and the crude throughput expansion from 62,000 bpd to 70,000 bpd in February 2005, $12.1 million was spent on regulatory and compliance projects and $9.1 million was spent on various sustaining and capital improvement projects.
Major Influences on Results of Operations
     Refining and Marketing. 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 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.
     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 the Gulf Coast 3/2/1 crack spread using the market values of Gulf Coast conventional gasoline and low-sulfur diesel and the market value of WTI crude oil. We calculate the Group III 3/2/1 crack spread using the market values of Group III conventional gasoline and low-sulfur diesel and the market value of WTI crude oil. The Gulf Coast and Group III crack spreads are proxies for the per barrel refinery operating margin that a crude oil refiner situated in the Gulf Coast and Group III region, respectively, would expect to earn if it refined WTI crude oil and sold conventional gasoline and low-sulfur diesel. We calculate our refinery operating margin by dividing the margin between net sales 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. We exclude net sales and cost of sales relating to our non-integrated system from our refinery operating margin because the refined products we sell in this region are obtained from third-party suppliers and are not produced at our Big Spring refinery.
     Our refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. In addition, we are able to access domestic and foreign crude oils available on the Gulf Coast through the Amdel pipeline, which enables us to better optimize our crude supply. As a result, our refinery operating margin generally exceeds the Gulf Coast 3/2/1 crack spread. Over the past two years our refinery operating margin exceeded the Group III 3/2/1 crack spread. The Group III market area has experienced product supply constraints in recent years due to insufficient pipeline capacity from the Gulf Coast to the Group III market area. The supply constraints have typically caused Group III products to be priced at a premium to Gulf Coast products, although in 2005, the Gulf Coast and Group III crack spread were comparable. We measure the cost advantage of refining sour crude oil by calculating the difference between the value 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.
     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.

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Natural gas prices have historically been volatile. For example, natural gas prices ranged between $5.79 and $15.38 per million British thermal units, or MMBTU, in 2005. Typically, electricity prices fluctuate with natural gas prices.
     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, 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 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.
     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 a 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.
Outlook
     We believe that we are well positioned to capitalize on the expected positive refining industry fundamentals in 2006. As a result of our 2005 crude oil capacity expansion at the Big Spring refinery, we plan to increase production in 2006. We plan to complete our ultra low-sulfur diesel upgrades to reduce the sulfur content in all of our diesel fuel products to 15 ppm in the second quarter of 2006. Our increased production capabilities and the conversion of all of our finished diesel fuel production to meet the required low-sulfur specifications is expected to allow us to fully participate in the anticipated positive refinery margin environment in 2006.
     The positive refining industry fundamentals experienced in 2004 and 2005 have continued in the first two months of 2006. We expect that continued concern over adequate refining capacity to meet demand, tight product inventories as a result of heavy turnaround activity scheduled for the first half of 2006 and the widening of the sweet/sour crude oil differential will result in a favorable outlook for refining margins in 2006.
     Our outlook for diesel margins is positive in 2006, due to high distillate demand and as a result of the EPA’s tightening of the diesel fuel specifications that take effect on June 1, 2006. We expect an industry-wide loss of finished diesel production as a result of refineries inability to convert current levels of diesel fuel production to low-sulfur diesel grades which meet the new specifications. In addition, low-sulfur diesel inventories are expected to drop due to scheduling and supply constraints during the transition period to meet low-sulfur diesel specifications in the pipelines, terminals and retail outlets. While diesel margins are expected to outpace gasoline margins, our outlook for gasoline margins is also favorable as demand is expected to exceed supply due to continued supply constraints related to, among other things, reduced gasoline production as a result of the elimination by Congress of MTBE in the gasoline pool and the seasonal shift to summer-grade gasoline in early March 2006.
     The average sweet/sour crude oil differential for the first two months of 2006 was well above historical sweet/sour crude oil differentials. As sour crude oil has typically accounted for over 90% of our crude throughput, we believe our refinery margins will benefit from the continued widening of the sweet/sour differential. The higher sweet/sour differential in 2006 is primarily due to the continued increased demand for sweet crude oils due to low-sulfur specifications, higher incremental sour crude oil production and the expected introduction of low priced Canadian sour crude oil into the Midwest and Gulf Coast regions. Overall, we believe that we are well positioned to capitalize on the expected positive refining industry fundamentals and our expected favorable outlook for refined product margins and sweet/sour crude oil differentials.

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Factors Affecting Comparability
     Our financial condition and operating results over the three-year period ended December 31, 2005 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.
     The contribution of assets in connection with the HEP transaction on February 28, 2005 reduced property, plant and equipment, net, by approximately $37.7 million.
     Pursuant to our Pipelines and Terminals Agreement with HEP, we have agreed to transport and store minimum volumes of refined products in the pipelines and terminals contributed to HEP during the term of such agreement. Beginning March 1, 2005, tariff and terminalling fees associated with the Pipelines and Terminals Agreement are reflected as a component of cost of sales. In the periods prior to the HEP transaction, tariff and terminalling fees related to the contributed assets were eliminated through consolidation of our financial statements. As of March 1, 2005, the majority of all operating expenses related to the pipelines and terminals contributed to HEP are no longer incurred by us, resulting in an offsetting decrease in cost of sales. However, we anticipate that the additional tariff and terminalling fees will be greater than the operating expenses that we will no longer incur, resulting in a net increase to cost of sales. This net increase to cost of sales has the effect of reducing our refinery operating margin.
     The HEP transaction was recorded as a partial sale for accounting purposes. We recognized pre-tax gain of $38.6 million in the ten-month period ending December 31, 2005 in connection with the transaction. This pre-tax gain includes $6.5 million of deferred gain, which was recognized in September 2005, as a result of events which permitted us to accelerate recognition of a portion of the deferred gain. We expect the remaining $63.9 million of deferred gain to be recognized between now and 2017. In addition, $6.7 million of pro-rata gain was subtracted from the carrying value of our investment in HEP in our consolidated balance sheet as a basis adjustment. See Note 4 of the consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
     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 should enable 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 should result in increased production and higher sales volumes, which will affect the comparability of our future operating results to periods prior to the expansion. Our average refinery production was 64,393 bpd for 2005, reflecting effects of the crude oil throughput expansion, partially offset by reduced production resulting from the planned major turnaround completed in the first quarter of 2005. Average refinery production was 70,065 bpd for the last three quarters of 2005, compared to average production of 47,060 bpd for the first quarter of 2005. Average refinery production was 61,372 bpd for 2004.
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.

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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 inter-segment 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 crude oil and 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. Cost of goods excludes depreciation and amortization expense.
     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.
     Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for us and our two operating segments for the years ended December 31, 2005, 2004 and 2003. 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 Annual Report on Form 10-K.

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ALON USA ENERGY, INC. CONSOLIDATED
                         
    Year Ended December 31,  
    2005     2004     2003  
    (dollars in thousands)  
STATEMENT OF OPERATIONS DATA:
                       
Net sales
  $ 2,328,507     $ 1,707,564     $ 1,410,766  
Operating costs and expenses:
                       
Cost of sales
    1,990,338       1,469,940       1,215,032  
Direct operating expenses
    93,843       75,742       66,113  
Selling, general and administrative expenses (1)
    73,219       73,554       69,066  
Depreciation and amortization (2)
    20,935       19,064       18,262  
 
                 
Total operating costs and expenses
    2,178,335       1,638,300       1,368,473  
 
                 
Gain on disposition of assets (3)
    38,591       175        
 
                 
Operating income
    188,763       69,439       42,293  
Interest expense
    (19,326 )     (23,704 )     (16,284 )
Equity earnings in HEP
    1,086              
Other income (expense), net (4)
    4,775       277       (1,819 )
 
                 
Income before income tax expense, minority interest in income of subsidiaries and accounting change
    175,298       46,012       24,190  
Income tax expense
    65,518       18,315       9,105  
 
                 
Income before minority interest in income of subsidiaries and accounting change
    109,780       27,697       15,085  
Minority interest in income of subsidiaries
    5,792       2,565       681  
 
                 
Net income before accounting change
    103,988       25,132       14,404  
Cumulative effect of adoption of accounting principle
                336  
 
                 
Net income
  $ 103,988     $ 25,132     $ 14,068  
 
                 
 
                       
Earnings per share, basic and diluted (5)
  $ 2.61     $ .72     $ .40  
Weighted average shares outstanding (5)
    39,889       35,001       35,001  
 
                       
CASH FLOW DATA:
                       
Net cash provided by (used in):
                       
Operating activities
  $ 137,895     $ 76,743     $ 76,173  
Investing activities
    (106,962 )     (39,886 )     (34,664 )
Financing activities
    42,530       19,244       (39,667 )
 
                       
BALANCE SHEET DATA (end of period):
                       
Cash, cash equivalents and short-term investments
  $ 322,140     $ 63,357     $ 7,256  
Working capital
    275,996       44,443       5,071  
Total assets
    758,780       472,516       386,982  
Total debt
    132,390       187,706       166,816  
Stockholders’ equity
    279,493       71,472       46,923  
 
                       
OTHER DATA:
                       
Adjusted EBITDA (6)
  $ 176,968     $ 88,605     $ 58,400  
Capital expenditures (7)
    23,034       27,301       23,391  
Capital expenditures for turnarounds and catalysts
    12,041       2,322       1,547  
 
(1)   Includes corporate headquarters selling, general and administrative expenses of $491, $589 and $622, for the years ended December 31, 2005, 2004 and 2003, respectively, which are not allocated to our two operating segments.
 
(2)   Includes corporate depreciation and amortization of $1,914, $1,480, and $1,548, for the years ended December 31, 2005, 2004 and 2003, respectively, which are not allocated to our two operating segments.
 
(3)   Gain on disposition of assets reported in 2005, reflects the initial pre-tax gain recognized in connection with assets contributed in the February 28, 2005 HEP transaction and recognition of deferred gain recorded in the ten months following the transaction. The transaction was recorded as a partial sale for accounting purposes.
 
(4)   Includes interest earned on cash, cash equivalents and short-term investments.
 
(5)   Weighted average shares outstanding and earnings per share amounts for the periods presented reflect the effect of a 33,600-for-one split of our common stock which was effected on July 6, 2005. On August 2, 2005, we completed an initial public offering of 11,730,000 shares of our common stock. The shares issued in our initial public offering are included in number of weighted average shares outstanding at December 31, 2005.

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(6)   See “— Reconciliation of Amounts Reported Under Generally Accepted Accounting Principles” for information regarding our definition of EBITDA and Adjusted EBITDA, its limitations as an analytical tool and a reconciliation of net income to EBITDA and Adjusted EBITDA for the periods presented.
     
(7)   Includes corporate capital expenditures of $470, $612, and $609, for the years ended December 31, 2005, 2004 and 2003, respectively, which are not included in our two operating segment capital expenditures.

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REFINING AND MARKETING SEGMENT
                         
    Year Ended December 31,  
    2005     2004     2003  
    (dollars in thousands, except per barrel data and  
    pricing statistics)  
STATEMENT OF OPERATIONS DATA:
                       
Net sales (1) (2)
  $ 2,147,390     $ 1,523,850     $ 1,225,045  
Operating costs and expenses:
                       
Cost of sales (2)
    1,866,536       1,342,426       1,084,213  
Direct operating expenses
    93,843       75,742       66,113  
Selling, general and administrative expenses
    22,932       23,679       20,063  
Depreciation and amortization
    14,464       13,392       12,636  
 
                 
Total operating costs and expenses
    1,997,775       1,455,239       1,183,025  
 
                 
Gain on disposition of assets (3)
    38,628              
 
                 
Operating income
  $ 188,243     $ 68,611     $ 42,020  
 
                 
 
                       
KEY OPERATING STATISTICS AND OTHER DATA:
                       
Total sales volume (bpd)
    87,251       85,950       90,914  
Non-integrated marketing sales volume (bpd) (4)
    20,335       19,926       24,093  
Non-integrated marketing margin (per barrel sales volume) (4)
  $ (1.32 )   $ 0.03     $ 0.52  
Per barrel of throughput:
                       
Refinery operating margin (5)
  $ 12.30     $ 8.03     $ 5.80  
Direct operating expenses (6)
    3.97       3.36       2.81  
Capital expenditures
  $ 19,080     $ 23,555     $ 16,169  
Capital expenditures for turnarounds and catalysts
    12,041       2,322       1,547  
 
                       
PRICING STATISTICS:
                       
WTI crude oil (per barrel)
  $ 56.49     $ 41.42     $ 31.11  
WTS crude oil (per barrel)
    51.87       37.45       28.36  
Crack spreads (3/2/1) (per barrel):
                       
Gulf Coast
  $ 11.45     $ 6.77     $ 4.73  
Group III
    11.44       8.02       6.74  
Crude differentials (per barrel):
                       
WTI less WTS
  $ 4.62     $ 3.97     $ 2.75  
Product price (per gallon):
                       
Gulf Coast unleaded
    158.8¢       116.4¢       86.9¢  
Gulf Coast low-sulfur diesel
    167.6       111.0       82.2  
Group III unleaded
    159.4       119.0       91.9  
Group III low-sulfur diesel
    166.5       115.1       86.5  
Natural gas (per MMBTU)
  $ 9.01     $ 6.19     $ 5.50  
                                                 
    Year Ended December 31,  
    2005     2004     2003  
    Bpd     %     Bpd     %     Bpd     %  
THROUGHPUT AND PRODUCTION DATA:
                                               
Refinery throughput:
                                               
Sweet crude
    5,072       7.8       4,321       7.0       5,398       8.4  
Sour crude
    55,643       86.0       53,646       87.0       55,676       86.5  
Blendstocks
    4,040       6.2       3,697       6.0       3,280       5.1  
 
                                   
Total refinery throughput (7)(8)
    64,755       100.0       61,664       100.0       64,354       100.0  
 
                                   
 
                                               
Refinery production:
                                               
Gasoline
    29,499       45.8       28,711       46.8       30,700       47.7  
Diesel/jet
    21,903       34.0       19,939       32.5       21,554       33.5  
Asphalt
    5,824       9.1       5,781       9.4       5,746       8.9  
Petrochemicals
    4,256       6.6       4,492       7.3       4,536       7.1  
Other
    2,911       4.5       2,449       4.0       1,804       2.8  
 
                                   
Total refinery production (8)(9)
    64,393       100.0       61,372       100.0       64,340       100.0  
 
                                   
 
                                               
Refinery utilization (10)
            94.3 %             95.0 %             99.3 %
 
(1)   Net sales include inter-segment sales to our retail segment at prices which approximate market price. These inter-segment sales are eliminated through consolidation of our financial statements.
 
(2)   Our buy/sell arrangements involve linked purchase and sales related to refined product contracts entered into to address location or grade requirements. Included in cost of sales are amounts which approximate the revenues resulting from these transactions. See Note 2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

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(3)   Gain on disposition of assets reported in 2005 reflects the initial pre-tax gain recognized in connection with assets contributed in the February 28, 2005 HEP transaction and recognition of deferred gain recorded in the ten months following the transaction. The transaction was recorded as a partial sale for accounting purposes.
 
(4)   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. Non-integrated marketing margin represents the margin between 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 and costs of sales exclusive of depreciation and amortization expense, 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. We exclude net sales and cost of sales from our non-integrated system because the refined products we sell in this system are not produced at our refinery. 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)   Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses, exclusive of depreciation and amortization expense, by our refinery throughput.
 
(7)   Total refinery throughput represents the aggregate volume of crude oil and blendstock used in the refinery production process.
 
(8)   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 our refinery.
 
(9)   2005 throughput reflects the effect of the downtime associated with the planned major turnaround in the first throughput of quarter 2005. Refinery throughput increased to an average of 70,419 bpd for the last three quarters of 2005, compared to average throughput of 47,447 bpd for the first quarter 2005. Refinery production increased to an average production of 70,065 bpd for the last three quarters of 2005, compared to average production of 47,060 bpd for the first quarter 2005.
 
(10)   Refinery utilization represents average daily crude oil throughput divided by crude capacity, excluding planned periods of downtime for maintenance and turnarounds.

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RETAIL SEGMENT
                         
    Year Ended December 31,  
    2005     2004     2003  
    (dollars in thousands, except per gallon data)  
STATEMENT OF OPERATIONS DATA:
                       
Net sales
  $ 326,537     $ 301,491     $ 278,189  
Operating costs and expenses:
                       
Cost of sales (1)
    269,222       245,291       223,287  
Selling, general and administrative expenses
    49,796       49,286       48,381  
Depreciation and amortization
    4,557       4,192       4,078  
 
                 
Total operating costs and expenses
    323,575       298,769       275,746  
 
                 
Gain (loss) on disposition of assets
    (37 )     175        
 
                 
Operating income
  $ 2,925     $ 2,897     $ 2,443  
 
                 
 
                       
KEY OPERATING STATISTICS AND OTHER DATA:
                       
Number of stores (end of period)
    167       167       170  
Fuel sales (thousands of gallons)
    87,714       97,541       100,389  
Fuel sales (thousands of gallons per site per month)
    45       49       50  
Fuel margin (cpg) (2)
    14.9¢       12.9¢       11.9¢  
Fuel sales price (dollar per gallon) (3)
  $ 2.20     $ 1.76     $ 1.47  
Merchandise sales
  $ 133,305     $ 130,117     $ 130,413  
Merchandise sales (per site per month)
    68       65       64  
Merchandise margin (4)
    33.2 %     33.5 %     33.0 %
Capital expenditures
    3,484       3,134       6,613  
 
(1)   Cost of sales includes inter-segment purchases of motor fuels from our refining and marketing segment at prices which approximate market prices. These inter-segment purchases are eliminated through consolidation of our financial statements.
 
(2)   Fuel margin represents the difference between motor fuel revenues and the net cost of purchased 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 revenues 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.

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Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Net Sales
     Consolidated. Net sales for 2005 were $2,328.5 million, compared to $1,707.6 million for 2004, an increase of $620.9 million or 36.4%. This increase was primarily due to higher than average refined product prices and increased refined product sales volume as a result of the completion of our 8,000 bpd throughput capacity expansion in the first quarter of 2005.
     Refining and Marketing Segment. Net sales for our refining and marketing segment were $2,147.4 million for 2005, compared to $1,523.9 million for 2004, an increase of $623.5 million or 40.9%. The increase in net sales was primarily the result of significantly higher refined product prices in 2005 compared to 2004. 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 gasoline in 2005 increased 42.4 cpg, or 36.4%, to 158.8 cpg, compared to 116.4 cpg in 2004. The average Gulf Coast diesel price in 2005 increased 56.6 cpg, or 51.0%, to 167.6 cpg compared to 111.0 cpg in 2004. Also contributing to the increase in sales revenues was an increase in sales volume. Our sales volume increased by 16.4 million gallons, or 1.2%, to 1,337.6 million gallons in 2005 compared to 1,321.2 million gallons in 2004. This increase in sales volume resulted primarily from the 8,000 bpd throughput capacity expansion completed in the first quarter of 2005, which resulted in average refinery production of 64,393 bpd in 2005 compared to 61,372 bpd in 2004, despite the effects of a reformer catalyst regeneration in September 2005 and the effects of the planned major turnaround in the first quarter 2005. Average refinery production increased to 70,065 bpd in the last three quarters of 2005, compared to average production of 47,060 bpd in the first quarter 2005.
     Retail Segment. Net sales for our retail segment were $326.5 million for 2005 compared to $301.5 million for 2004, an increase of $25.0 million or 8.3%. This increase was primarily due to higher average retail fuel prices. Average retail fuel prices were $2.20 per gallon for 2005, compared to average retail fuel prices of $1.76 per gallon for 2004. Additionally, merchandise gross sales increased 2.5% to $133.3 million for 2005, compared to $130.1 million for 2004. This increase was partially offset by a decline in retail motor fuel sales volume. Our retail motor fuel sales volume decreased by 9.8 million gallons, or 10.1%, to 87.7 million gallons in 2005 compared to 97.5 million gallons in 2004. This decrease was due to competitive pressures from an increased presence of larger retailers in some of our retail markets.
Cost of Sales
     Consolidated. Cost of sales was $1,990.3 million for 2005, compared to $1,470.0 million for 2004, an increase of $520.3 million or 35.4%. This increase resulted primarily from higher crude oil prices.
     Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $1,866.5 million for 2005, compared to $1,342.4 million for 2004, an increase of $524.1 million or 39.0%. This increase was primarily due to significantly higher crude oil prices and the increase in refinery production in 2005 compared to 2004. The average price per barrel of WTS for 2005 increased $14.42 per barrel to $51.87 per barrel, compared to $37.45 per barrel for 2004, an increase of 38.5%. In addition, approximately $12.9 million of the increase in cost of sales related to transportation expense associated with the throughput agreement with HEP.
     Retail Segment. Cost of sales for our retail segment was $269.2 million for 2005, compared to $245.3 million for 2004, an increase of $23.9 million or 9.7%. This increase was primarily attributable to higher motor fuel costs, partially offset by a decrease in fuel sales volume.
Direct Operating Expenses
     Direct operating expenses were $93.8 million for 2005, compared to $75.7 million for 2004, an increase of $18.1 million or 23.9%. Of this increase, approximately $15.3 million was attributable to an increase in natural gas prices in 2005 compared to 2004. The average price of natural gas was $9.01 per MMBTU in 2005, compared to $6.19 per MMBTU in 2004, an increase of 45.6%. Overall energy usage also increased as a result of the 8,000 bpd throughput capacity expansion in the first quarter 2005. In addition, repairs and maintenance expense increased in 2005 as a result of routine maintenance projects that were completed in conjunction with the major turnaround completed in the first quarter of 2005 and in connection with the reformer catalyst regeneration performed in the third quarter 2005.

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Selling, General and Administrative Expenses
     Consolidated. SG&A expenses for 2005 were $73.2 million, compared to $73.6 million in 2004, a decrease of $0.4 million or 0.5%.
     Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for 2005 were $22.9 million, compared to $23.7 million for 2004, a decrease of $0.8 million or 3.3%. This decrease was primarily due to a reduction of bad debt expense and professional fees.
     Retail Segment. SG&A expenses for 2005 were $49.8 million, compared to $49.3 million for 2004, an increase of $0.5 million or 1.0%. This increase was primarily due to increased credit card brokerage fees as a result of the higher fuel prices, which were partially offset by decreased healthcare and workers compensation insurance costs.
Depreciation and Amortization
     Depreciation and amortization for 2005 was $20.9 million, compared to $19.1 million for 2004, an increase of $1.8 million or 9.4%. This increase was primarily attributable to the completion of the various capital projects in late 2004 and the first half of 2005. Partially offsetting this increase was a reduction in depreciation due to the disposition of assets in the HEP transaction.
Operating Income
     Consolidated. Operating income for 2005 was $188.8 million. Excluding $38.6 million of net gain on disposition of assets resulting from the HEP transaction, which management believes enhances period-to-period comparability, operating income for 2005 was $150.2 million, compared to $69.2 million (excluding the $0.2 million gain on disposition of assets) for 2004, an increase of $81.0 million or 117.1%. 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 2005 was $188.2 million. Excluding $38.6 million of gain on disposition of assets resulting from the HEP transaction, operating income for 2005 was $149.6 million, compared to operating income for 2004 of $68.6 million, an increase of $81.0 million or 118.1%. This increase was primarily attributable to the increase in our refinery operating margins and increased sales volumes as a result of the 8,000 bpd crude oil throughput capacity expansion at our Big Spring refinery in the first quarter of 2005. Our refinery operating margin for 2005 increased $4.27 per barrel to $12.30 per barrel, compared to $8.03 per barrel in the 2004. This increase was attributable, in part, to higher differentials between refined product prices and crude oil prices as a result of decreases in finished product inventories, concern over adequate refining capacity to meet demand and continued year-on-year demand increases at above historical levels in the United States and abroad. The Gulf Coast 3/2/1 crack spread increased by $4.68 per barrel to an average of $11.45 per barrel in 2005 compared to an average of $6.77 per barrel in 2004, an increase of 69.1%. Also contributing to this increase was a widening of the sweet/sour spread. The average sweet/sour spread increased $.65 per barrel to $4.62 per barrel for 2005 compared to the average sweet/sour spread of $3.97 per barrel for 2004, an increase of 16.4%.
     Retail Segment. Operating income for our retail segment was $2.9 million for 2005 and $2.7 million (excluding the $0.2 million gain on disposition of assets) for 2004. Our average retail motor fuel margin increased 2.0 cpg to 14.9 cpg in 2005, compared to 12.9 cpg in 2004, an increase of 15.5%. Partially offsetting this increase was a decrease in motor fuel sales volumes as a result of weaker demand in some markets due to the higher prices. The increase in gross merchandise sales were partially offset by a slight decrease in merchandise gross margin to 33.2% in 2005, compared to 33.5% in 2004.
Interest Expense
     Interest expense was $19.3 million in 2005, compared to $23.7 million in 2004, a decrease of $4.4 million or 18.6%. Interest expense for 2005 reflects the repayment of $55.3 million of debt during 2005 and the significant reductions of borrowings under our revolving credit facility as a result of increases in cash from operating activities and funds received as a result of the HEP transaction in the first quarter 2005 and the completion of our initial public offering in the third quarter of 2005.

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Income Tax Expense
     Income tax expense was $65.5 million in 2005 compared to $18.3 million in 2004, an increase of $47.2 million. The increase in income tax expense was attributable to our increased 2005 taxable income compared to 2004. Our effective tax rate for 2005 was 37.4% and reflects the $1.1 million benefit of the Jobs Creation Act tax credit for 2005. Our effective tax rate was 39.8% for 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 shareholders in two of our subsidiaries, Alon Assets and Alon Operating. Minority interest in income of subsidiaries was $5.8 million for 2005, compared to $2.6 million for 2004, an increase of $3.2 million. This increase was attributable to our increased after-tax income in 2005 as a result of the factors discussed above. This increase was partially offset by a reduction in the minority interest ownership percentage to 4.8% in the third quarter of 2005 compared to 8.4% in 2004 as a result of the issuance of additional voting common stock by Alon Assets and Alon Operating in the third quarter of 2005 and the repurchase of shares of non-voting common stock by Alon Assets and Alon Operating in the first quarter of 2005.
Net Income
     Net income was $104.0 million for 2005, compared to $25.1 million for 2004, an increase of $78.9 million or 314.3%. This increase was attributable to the factors discussed above.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Net Sales
     Consolidated. Net sales for 2004 were $1,707.6 million, compared to $1,410.8 million for 2003, an increase of $296.8 million or 21.0%. This increase was primarily due to favorable market conditions resulting from higher refined product prices, partially offset by a decrease in sales volume.
     Refining and Marketing Segment. Net sales for our refining and marketing segment were $1,523.9 million for 2004, compared to $1,225.0 million for 2003, an increase of $298.9 million or 24.4%. The increase in net sales was primarily the result of significantly higher refined product prices in 2004 compared to 2003. The average price of Gulf Coast gasoline in 2004 increased 29.5 cpg, or 34.0%, to 116.4 cpg, compared to 86.9 cpg in 2003. The average Gulf Coast diesel price in 2004 increased 28.8 cpg, or 35.0%, to 111.0 cpg compared to 82.2 cpg in 2003. The increase in net sales was partially offset by a 5.2%, or 72.4 million gallons, decrease in sales volumes in 2004 compared to 2003. This decrease was due, in part, to the non-renewal of several distributor supply contracts in our non-integrated system that expired in late 2003 and early 2004. The decrease was also due to reduced production resulting from unplanned downtime and repairs to our catalytic cracking unit as we neared the end of our major turnaround cycle.
     Retail Segment. Net sales for our retail segment were $301.5 million for 2004 compared to $278.2 million for 2003, an increase of $23.3 million or 8.4%. This increase was primarily due to higher average retail fuel prices. Average retail fuel prices were $1.76 per gallon for 2004, compared to average retail fuel prices of $1.47 per gallon for 2003. This increase was partially offset by a decrease in fuel sales volume of 2.9 million gallons, or 3.0%, to 97.5 million gallons in 2004 as compared to 100.4 million gallons in 2003 and a decrease in merchandise sales. The decrease in fuel sales volume and merchandise sales was primarily related to closing three stores in 2004.
Cost of Sales
     Consolidated. Cost of sales was $1,470.0 million for 2004, compared to $1,215.0 million for 2003, an increase of $255.0 million or 21.0%. This increase was primarily due to higher crude oil prices, partially offset by reduced crude oil purchases in 2004, due to slightly reduced crude throughput at our Big Spring refinery.
     Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $1,342.4 million for 2004, compared to $1,084.2 million for 2003, an increase of $258.2 million or 23.8%. This increase was primarily due to significantly higher crude oil prices. The average price per barrel of WTS for 2004 increased $9.09

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per barrel to $37.45 per barrel, compared to $28.36 per barrel for 2003, an increase of 32.1%. The increase in cost of sales was partially offset by a decline in our crude oil purchases as a result of reduced crude throughput at the Big Spring refinery.
     Retail Segment. Cost of sales for our retail segment was $245.3 million for 2004, compared to $223.3 million for 2003, an increase of $22.0 million or 9.9%. This increase was primarily attributable to higher motor fuel costs, partially offset by a decrease in fuel sales volume as a result of closing three stores in 2004.
Direct Operating Expenses
     Direct operating expenses were $75.7 million for 2004, compared to $66.1 million for 2003, an increase of $9.6 million or 14.5%. This increase was primarily attributable to increased energy costs resulting from higher natural gas prices. The average price of natural gas was $6.19 per MMBTU in 2004, compared to $5.50 per MMBTU in 2003, an increase of 12.5%. In addition, increased maintenance labor costs and maintenance expenditures contributed to the increase in direct operating expenses.
Selling, General and Administrative Expenses
     Consolidated. SG&A expenses for 2004 were $73.6 million, compared to $69.1 million in 2003, an increase of $4.5 million or 6.5%. This increase was attributable to higher professional fees and employment related costs in our refining and marketing segment and higher insurance premiums and utility prices in our retail segment.
     Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for 2004 were $23.7 million, compared to $20.1 million for 2003, an increase of $3.6 million or 17.9%. This increase was primarily attributable to higher legal and consulting fees and higher employee incentive awards.
     Retail Segment. SG&A expenses for 2004 were $49.3 million, compared to $48.4 million for 2003, an increase of $0.9 million or 1.9%. This increase was primarily due to increased workers compensation insurance and health insurance costs.
Depreciation and Amortization
     Depreciation and amortization for 2004 was $19.1 million, compared to $18.3 million for 2003, an increase of $0.8 million or 4.4%. This increase resulted from additions to property, plant and equipment as a result of capital expenditures in 2004 and a full year of depreciation associated with 2003 capital expenditures.
Operating Income
     Consolidated. Operating income for 2004 was $69.4 million, compared to $42.3 million for 2003, an increase of $27.1 million or 64.1%. 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 2004 was $68.6 million, compared to $42.0 million for 2003, an increase of $26.6 million or 63.3%. This increase was attributable to the significant increase in our refinery operating margins, partially offset by higher direct operating expenses and SG&A expenses. Our refinery operating margin increased $2.23 per barrel to $8.03 per barrel in 2004, compared to $5.80 per barrel in 2003. This increase was attributable, in part, to higher differentials between refined product prices and crude oil prices. The Gulf Coast 3/2/1 crack spread increased by 43.1% from an average of $4.73 per barrel in 2003 to an average of $6.77 per barrel in 2004. Also contributing to this increase was a widening of the sweet/sour spread which increased to an average of $3.97 per barrel in 2004 compared to $2.75 per barrel in 2003, an increase of 44.4%.
     Retail Segment. Operating income for our retail segment was $2.9 million for 2004, compared to $2.4 million for 2003, an increase of $0.5 million or 20.8%. The increase in merchandise and motor fuel margins were partially offset by increased SG&A expenses. Our merchandise margin increased to 33.5% in 2004, compared to 33.0% in 2003. Our average retail motor fuel margin increased 1.0 cpg to 12.9 cpg in 2004, compared to 11.9 cpg in 2003, an increase of 8.4%.

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Interest Expense
     Interest expense was $23.7 million in 2004, compared to $16.3 million in 2003, an increase of $7.4 million or 45.4%. Interest expense for 2004 reflects a net increase of $34.7 million in outstanding term loan debt resulting from our incurrence of $100.0 million of indebtedness under our senior secured term loan in January 2004, as well as $0.7 million of non-cash debt issuance costs associated with this transaction and the application of the proceeds to repay our existing term debt. In addition, higher crude oil prices in 2004 compared to 2003 resulted in increased letter of credit fees relating to our crude oil purchases.
Income Tax Expense
     Income tax expense was $18.3 million in 2004 compared to $9.1 million in 2003, an increase of $9.2 million. The increase in income tax expense was attributable to our increased 2004 taxable income compared to 2003. Our effective tax rate for 2004 was 39.8% as compared to 37.6% for 2003.
Minority Interest In Income of Subsidiaries
     Minority interest in income of subsidiaries was $2.6 million for 2004, compared to $0.7 million for 2003, an increase of $1.9 million. This increase was primarily attributable to the increase in net income as a result of the factors discussed above and the issuance of additional stock under the Alon Assets and Alon Operating stock option plans.
Net Income
     Net income was $25.1 million for 2004, compared to $14.1 million for 2003, an increase of $11.0 million or 78.0%. 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, our liquidity was enhanced during the third quarter of 2005 by the receipt of $72.3 million net cash proceeds received from our initial public offering after the payment of commissions and expenses, debt prepayment, dividends to pre-offering stockholders, minority interest stockholders and general corporate expenditures. We believe that our cash on hand, cash flows from operating activities, 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 that we complete.
Cash Flow
     The following table sets forth our consolidated cash flows for the years ended December 31, 2005, 2004 and 2003:
                         
    Year Ended December 31  
    2005     2004     2003  
    (dollars in thousands)  
Cash provided by (used in):
                       
Operating activities
  $ 137,895     $ 76,743     $ 76,173  
Investing activities (1)
    (106,962 )     (39,886 )     (34,664 )
Financing activities
    42,530       19,244       (39,667 )
 
                 
Net increase in cash and cash equivalents
  $ 73,463     $ 56,101     $ 1,842  
 
                 
 
(1)   2005 cash used in investing activities include $185,320 investments in short-term, highly liquid debt instruments, partially offset by $118,000 net proceeds received in the HEP transaction.
Cash Flows Provided By Operating Activities
     Net cash provided by operating activities for 2005 was $137.9 million, compared to net cash provided by operating activities of $76.7 million for 2004. The $61.2 million net increase in cash provided by operating

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activities was primarily due to increased net income (excluding after-tax gains on dispositions of assets), resulting from higher refinery operating margins and increased refinery production as a result of the expansion of the Big Spring refinery crude oil capacity and the major turnaround in the first quarter of 2005. Working capital, net of cash and short-term investments, was $(46.1) million at December 31, 2005 compared to $(18.9) million at December 31, 2004, a decrease of $27.2 million. This decrease was primarily due to higher crude oil prices, products prices and increased sales volume.
     Net cash provided by operating activities for 2004 was $76.7 million compared to net cash provided by operating activities of $76.2 million for 2003. Cash flow from operating activities for 2004 was primarily attributable to operating income of $69.4 million, resulting from higher refinery operating margins. Cash flow from operating activities for 2003 was primarily attributable to improved operating income of $42.3 million and an increase in trade payables due to the increase in crude oil prices. Working capital, net of cash, was $(18.9) million at December 31, 2004 compared to $(2.2) million at December 31, 2003, a decrease of $16.7 million. This decrease was primarily attributable to the net increase in trade payables as a result of higher crude prices in 2004, partially offset by increased accounts receivable balance resulting from higher product prices.
     Net cash provided by operating activities for 2003 was $76.2 million. Cash flow from operating activities for 2003 was primarily attributable to operating income of $42.3 million and an increase in trade payables due to the increase in crude oil prices. Working capital, net of cash, decreased by $27.7 million, compared to $(2.2) million at December 31, 2003. This decrease was primarily attributable to reduced inventories from 2002 levels and an increase in trade payables as a result of higher crude oil prices.
Cash Flows Used In Investing Activities
     Net cash used in investing activities increased to $107.0 million in 2005 from $39.9 million in 2004. This increase was primarily attributable to our $185.3 million investment in highly liquid short-term debt instruments and turnaround and chemical catalyst expenditures of $12.0 million due to the major turnaround in the first quarter of 2005, partially offset by the receipt of $118.0 of net cash proceeds in connection with the HEP transaction. Capital expenditures in 2005 totaled $23.0 million and included $12.1 million for regulatory and compliance projects, $1.8 million for the completion of our throughput capacity expansion project, $1.4 million for retail store automation and $7.7 million for various sustaining and capital improvement projects.
     Net cash used in investing activities increased to $39.9 million in 2004 from $34.7 million during 2003. Our primary investments in 2004 included $10.0 million of deferred payment for the 2002 Alon Capital minority interest acquisition, $9.4 million for the acquisition of the Trust and River pipeline systems, $5.0 million for the initial phase of our Big Spring refinery’s throughput capacity expansion project, $4.0 million for EPA low-sulfur fuel projects, $2.3 million for chemical catalysts and turnaround preparations and $4.3 million for retail acquisitions and improvements. The remaining $4.9 million was spent on sustaining capital needs and growth opportunities, including the acquisition of our asphalt facility in Bakersfield, California.
     Net cash used in investing activities totaled $34.7 million in 2003. Our primary investments in 2003 included $13.6 million for our low-sulfur gasoline project, $10.0 million of deferred payment for the 2002 Alon Capital minority interest acquisition and $4.1 million for the acquisition of three retail locations. The remaining $7.0 million was spent on sustaining capital needs and growth opportunities.
Cash Flows Provided By (Used In) Financing Activities
     Net cash provided by financing activities was $42.5 million in 2005, compared to net cash provided by financing activities of $19.2 million in 2004. Cash provided by financing activities in 2005 included the net proceeds from our initial public offering on August 2, 2005 of $74.8 million after payment of commissions and expenses, debt prepayment, dividends to pre-offering stockholders and minority interest stockholders. In addition, cash used in financing activities during 2005 included additional debt reduction of $31.0 million.
     Net cash provided by financing activities was $19.2 million in 2004, compared to net cash used in financing activities of $39.7 million in 2003. This difference was primarily attributable to the $100.0 million in new borrowings under our term loan in January 2004. Approximately $43.7 million of existing term debt and $21.6 million of borrowings under our revolving credit facilities were retired with the term loan proceeds.

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     Net cash used in financing activities in 2003 was $39.7 million. The use of cash in 2003 reflected the reduction in our net borrowings under our revolving credit facility due to increased operating income and decreased working capital needs.
Initial Public Offering
     On August 2, 2005, we completed an initial public offering of 11,730,000 shares of our common stock at a price of $16.00 per share for an aggregate offering price of approximately $187.7 million. We received approximately $172.2 million in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15.5 million or $1.32 per share.
     On August 2, 2005, we paid our stockholders of record prior to our initial public offering aggregate dividends of approximately $68.4 million, and the minority interest stockholders of Alon Operating were paid aggregate dividends of approximately $4.7 million. During August 2005, we utilized a portion of the proceeds from our initial public offering to repay the remaining $20.7 million of outstanding debt owed to our parent company, Alon Israel, and $3.6 million of outstanding debt owed to FINA. As of December 31, 2005, the remaining proceeds from the initial public offering were invested in various highly liquid, low-risk debt instruments with maturities of three months or less or low-risk debt instruments with maturities in excess of three months. On January 19, 2006, we used the remaining $72.3 million of the proceeds, along with cash from operating activities, to repay our $100.0 million term loan facility. See Item 5 “—Use of Proceeds from Registered Securities.”
Cash, Cash Equivalents and Short-Term Investment 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 (“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 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 December 31, 2005, our total cash and cash equivalents were $136.8 million, our short-term investments were $185.3 million and we had total debt of approximately $132.4 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 accrued interest.
     Summary of Indebtedness. The following table sets forth the principal amounts outstanding under our bank credit facilities, retail mortgages and equipment loans at December 31, 2005:
         
    As of December 31, 2005  
    (dollars in thousands)  
Debt, including current portion
       
Bank credit facilities:
       
Revolving credit facility
  $  
Term loan
    100,000  
Retail mortgages and equipment loans
    32,390  
 
     
 
       
Total debt
  $ 132,390  
 
     
     Revolving Credit Facility. We entered into a revolving credit facility on July 31, 2000, which was amended and restated on January 14, 2004 and further amended and restated on February 15, 2006. The Israel Discount Bank of New York, or Israel Discount Bank, acts as agent administrative agent, co-arranger, collateral agent and lender and Bank Leumi act 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 upon the increase of crude oil prices or an increase in our throughput capacity. Prior to the amendment, the amount available under the previous revolving credit facility was $141.6 million.
     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

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borrowing base under the revolving credit agreement. As of December 31, 2005, the borrowing base under the revolving credit facility was $337.8 million. The entire revolving credit facility is available in the form of letters of credit, and of 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 cash, accounts receivable, inventory and related assets. All fixed assets previously securing the facility were released in conjunction with the amendment of the facility on February 15, 2006.
     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 USA 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 (minimum consolidated tangible net worth as of December 31, 2005 was $158.1 million and our actual consolidated tangible net worth was $193.6);
 
    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 December 31, 2005 was (0.4) to 1.00);
 
    a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0 (the ratio as of December 31, 2005 was 1.8 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 December 31, 2005 was 11.8 to 1.0);
     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. This calculation of consolidated EBITDA differs from the calculation of Adjusted EBITDA presented elsewhere in this Annual Report on Form 10-K. As of December 31, 2005, we were in compliance with all of these covenants.
     Under our revolving credit facility, a change of control will be deemed to occur, if Alon Israel ceases to have the power to exercise, directly or indirectly, a controlling influence over our management or policies or ceases to own and control at lease 25% of the aggregate voting power represented by our outstanding capital stock.
     The revolving credit facility expires on January 1, 2010. As of December 31, 2005 there were no borrowings outstanding and approximately $131.7 million of letters of credit outstanding under the revolving credit facility.
     Term Loan. We entered into a term credit facility, or term facility, on December 16, 2003, which was amended and restated as of January 14, 2004, and further amended on February 10, 2005 and May 6, 2005. Credit Suisse was the administrative agent and collateral agent under the term facility. On January 19, 2006, we made a payment of approximately $103.9 million in satisfaction of all of our outstanding obligations under the term facility and terminated the term facility. Of this amount, $100.0 million represented a voluntary prepayment of the outstanding principal under the term facility, approximately $0.9 million represented accrued and unpaid interest on the principal balance and $3.0 million represented a prepayment premium. Borrowings under the term facility bore

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interest, at our option, at either adjusted LIBOR plus 6.5% per annum, or at the alternate base rate plus 5.5% per annum, but not less than 10% per annum. We did not have the right to prepay outstanding principal amounts prior to January 17, 2006. Borrowings outstanding under the term facility would have matured on January 14, 2009.
     Mortgage Loans and Equipment Loans. We entered into mortgage and equipment loan agreements with GE Capital Franchise Finance Corporation on October 1, 2002. Pursuant to these agreements, we formed two new retail finance subsidiaries, which received $22.3 million in mortgage loans and $12.7 million in equipment loans. The mortgage loans and equipment loans bear interest at a fixed rate of 8.06% per annum and 8.30% per annum, respectively. The loans are guaranteed by Alon USA and secured by liens on the properties and equipment owned by the retail finance subsidiaries. The loans contain representations and warranties, affirmative, negative and financial covenants and events of default that we believe are customary for financings of this kind. The mortgage loans are payable on a 20-year amortization schedule, and the equipment loans are payable on a ten-year amortization schedule. As of December 31, 2005, we had $30.6 million aggregate principal amount outstanding under the GE mortgage loans and equipment loans. In 2003 and 2004, we obtained $2.3 million in mortgage and equipment loans to finance the acquisition of new retail locations and equipment. The interest rates on these loans range from 5.5% to 9.7% with five to 15-year payment terms.
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 capital expenditure budgets, including expenditures for chemical catalyst and turnarounds, for 2006 and 2007 are $38.2 million and $42.7 million, respectively. The following table summarizes our expected capital expenditures for 2006 and 2007 by operating segment and major category:
                 
    2006     2007  
    (dollars in thousands)  
Refining and Marketing Segment:
               
Sustaining maintenance
  $ 11,515     $ 7,034  
Growth/profit improvement/other
    4,932       13,402  
Low-sulfur gasoline and diesel compliance
    9,930       500  
 
           
 
    26,377       20,936  
 
           
 
               
Retail Segment:
               
Sustaining maintenance
    1,947       1,211  
Growth/profit improvement
    5,471       9,129  
 
           
 
    7,418       10,340  
 
           
Total
  $ 33,795     $ 31,276  
 
           
     Clean Air Capital Expenditures. We expect to spend approximately $25.3 million over the next five years to comply with the Federal Clean Air Act regulations requiring a reduction in sulfur content in gasoline and diesel fuels, including $9.9 million for low-sulfur diesel compliance in 2006.
     As of December 31, 2005, we had completed substantially all of the expenditures required to meet regulatory requirements under the Voluntary Emission Reduction Permit program, or VERP, sponsored by the Texas Commission on Environmental Quality, or TCEQ, and for Maximum Achievable Control Technologies for petroleum refineries, or MACT II, which required additional air emission controls for certain processing units at our Big Spring refinery.
     The estimated capital expenditures described above are summarized in the table below. If we were to lose our status as a small refiner, expenditures for the low-sulfur gasoline requirements would be accelerated.
                                                         
                                            2011 and          
    2006     2007     2008     2009     2010     Thereafter   Total  
    (dollars in thousands)  
Low-sulfur gasoline
  $     $ 500     $ 1,000     $ 4,877     $ 9,000     $     $ 15,377  
Low-sulfur diesel
    9,930                                     9,930  
 
                                         
Total
  $ 9,930     $ 500     $ 1,000     $ 4,877     $ 9,000     $       $ 25,307  
 
                                         

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     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, in the first quarter of 2005, at a cost of approximately $8.0 million. Chemical catalyst replacement costs associated with the turnaround were approximately $3.1 million. An additional $0.9 million was spent in the third quarter 2005 in connection with a reformer catalyst regeneration which had originally been scheduled for January 2006.
     Between our major turnarounds, we also perform periodic scheduled turnaround projects on various units at our Big Spring refinery.
                                                 
    2006     2007     2008     2009     2010     2011  
    (dollars in thousands)  
Scheduled turnaround costs
  $ 400     $ 700     $ 400     $ 8,750     $ 500     $ 500  
Chemical catalyst costs
    3,970       10,750       7,701       6,596       7,400       5,400  
 
                                   
Total
  $ 4,370     $ 11,450     $ 8,101     $ 15,346     $ 7,900     $ 5,900  
 
                                   
Contractual Obligations and Commercial Commitments
     Information regarding our known contractual obligations of the types described below as of December 31, 2005 is set forth in the following table.
                                         
    Payments Due by Period  
    Less Than                     More Than        
Contractual Obligations   1 Year     1-3 Years     3-5 Years     5 Years     Total  
    (dollars in thousands)  
Long-term debt obligations (a)
  $ 4,487     $ 104,099 (b)   $ 5,023     $ 18,781     $ 132,390  
Operating lease obligations
    12,469       33,061       9,908       6,278       61,716  
Pipelines and Terminals Agreement (c)
    19,621       58,863       39,242       160,238       277,964  
Other commitments (d)
    6,827       8,483       5,654       28,981       49,945  
 
                             
Total obligations
  $ 43,404     $ 204,506     $ 59,827     $ 214,278     $ 522,015  
 
                             
 
(a)   We repaid approximately $24.3 million of outstanding debt with a portion of the proceeds received from our initial public offering, of which $3.6 million was due within one year and $20.7 million was due within five years.
 
(b)   Includes $100.0 million of indebtedness owed under our term facility. We prepaid all amounts outstanding under the term facility in the first quarter of 2006.
 
(c)   Balances represent the minimum committed volume multiplied by the tariff and terminal rates pursuant to the terms of the Pipelines and Terminals Agreement with HEP.
 
(d)   Other commitments include refinery maintenance services costs and management fees to our parent. These management fees were terminated in connection with our initial public offering for an aggregate payment of $6.0 million, of which $2.0 million was paid in August 2005 and the remaining $4.0 million was paid in January 2006.
     As of December 31, 2005, we did not have any capital lease obligations or any agreements to purchase goods or services, other than those included in the table above, that were binding on us and that specified all significant terms.
     Our “other non-current liabilities” are described in our consolidated financial statements included elsewhere in this in this Annual Report on Form 10-K. For most of these liabilities, timing of the payment of such liabilities is not fixed and therefore cannot be determined as of December 31, 2005. However, certain expected payments related to our anticipated pension contributions in 2006 and other post-retirement benefits obligations are discussed in Note 12 of our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
Off-Balance Sheet Arrangements
     We have no off-balance sheet arrangements.

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Critical Accounting Policies
     Our accounting policies are described in the notes to our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. 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, which are discussed below, could materially affect the amounts recorded in our consolidated financial statements.
     Inventory. Crude oil, refined products and blendstocks for the refining and marketing segment are priced at the lower of cost or market value. Cost is determined using the LIFO valuation method. Under the LIFO valuation method, we charge the most recent acquisition costs to cost of sales, and we value inventories at the earliest acquisition costs. We selected this method because we believe it more accurately reflects the cost of our current sales. If the market value of inventory is less than the inventory cost on a LIFO basis, then inventory is written down to market value. An inventory write-down to market value results in a non-cash accounting adjustment, decreasing the value of our crude oil and refined products inventory and increasing our cost of sales. For example, in the second half of 2001, market prices were significantly lower than our inventory cost determined under our LIFO valuation method, which resulted in our recording a non-cash charge of $23.2 million to cost of sales and a corresponding decrease in the value of our crude oil and refined products inventory. In 2002, market prices rose substantially, allowing us to recover $18.6 million of the 2001 inventory write-down to market value with a corresponding non-cash credit to cost of sales. Any such recovery results in a non-cash accounting adjustment, increasing the value of our crude oil and refined products inventory and decreasing our cost of sales. Our results of operations could continue to include such non-cash write-downs and recoveries of inventory if market prices for crude oil and refined products return to levels comparable to those in 2001. A reduction of inventory volumes during 2005 resulted in a liquidation of LIFO inventory layers carried at lower costs which prevailed in previous years. The liquidation decreased cost of sales by approximately $2.4 million in 2005. Market values of crude oil, refined products and blendstocks exceeded LIFO costs by $52.2 million at December 31, 2005.
     Environmental and Other Loss Contingencies. We record liabilities for loss contingencies, including environmental remediation costs, when such losses are probable and can be reasonably estimated. Our environmental liabilities represent the estimated cost to investigate and remediate contamination at our properties. Our estimates are based upon internal and third-party assessments of contamination, available remediation technology and environmental regulations. Accruals for estimated liabilities from projected environmental remediation obligations are recognized no later than the completion of the remedial feasibility study. These accruals are adjusted as further information develops or circumstances change. We do not discount environmental liabilities to their present value unless payments are fixed and determinable, and we record them without considering potential recoveries from third parties. Recoveries of environmental remediation costs from third parties are recorded as assets when receipt is deemed probable. We update our estimates to reflect changes in factual information, available technology or applicable laws and regulations.
     Turnarounds and Chemical Catalyst Costs. We record the cost of planned major refinery maintenance, referred to as turnarounds, and catalysts used in refinery process units, which are typically replaced in conjunction with planned turnarounds, in “other assets” in our consolidated financial statements. Turnaround and catalyst costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround. The amortization of deferred turnaround and chemical catalysts costs are presented in “depreciation and amortization” in our consolidated financial statements.
     Impairment of Long-Lived Assets. We account for impairment of long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment of Disposal of Long-Lived Assets. In evaluating our assets, long-lived assets and certain identifiable intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of an asset to future net cash flows expected to be generated by the asset. If the carrying value of an asset exceeds its expected future cash flows, an impairment loss is recognized based on the excess of the carrying value of the impaired asset over its fair value. These future

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cash flows and fair values are estimates based on our judgment and assumptions. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs of disposition.
     Deferred Income Taxes. Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date.
     Asset Retirement Obligations. Effective January 1, 2003, we adopted Statement No. 143, Accounting for Asset Retirement Obligations, which established accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. An entity is required to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability should be recognized when a reasonable estimate of fair value can be made.
     In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are subjective.
New Accounting Standards and Disclosures
     In December 2004, the FASB issued Statement of Accounting Standards No. 123R, Share-Based Payment (SFAS No. 123R), which requires expensing of stock options and other share-based compensation payments to employees and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing pro forma disclosure only. This standard is effective as of January 1, 2006 and will apply to all awards granted, modified, cancelled or repurchased after that date as well as the unvested portion of prior rewards. Because we use the minimum value method of measuring equity share options for pro forma disclosure purposes under SFAS No. 123, we will apply SFAS No. 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006. The adoption of SFAS No. 123R is not expected to have a material effect on our financial position or results of operations.
     In November 2004, the 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, and is not expected to affect our financial position or results of operations.
     In December 2004, the FASB issued Statement No. 153, “Exchanges of Nonmonetary Assets,” which addresses the measurement of exchanges of nonmonetary assets. Statement No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets, which was previously provided by APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. Statement No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement No. 153 is effective for nonmonetary asset exchanges occurring in interim periods beginning after June 15, 2005. The adoption of Statement No. 153 did not have a material effect on our financial position or results of operations.
     In May 2005, the FASB issued FASB Statement No. 154, “Accounting Changes and Error Corrections.” Statement 154 establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to a newly adopted accounting principle. This statement will be effective for all accounting changes and any error corrections occurring after January 1, 2006.

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     In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Retirement Obligations,” or FIN 47, which requires companies to recognize a liability for the fair value of a legal obligation to perform asset-retirement activities that are conditional on a future event, if the amount can be reasonably estimated. We adopted FIN 47 at December 31, 2005. The impact of adoption had no effect on our consolidated financial statements.
     In December 2004 the FASB issued FASB Staff Position 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. We have included the $1.1 million effects of this special deduction in our calculation of the deferred income tax provision.
     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 generally requires non-monetary exchanges of finished goods inventory within the same line of business be recognized at the carrying value of the inventory transferred. The consensus is to be applied to new buy/sell arrangements entered in reporting periods beginning after March 15, 2006. We do not expect the impact of this EITF Issue No. 04-13 consensus to have a material effect on our financial position or results of operations.
Reconciliation of Amounts Reported Under Generally Accepted Accounting Principles
     Reconciliation of Adjusted EBITDA to amounts reported under generally accepted accounting principles in financial statements.
     EBITDA represents earnings before minority interest, income tax expense, interest expense, depreciation and amortization. Adjusted EBITDA represents EBITDA, exclusive of gain on disposition of assets. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in 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 interests, interest expense, income taxes, 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 “ — Liquidity and Capital Resources — Cash, Cash Equivalents and Short-Term Investment 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.

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     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.
     The following table reconciles net income to EBITDA and Adjusted EBITDA for the years ended December 31, 2005, 2004 and 2003, respectively:
                         
    For the Year Ended December 31,  
    2005     2004     2003  
    (dollars in thousands)  
Net income
  $ 103,988     $ 25,132     $ 14,068  
Minority interest
    5,792       2,565       681  
Income tax expense
    65,518       18,315       9,105  
Interest expense
    19,326       23,704       16,284  
Depreciation and amortization
    20,935       19,064       18,262  
 
                 
EBITDA
    215,559       88,780       58,400  
Gain on disposition of assets
    (38,591 )     (175 )      
 
                 
Adjusted EBITDA
  $ 176,968     $ 88,605     $ 58,400  
 
                 
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Quantitative and Qualitative Disclosure 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.
     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 December 31, 2005, we held approximately 1.8 million barrels of crude and product inventories valued under the LIFO valuation method with an average cost of $30.04 per barrel. Market value exceeded carrying value of LIFO costs by $52.2 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 to $1.8 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 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.

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Table of Contents

     The following table provides information about our derivative commodity instruments as of December 31, 2005:
                                                 
            Wtd Avg     Wtd Avg                    
Description   Contract     Purchase     Sales     Contract     Fair     Gain  
of Activity   Volume     Price     Price     Value     Value     (Loss)  
Futures-long
        $     $     $     $     $  
Futures-short
                                   
Forwards-long (refined products)
    25,000       63.62       71.84       1,590       1,796       206  
Forwards-short (refined products)
                                   
Interest Rate Risk
     As of December 31, 2005, $100.0 million of our outstanding debt was at floating interest rates. This debt was repaid in full on January 19, 2006.
ITEM 8.   CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE.
     The Consolidated Financial Statements and Schedule are included as an annex of this Annual Report on Form 10-K. See the Index to Consolidated Financial Statements and Schedule on page F-1.
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
     None.
ITEM 9A.   CONTROLS AND PROCEDURES.
     Included in this Annual Report on Form 10-K are certifications of our Chief Executive Officer and Chief Financial Officer which are required in accordance with Rule 13a-14 of the Securities Exchange Act of 1934 (the “Exchange Act”). This section includes the information concerning the controls and controls evaluation referred to in the certifications.
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 Exchange Act) 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 SEC’s rules and forms.
Changes in Internal Control Over Financial Reporting
     There has been no change in our internal control over financial reporting during the quarter ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.   OTHER INFORMATION.
     None.

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PART III
ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
     The information concerning our directors set forth under “Corporate Governance Matters — The Board of Directors” in the proxy statement for our May 9, 2006 annual meeting of stockholders (the “Proxy Statement”) is incorporated herein by reference. Certain information concerning our executive officers is set forth under the heading “Business and Properties — Executive Officers of the Registrant” in Item 1 and 2 of this Annual Report on Form 10-K, which is incorporated herein by reference. The information concerning compliance with Section 16(a) of the Exchange Act set forth under “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement is incorporated herein by reference.
     The information concerning our audit committee set forth under “Corporate Governance Matters — Committees of the Board and — Audit Committee” in the Proxy Statement is incorporated herein by reference.
     The information regarding our Code of Ethics set forth under “ Corporate Governance Matters — Corporate Governance Guidelines, Code of Business Conduct and Ethics and Committee Charters” in the Proxy Statement is incorporated herein by reference.
ITEM 11.   EXECUTIVE COMPENSATION.
     The information set forth under “Executive Compensation,” “Compensation Committee Report on Executive Compensation” and “Stockholder Return Performance Graph” in the Proxy Statement is incorporated herein by reference.
ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
     The information set forth under “Security Ownership of Certain Beneficial Holders and Management” in the Proxy Statement is incorporated herein by reference. The information regarding our equity plans under which shares of our common stock are authorized for issuance as set forth under “Equity Compensation Plan Information” in the Proxy Statement is incorporated herein by reference.
ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
     The information set forth under “Certain Relationships and Related Transactions” in the Proxy Statement is incorporated herein by reference.
ITEM 14.   PRINCIPAL ACCOUNTANT FEES AND SERVICES.
     The information set forth under “Independent Public Accountants” in the Proxy Statement is incorporated herein by reference.

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PART IV
ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)   The following documents are filed as part of this report:
 
(1)   Consolidated Financial Statements and Schedule
 
    See Index to Consolidated Financial Statements and Schedule on page F-1.
 
(2)   Exhibits:
 
    Reference is made to the Index of Exhibits immediately preceding the exhibits hereto, which index in incorporated herein by reference.
     
Exhibit No.   Description of Exhibit
 
3.1
  Amended Restated Certificate of Incorporation of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.1 to Form S-1/A, 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/A, 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/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.1 †
  Area License Agreement, dated as of June 2, 1993, between Southwest Convenience Stores, Inc. and The Southland Corporation (incorporated by reference to Exhibit 10.1 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
10.2 †
  Amendment to Area License Agreement and Consent to Assignment, dated as of December 20, 1996, between The Southland Corporation and Permian Basin Investments, Inc. d/b/a Southwest Convenience Stores, Inc. (incorporated by reference to Exhibit 10.2.1 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
10.3 †
  Amendment No. 2 to Area License Agreement, dated as of August 14, 1997, between Southwest Convenience Stores LLC and The Southland Corporation (incorporated by reference to Exhibit 10.2.2 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
10.4
  Trademark License Agreement, dated as of June 31, 2000, among Finamark, Inc., Atofina Petrochemicals, Inc. and SWBU, L.P. (incorporated by reference to Exhibit 10.3 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.5
  First Amendment to Trademark License Agreement, dated as of April 11, 2001, among Finamark, Inc., Atofina Petrochemicals, Inc. and SWBU, L.P. (incorporated by reference to Exhibit 10.4 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.6
  Pipeline Lease Agreement, dated as of January 22, 2001, between Chevron Pipe Line Company and Fin-Tex Pipe Line Company (incorporated by reference to Exhibit 10.5 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.7
  Pipeline Lease Agreement, dated as of February 21, 1997, between Navajo Pipeline Company and American Petrofina Pipe Line Company (incorporated by reference to Exhibit 10.6 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.8
  Contribution Agreement, dated as of January 25, 2005, among Holly Energy Partners, L.P., Holly Energy Partners – Operating, L.P., T & R Assets, Inc., Fin-Tex Pipe Line Company, Alon USA Refining, Inc., Alon Pipeline Assets, LLC, Alon Pipeline Logistics, LLC, Alon USA, Inc. and Alon USA, LP. (incorporated by reference to Exhibit 10.7 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).

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Table of Contents

     
Exhibit No.   Description of Exhibit
 
10.9
  Pipelines and Terminals Agreement, dated as of February 28, 2005, between Alon USA, LP and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.8 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.10
  Master Lease, dated as of October 1, 2002, between SCS Finance I, L.P. and Southwest Convenience Stores, LP (incorporated by reference to Exhibit 10.9 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.11
  Loan Agreement, dated as of October 1, 2002, between GE Capital Franchise Finance Corporation and SCS Finance I, L.P. (incorporated by reference to Exhibit 10.10 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.12
  Equipment Loan and Security Agreement, dated as of October 1, 2002, between GE Capital Franchise Finance Corporation and SCS Finance I, L.P. (incorporated by reference to Exhibit 10.11 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.13
  Master Lease, dated as of October 1, 2002, between SCS Finance II, L.P. and Southwest Convenience Stores, LP. (incorporated by reference to Exhibit 10.12 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.14
  Loan Agreement, dated as of October 1, 2002, between GE Capital Franchise Finance Corporation and SCS Finance II, L.P. (incorporated by reference to Exhibit 10.13 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.15
  Equipment Loan and Security Agreement, dated as of October 1, 2002, between GE Capital Franchise Finance Corporation and SCS Finance II, L.P. (incorporated by reference to Exhibit 10.14 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.16
  Amended and Restated Credit Agreement, dated as of January 14, 2004, among Alon USA, Inc., the lenders listed therein and Credit Suisse First Boston (incorporated by reference to Exhibit 10.15 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.17
  First Amendment, dated as of February 10, 2005, to the Amended and Restated Credit Agreement, dated as of January 14, 2004, among Alon USA, Inc., the lenders listed therein and Credit Suisse First Boston, and the Guarantee and Collateral Agreement, dated as of January 14, 2004, among Credit Suisse First Boston, Alon USA, Inc., the subsidiaries of Alon USA, Inc. identified therein and Alon USA, Inc. (incorporated by reference to Exhibit 10.17 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.18
  Second Amendment, dated as of May 6, 2005, to the Amended and Restated Credit Agreement, dated as of January 14, 2004, among Alon USA Energy, Inc., the lenders listed therein and Credit Suisse First Boston (incorporated by reference to Exhibit 10.18 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.19
  Guarantee and Collateral Agreement, dated as of January 14, 2004, among Credit Suisse First Boston, Alon USA, Inc., the subsidiaries of Alon USA, Inc. identified therein and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.16 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.20
  Amended Revolving Credit Agreement, dated as of January 14, 2004, among Alon USA, LP, the guarantor companies and financial institutions identified therein and Israel Discount Bank of New York (incorporated by reference to Exhibit 10.19 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.21
  First Amendment, dated as of February 10, 2005, to the Amended Revolving Credit Agreement, dated as of January 14, 2005, among Alon USA, LP, the guarantor companies and financial institutions identified therein and Israel Discount Bank of New York (incorporated by reference to Exhibit 10.20 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).

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Exhibit No.   Description of Exhibit
 
10.22
  Second Amendment, dated as of June 16, 2005, to the Amended Revolving Credit Agreement, dated as of January 14, 2005, among Alon USA, LP, the guarantor companies and financial institutions identified therein and Israel Discount Bank of New York (incorporated by reference to Exhibit 10.20.1 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.23
  Amending Revolving Credit Agreement, dated as of February 15, 2006, among Alon USA, LP, the guarantor companies and financial institutions named therein, Israel Discount Bank of New York and Bank Leumi USA (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on February 16, 2006, SEC File No. 001-32567).
 
   
10.24
  Management and Consulting Agreement, dated August 1, 2003, among Alon USA, Inc., Alon Israel Oil Company, Ltd. and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.21 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.25
  Amendment, dated as of June 17, 2005, to the Management and Consulting Agreement, dated as of August 1, 2003, among Alon USA, Inc., Alon Israel Oil Company, Ltd. and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.21.1 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.26
  Registration Rights Agreement, dated as of July 6, 2005, between Alon USA Energy, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.22 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
10.27*
  Executive Employment Agreement, dated as of July 31, 2000, between Jeff D. Morris and Alon USA GP, Inc., as amended on May 4, 2005 (incorporated by reference to Exhibit 10.23 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.28*
  Executive Employment Agreement, dated as of July 31, 2000, between Claire A. Hart and Alon USA GP, Inc., as amended on May 4, 2005 (incorporated by reference to Exhibit 10.24 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.29*
  Executive Employment Agreement, dated as of February 5, 2001, between Joseph A. Concienne, III and Alon USA GP, Inc., as amended on May 4, 2005 (incorporated by reference to Exhibit 10.25 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.30*
  Management Employment Agreement, dated as of October 1, 2002, between Harlin R. Dean and Alon USA GP, LLC, as amended on May 4, 2005 (incorporated by reference to Exhibit 10.26 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.31*
  Amendment, dated as of October 1, 2003, to the Management Employment Agreement, dated as of October 1, 2002, between Harlin Dean and Alon USA GP, LLC, as amended on May 4, 2005 (incorporated by reference to Exhibit 10.26.1 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.32*
  Amendment to Executive/Management Employment Agreement, dated as of November 7, 2005, between Harlin Dean and Alon USA GP, LLC (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on November 8, 2005, SEC File No. 001-32567).
 
   
10.33+*
  Management Employment Agreement, dated September 1, 2000, between Yosef Israel and Alon USA, GP, LLC.
 
   
10.34+*
  Amendment to Executive/Management Employment Agreement, dated May 1, 2005 between Yosef Israel and Alon USA. GP, LLC.
 
   
10.35*
  Annual Cash Bonus Plan (incorporated by reference to Exhibit 10.27 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.36*
  Description of 10% Bonus Plan (incorporated by reference to Exhibit 10.28 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.37*
  Change of Control Incentive Bonus Program (incorporated by reference to Exhibit 10.29 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).

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Table of Contents

     
Exhibit No.   Description of Exhibit
 
   
10.38*
  Description of Director Compensation (incorporated by reference to Exhibit 10.30 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.39*
  Form of Director Indemnification Agreement (incorporated by reference to Exhibit 10.31 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.40*
  Form of Officer Indemnification Agreement (incorporated by reference to Exhibit 10.32 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.41*
  Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.33 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.42
  Liquor License Purchase Agreement, dated as of May 12, 2003, between Southwest Convenience Stores, LLC and SCS Beverage, Inc. (incorporated by reference to Exhibit 10.34 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.43
  Premises Lease, dated as of May 12, 2003, between Southwest Convenience Stores, LLC and SCS Beverage, Inc. (incorporated by reference to Exhibit 10.35 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.44*
  Alon Assets, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.36 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.45*
  Alon USA Operating, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.37 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.46*
  Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended on June 30, 2002 (incorporated by reference to Exhibit 10.38 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.47
  Shareholder Agreement, dated as of July 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended on June 30, 2002 (incorporated by reference to Exhibit 10.39 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.48*
  Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Jeff D. Morris, as amended on June 30, 2002 (incorporated by reference to Exhibit 10.40 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.49
  Shareholder Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Jeff D. Morris, as amended on June 30, 2002 (incorporated by reference to Exhibit 10.41 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.50*
  Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended on June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.42 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.51
  Shareholder Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended on June 30, 2002 (incorporated by reference to Exhibit 10.43 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.52*
  Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended on June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.44 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.53
  Shareholder Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended on June 30, 2002 (incorporated by reference to Exhibit 10.45 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.54*
  Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III, as amended on July 25, 2002 (incorporated by reference to Exhibit 10.46 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).

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Exhibit No.   Description of Exhibit
 
10.55
  Shareholder Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.47 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.56*
  Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III, as amended on July 25, 2002 (incorporated by reference to Exhibit 10.48 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.57
  Shareholder Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.49 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.58*
  Agreement of Principles of Employment, dated as of July 6, 2005, between David Wiessman and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.50 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
10.59*
  Alon USA Energy, Inc. 2005 Incentive Compensation Plan, as amended on November 7, 2005 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on November 8, 2005, SEC File No. 001-32567).
 
   
10.60*
  Agreement, dated as of July 6, 2005, by and among Alon USA Energy, Inc., Alon USA, Inc., Alon USA Capital, Inc., Alon USA Operating, Inc., Alon Assets, Inc., Jeff D. Morris, Claire A. Hart and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.52 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
10.61*
  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).
 
   
10.62*
  Form of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 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 23, 2005, SEC File No. 001-32567).
 
   
10.63*
  Form II of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed by the Company on November 8, 2005, SEC File No. 001-32567).
 
   
10.64
  Purchase and Sale Agreements between Alon Petroleum Pipe Line, LP and Sunoco Pipelines, LP, dated February 13, 2006 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on February 13, 2006, SEC File No. 001-32567).
 
   
21.1+
  List of Subsidiaries of Alon USA Energy, Inc.
 
   
23.1+
  Consent of KPMG LLP.
 
   
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+
  Certification 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.
 
+   Filed herewith.
 
*   Identifies management contracts and compensatory plans or arrangements.
 
  Filed under confidential treatment request.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE
    Page
Audited Consolidated Financial Statements:
   
  F-2
  F-3
  F-4
  F-5
  F-6
  F-8
ALON USA ENERGY, INC. (PARENT COMPANY ONLY)
INDEX TO CONDENSED FINANCIAL STATEMENTS AND SCHEDULE
     
Audited Condensed Financial Statements:
   
  F-32
  F-33
  F-34
  F-35
  F-36

F-1


Table of Contents

Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Alon USA Energy, Inc.:
     We have audited the accompanying consolidated balance sheets of Alon USA Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
     In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Alon USA Energy, Inc. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations, and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
     As discussed in Note 11 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, in 2003.
/s/ KPMG LLP
Dallas, Texas
March 13, 2006

F-2


Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands except share data)
                 
    As of December 31,  
    2005     2004  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 136,820     $ 63,357  
Short-term investments
    185,320        
Accounts and other receivables, net
    89,529       69,328  
Inventories
    79,181       79,329  
Prepaid expenses and other current assets
    6,264       2,441  
 
           
Total current assets
    497,114       214,455  
 
           
Investment in HEP
    22,754        
Property, plant, and equipment, net
    211,410       236,228  
Other assets
    27,502       21,833  
 
           
Total assets
  $ 758,780     $ 472,516  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
               
Current liabilities:
               
Accounts payable
  $ 157,076     $ 103,051  
Accrued liabilities
    48,128       50,846  
Current portion of deferred gain on disposition of assets
    11,427        
Current portion of long-term debt
    4,487       16,115  
 
           
Total current liabilities
    221,118       170,012  
 
           
Other non-current liabilities
    18,345       19,436  
Deferred gain on disposition of assets
    52,433        
Long-term debt
    127,903       171,591  
Deferred income tax liability
    52,422       31,829  
 
           
Total liabilities
    472,221       392,868  
 
           
Commitments and contingencies (Note 19)
               
Minority interest in subsidiaries
    7,066       8,176  
 
           
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; 46,809,857 and 35,001,120 shares issued and outstanding at December 31, 2005 and 2004
    468       350  
Additional paid-in capital
    181,108       8,379  
Accumulated other comprehensive loss, net of income tax
    (2,596 )     (2,261 )
Retained earnings
    100,513       65,004  
 
           
Total stockholders’ equity
    279,493       71,472  
 
           
Total liabilities and stockholders’ equity
  $ 758,780     $ 472,516  
 
           
The accompanying notes are an integral part of these consolidated financial statements.
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ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands except per share data)
                         
    Year Ended December 31,  
    2005     2004     2003  
Net sales
  $ 2,328,507     $ 1,707,564     $ 1,410,766  
Operating costs and expenses:
                       
Cost of sales
    1,990,338       1,469,940       1,215,032  
Direct operating expenses
    93,843       75,742       66,113  
Selling, general and administrative expenses
    73,219       73,554       69,066  
Depreciation and amortization
    20,935       19,064       18,262  
 
                 
Total operating costs and expenses
    2,178,335       1,638,300       1,368,473  
 
                 
Gain on disposition of assets
    38,591       175        
 
                 
Operating income
    188,763       69,439       42,293  
Interest expense
    (19,326 )     (23,704 )     (16,284 )
Equity earnings in HEP
    1,086              
Other income (expense), net
    4,775       277       (1,819 )
 
                 
Income before income tax expense, minority interest in income of subsidiaries, and accounting change
    175,298       46,012       24,190  
Income tax expense
    65,518       18,315       9,105  
 
                 
Income before minority interest in income of subsidiaries and accounting change
    109,780       27,697       15,085  
Minority interest in income of subsidiaries
    5,792       2,565       681  
 
                 
Income before accounting change
    103,988       25,132       14,404  
Cumulative effect of adoption of accounting principle (Note 11)
                336  
 
                 
Net income
  $ 103,988     $ 25,132     $ 14,068  
 
                 
Earnings per share, basic and diluted
  $ 2.61     $ .72     $ .40  
 
                 
Weighted average shares outstanding
    39,889       35,001       35,001  
 
                 
The accompanying notes are an integral part of these consolidated financial statements.
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ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(dollars in thousands)
                                         
                    Accumulated              
            Additional     Other              
    Common     Paid-In     Comprehensive     Retained        
    Stock     Capital     Loss     Earnings     Total  
Balance at January 1, 2003
  $ 350     $ 8,199     $ (1,225 )   $ 25,804     $ 33,128  
Received for shares issued
          40                   40  
Net income
                      14,068       14,068  
Other comprehensive loss:
                                       
Minimum pension liability, net of income tax
                (313 )           (313 )
 
                                     
Total comprehensive income
                                    13,755  
 
                             
Balance at December 31, 2003
    350       8,239       (1,538 )     39,872       46,923  
Received for shares issued
          140                   140  
Net income
                      25,132       25,132  
Other comprehensive loss:
                                       
Minimum pension liability, net of income tax
                (723 )           (723 )
 
                                     
Total comprehensive income
                                    24,409  
 
                             
Balance at December 31, 2004
    350       8,379       (2,261 )     65,004       71,472  
Proceeds from sale of common stock, net
    118       172,729                   172,847  
Dividends
                      (68,479 )     (68,479 )
Net income
                      103,988       103,988  
Other comprehensive loss:
                             
Minimum pension liability, net of income tax
                (335 )           (335 )
 
                                     
Total comprehensive income
                                    103,653  
 
                             
Balance at December 31, 2005
  $ 468     $ 181,108     $ (2,596 )   $ 100,513     $ 279,493  
 
                             
The accompanying notes are an integral part of these consolidated financial statements.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
                         
    Year Ended December 31,  
    2005     2004     2003  
Cash flows from operating activities:
                       
Net income
  $ 103,988     $ 25,132     $ 14,068  
Adjustments to reconcile net income to cash provided by operating activities:
                       
Depreciation and amortization
    20,935       19,064       18,262  
Stock option compensation
    2,336       530       683  
Deferred income tax expense
    16,646       1,669       6,241  
Minority interest in income of subsidiaries
    5,792       2,565       681  
Accrued interest on subordinated notes to stockholders
          3,815       3,665  
Gain on disposition of assets
    (38,591 )     (175 )      
Cumulative effect of adoption of accounting principle
                336  
Changes in operating assets and liabilities:
                       
Accounts and other receivables, net
    (20,201 )     (9,514 )     3,177  
Inventories
    148       (4,256 )     8,970  
Prepaid expenses and other current assets
    (2,107 )     2,575       1,816  
Other assets
    1,279       1,871       1,158  
Accounts payable
    52,895       17,245       9,653  
Accrued liabilities
    (2,718 )     17,902       3,454  
Other non-current liabilities
    (2,507 )     (1,680 )     4,009  
 
                 
Net cash provided by operating activities
    137,895       76,743       76,173  
 
                 
Cash flows from investing activities:
                       
Capital expenditures
    (23,034 )     (27,301 )     (23,391 )
Capital expenditures for turnarounds and catalysts
    (12,041 )     (2,322 )     (1,547 )
Proceeds from disposition of assets
    118,000       317       274  
Purchases of short-term investments, net
    (185,320 )            
Acquisition of minority interest in subsidiary
          (10,000 )     (10,000 )
Acquisition of asphalt business
          (580 )      
Dividends from investment in HEP (net of equity earnings in HEP)
    531              
Minority interest shares purchased
    (5,098 )            
 
                 
Net cash used in investing activities
    (106,962 )     (39,886 )     (34,664 )
 
                 
Cash flows from financing activities:
                       
Proceeds from sale of common stock, net
    172,459       140       1,721  
Dividends paid to minority interest shareholders
    (6,134 )            
Dividends paid to shareholders
    (68,479 )            
Deferred debt issuance costs
          (1,885 )      
Payments on revolving credit facilities, net
          (19,600 )     (29,400 )
Additions to long-term debt
    2,936       100,671       1,546  
Payments on long-term debt
    (58,252 )     (60,082 )     (13,534 )
 
                 
Net cash provided by (used in) financing activities
    42,530       19,244       (39,667 )
 
                 
Net increase in cash and cash equivalents
    73,463       56,101       1,842  
Cash and cash equivalents, beginning of period
    63,357       7,256       5,414  
 
                 
Cash and cash equivalents, end of period
  $ 136,820     $ 63,357     $ 7,256  
 
                 
The accompanying notes are an integral part of these consolidated financial statements.

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    Year Ended December 31,  
    2005     2004     2003  
Supplemental cash flow information:
                       
Cash paid for interest, net of capitalized interest
  $ 18,736     $ 20,536     $ 15,196  
 
                 
Cash paid for income tax, net of tax refunds of $7,306 in 2003
  $ 44,523     $ 15,701     $ (1,562 )
 
                 
Non-cash activities:
                       
Investing activity — receipt of Class B HEP subordinated units as proceeds from disposition of assets
  $ 30,000     $     $  
 
                 
 
                       
Asphalt Business Acquisition:
                       
Property, plant and equipment acquired
  $     $ (3,917 )   $  
Net working capital acquired (accounts and other receivables, net, inventories, accounts payable)
          817        
Net debt assumed
          2,520        
 
                 
Cash used in acquisition of asphalt business
  $     $ (580 )   $  
 
                 
The accompanying notes are an integral part of these consolidated financial statements.
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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
(1) Description and Nature of Business
     In this document, Alon may refer to Alon USA Energy, Inc. and its consolidated subsidiaries or to Alon USA Energy, Inc. or an individual subsidiary.
     Alon USA Energy, Inc. and its subsidiaries engage in the business of refining and marketing of petroleum products, primarily in the Southwestern and South Central regions of the United States. Alon’s business consists of two operating segments: (1) Refining and Marketing and (2) Retail.
     Refining and Marketing Segment. Alon owns and operates a refinery in Big Spring, Texas. The refinery can process a variety of crude oils, including regionally produced sour crude oil or Gulf Coast and imported crude oils transported on the Amdel and White Oil crude pipelines, which connect the refinery to the Gulf Coast. Alon refines crude oil into petroleum products including various grades of gasoline, diesel fuel, petrochemical feedstocks, asphalt and specialty blended asphalts. Alon primarily markets gasoline and diesel under the FINA brand name at approximately 1,250 locations in five states. Alon’s product distribution network includes seven product pipelines and accesses six product terminals, which are owned or accessed through lease or long-term throughput agreements.
     Retail Segment. Alon operates 167 branded 7-Eleven convenience stores in West Texas and New Mexico. These convenience stores typically offer merchandise, food products and motor fuels under the 7-Eleven and FINA brand names. Substantially all of the fuel sold by these stores is produced by Alon’s refinery and is transported to the stores through Alon’s pipeline and terminal networks.
(2) Summary of Significant Accounting Policies
     (a) Basis of Presentation
     The consolidated financial statements include the accounts of Alon Energy and its subsidiaries. All significant intercompany balances and transactions have been eliminated. Minority interest in Alon’s subsidiaries is reported separately in the accompanying consolidated balance sheets. Minority interest in income of subsidiaries is reported net of income taxes and after elimination of significant intercompany transactions.
     On July 6, 2005, Alon (i) increased its authorized common shares to 100,000,000 and (ii) effected a 33,600-for-1 stock split of its common shares, resulting in 35,001,120 common shares outstanding. The earnings per share information and all common share information have been retroactively restated for 2005 and prior periods presented to reflect this stock split (Note 16).
     (b) Use of Estimates
     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
     (c) Revenue Recognition
     Revenues, net of applicable excise taxes, for products sold by both the refining and marketing segment and the retail segment are recorded upon delivery of the products to their customers, which is the point at which title to the products is transferred, the customer has assumed risk of loss, and when payment has either been received or collection is reasonably assured. Transportation, shipping and handling costs incurred are reported in cost of sales.
     Revenues include the sales of certain 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. The results of these linked refined product buy/sell transactions are recorded in sales and cost of sales in the accompanying statement of operations at fair value. In the ordinary course of business, logistical and refinery
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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
production schedules necessitate the occasional sale of crude oil to third parties. All purchases and sales of crude oil are recorded net, in cost of sales in the accompanying statement of operations. Such sales are infrequent and the effects of the sales on operating results are not significant.
     For the year’s ended December 31, 2005, 2004 and 2003, Alon recorded revenues related to linked refined product sales of $35,924, $72,354 and $21,783, respectively. For the years ended December 31, 2005, 2004 and 2003, Alon recorded costs related to linked refined product sales of $36,418, $72,651 and $22,414, respectively.
     (d) Cost Classifications
     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. Cost of goods excludes depreciation and amortization, which is presented separately in the accompanying statement of operations.
     Direct operating expenses, all of which relate to Alon’s refining and marketing segment, include costs associated with the actual operations of the 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 Alon’s crude oil and product pipelines are considered to be transportation costs and are reflected in the cost of sales in the accompanying statement of operations.
     Selling, general and administrative expenses consist primarily of costs relating to the operations of the convenience stores, including labor, utilities, maintenance and retail corporate overhead costs. Refining and marketing segment corporate overhead and marketing expenses are also included in selling, general and administrative expenses.
     Interest expense consists of interest expense, letters of credit and financing fees, amortization of deferred debt issuance costs less capitalized interest.
     (e) Cash and Cash Equivalents
     All highly-liquid instruments with a maturity of three months or less at the time of purchase are considered to be cash equivalents. Cash equivalents are stated at cost, which approximates market value.
     (f) Short-Term Investments
     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 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 seven – 49 days, depending on the terms of the security. These securities are carried at cost, which approximates market value.
     (g) Accounts Receivable
     The majority of accounts receivable are due from companies in the petroleum industry. Credit is extended based on evaluation of the customer’s financial condition and in certain circumstances, collateral, such as letters of credit or guarantees, are required. Credit losses are charged to reserve for bad debts when accounts are deemed uncollectible. Historically such losses have been minimal. Reserve for bad debts is based on a combination of current sales, historical charge-offs and specific accounts identified as high risk.
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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     (h) Inventories
     Crude oil, refined products and blendstocks for the refining and marketing segment are stated at the lower of cost or market. Cost is determined under the last-in, first-out (LIFO) valuation method. Cost of crude oil, refined product, and blendstock inventories in excess of market value are charged to cost of sales. Such charges are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. Materials and supplies are stated at average cost. Cost for the retail segment merchandise inventories is determined under the retail inventory method and cost for retail segment fuel inventories is determined under the first-in, first-out (FIFO) method.
     (iHedging Activity
     Alon follows Statement of Financial Accountings Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, effective January 1, 2001. Alon considers all forwards, futures, and option contracts to be part of its risk management strategy. Alon has elected not to designate derivative contracts as cash flow hedges for financial accounting purposes. Accordingly, net unrealized gains and losses for changes in the fair value on open derivative contracts are recognized in current cost of sales.
     (j) HEP Investment
     The investment in HEP consists of 937,500 of subordinated class B limited partnership units in HEP and is accounted for under the equity method. These units maybe converted into common units after March 2010, or before as described in the limited partnership agreement. The fair market value of 937,500 HEP common units as of December 31, 2005 was $34,584.
     (k) Property, Plant, and Equipment
     The carrying value of property, plant, and equipment includes the fair value of the asset retirement obligation and have been reflected in the accompanying consolidated balance sheets at cost, net of accumulated depreciation.
     Property, plant, and equipment, net of salvage value, are depreciated using the straight-line method at rates based on the estimated useful lives for the assets or groups of assets, beginning in the month following acquisition or completion. Alon capitalizes interest costs associated with major construction projects based on the effective interest rate on aggregate borrowings.
     Leasehold improvements are depreciated on the straight-line method over the shorter of the contractual lease terms or the estimated useful lives.
     Expenditures for major replacements and additions are capitalized. Refining and marketing segment expenditures for routine repairs and maintenance costs are charged to direct operating expense as incurred. Retail segment routine repairs and maintenance costs are charged to selling, general and administrative expense as incurred. The applicable costs and accumulated depreciation of assets that are sold, retired, or otherwise disposed of are removed from the accounts and the resulting gain or loss is recognized.
     (l) Impairment of Long-Lived Assets and Assets to Be Disposed Of
     Long-lived assets and certain identifiable intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of an asset to future net cash flows expected to be generated by the asset. If the carrying value of an asset exceeds its expected future cash flows, an impairment loss is recognized based on the excess of the carrying value of the impaired asset over its fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. These future cash flows and fair values are estimates based on management’s judgment and assumptions.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     (m) Asset Retirement Obligations
     Effective January 1, 2003, Alon adopted Statement No. 143, Accounting for Asset Retirement Obligations, which established accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement costs. The provisions of this statement apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of a long lived asset (Note 11).
     In March of 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Retirement Obligations (“FIN 47”), which requires companies to recognize a liability for the fair value of a legal obligation to perform asset-retirement activities that are conditional on a future event, if the amount can be reasonably estimated. Alon adopted FIN 47 at the end of fiscal 2005. The impact of adoption had no effect on Alon’s consolidated financial statements as all such asset-retirement activities are included in Alon’s asset-retirement obligation under SFAS No. 143.
     (n) Turnarounds and Chemical Catalyst Costs
     Alon records the cost of planned major refinery maintenance, referred to as turnarounds, and chemical catalyst used in the refinery process units, which are typically replaced in conjunction with planned turnarounds, in “other assets” in Alon’s consolidated balance sheet. Turnaround and catalyst costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround. Amortization of deferred turnaround and chemical catalyst costs are presented in “depreciation and amortization” in Alon’s consolidated statement of operations.
     (o) Income Taxes
     Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
     (p) Stock-Based Compensation
     Alon accounts 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. Accordingly, compensation cost for stock options is measured as the excess of the estimated fair value of the common stock over the exercise price and is recognized over the scheduled vesting period on an accelerated basis. Stock compensation expense is presented as selling, general and administrative expenses in the accompanying statements of operations (Note 18).
     Alon uses the minimum value method for calculating the fair value impact of SFAS No. 123, Accounting for Stock-Based Compensation (SFAS No. 123). Accordingly, there is no significant pro forma impact on net earnings and earnings per share from adoption of SFAS No. 123.
     (q) Environmental Expenditures
     Alon accrues for costs associated with environmental remediation obligations when such costs are probable and can be reasonably estimated. Environmental liabilities represent the estimated costs to investigate and remediate contamination at Alon’s properties. This estimate is based on internal and third-party assessments of the extent of the contaminations, the selected remediation technology and review of applicable environmental regulations.
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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
Accruals for estimated costs from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded as assets when the receipt is deemed probable (Note 10). Estimates are updated to reflect changes in factual information, available technology or applicable laws and regulations.
     (r) Earnings Per Share
     Earnings per share is computed by dividing net income by the weighted average of the common shares outstanding. Weighted average shares outstanding for all periods presented reflect the effect of the 33,600-for-one stock split which was effected on July 6, 2005. The shares issued in our initial public offering are reflected in the weighted average shares outstanding at December 31, 2005.
     (s) Other Comprehensive Income
     Comprehensive income consists of net income and other gains and losses affecting stockholders’ equity that, under United States generally accepted accounting principles, are excluded from net income, such as minimum pension liability adjustments and gains and losses related to certain derivative instruments. The balance in other comprehensive loss, net of tax reported in Alon’s consolidated statements of stockholder’s equity consists solely of minimum pension liability adjustments.
     (t) Commitments and Contingencies
     Liabilities for loss contingencies, including environmental remediation costs not within the scope of FASB Statement No. 143, Accounting for Asset Retirement Obligations, arising from claims, assessments, litigation, fines, and penalties and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recorded as assets, and are not offset against the related environmental liability, in accordance with FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts.
     (u) New Accounting Standards and Disclosures
     In December 2004, the FASB issued Statement of Accounting Standards No. 123R, Share-Based Payment (SFAS No. 123R), which requires expensing of stock options and other share-based compensation payments to employees and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing proforma disclosure only. This standard is effective for Alon as of January 1, 2006. Because, as a private company, Alon used the minimum value method of measuring equity share options for pro forma disclosure purposes under SFAS No. 123, Alon will apply SFAS No. 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006. The adoption of SFAS No. 123R is not expected to have a significant effect Alon’s financial position or results of operations.
     In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. This interpretation addresses the consolidation by business enterprises of variable interest entities as defined in the interpretation. The interpretation applies immediately to interests in variable interest entities created after December 31, 2003, and to interests in variable interest entities obtained after December 31, 2003. The adoption of this interpretation in the first quarter of 2004 had no impact on Alon’s consolidated financial statements.
     In November 2004, the 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
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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
is effective for fiscal years beginning after June 15, 2005, and is not expected to affect Alon’s financial position or results of operations.
     In December 2004, the FASB issued Statement No. 153, Exchanges of Nonmonetary Assets, which addresses the measurement of exchanges of nonmonetary assets. Statement No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets, which was previously provided by APB Opinion No. 29, Accounting for Nonmonetary Transactions, and replaces it with an exception for exchanges that do not have commercial substance. Statement No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement No. 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The adoption of Statement No. 153 did not have a material effect Alon’s financial position or results of operations.
     In May 2005, the FASB issued FASB Statement No. 154, Accounting Changes and Error Corrections. Statement 154 establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to a newly adopted accounting principle. This statement will be effective for all accounting changes and any error corrections occurring after January 1, 2006.
     In March of 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Retirement Obligations (“FIN 47”), which requires companies to recognize a liability for the fair value of a legal obligation to perform asset-retirement activities that are conditional on a future event, if the amount can be reasonably estimated. FIN 47 was adopted by Alon at December 31, 2005. The impact of adoption had no effect on Alon’s consolidated financial statements.
     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. Alon has included the $1,111 effects of this special deduction in its calculation of the December 31, 2005 income tax expense.
     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. The consensus is to be applied to new buy/sell arrangements entered in reporting periods beginning after March 15, 2006. Such buy/sell transactions will be recorded as net sales in the statement of operations beginning January 1, 2006. The adoption of EITF Issue No. 04-13 consensus is not expected to have a material effect on Alon’s financial position or results of operations.
(3) Initial Public Offering of Alon
     On August 2, 2005, Alon USA Energy, Inc. completed an initial public offering of 11,730,000 shares of its common stock at a price of $16.00 per share for an aggregate offering price of $187,680. Alon received approximately $172,158 in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15,522, or $1.32 per share. The initial public offering represented the sale of a 25.1% interest in Alon.
     Alon’s use of proceeds from the initial public offering included the distribution of dividends to pre-offering stockholders of record, the prepayment of debt and general corporate purposes (Notes 13, 16 and 21).
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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
(4) Sale of Pipelines and Terminals
     HEP Transaction. On February 28, 2005, Alon completed the contribution of the Fin-Tex, Trust and River product pipelines, the Wichita Falls and Abilene product terminals and the Orla tank farm to Holly Energy Partners, LP (“HEP”). In exchange for this contribution, which is referred to as the HEP transaction, Alon received $120,000 in cash, prior to closing costs of approximately $2,000, and 937,500 subordinated Class B limited partnership units of HEP (“Units”).
     Simultaneously with this transaction, Alon entered into a Pipelines and Terminals Agreement with HEP providing continued access to these assets for an initial term of 15 years and three additional five year renewal terms exercisable at Alon’s sole option. Pursuant to the Pipelines and Terminals Agreement, Alon has committed to transport and store minimum volumes of refined products in these pipelines and terminals. The tariff rates applicable to the transportation of refined products on the pipelines are variable, with a base fee which is reduced for volumes exceeding defined volumetric targets. The agreement provides for the reduction of the minimum volume requirement under certain circumstances. The service fees for the storage of refined products in the terminals are initially set at rates competitive in the marketplace.
     The entire cash consideration of $120,000 was financed by high-yield debt issued by HEP with a 10-year maturity (“HEP Debt”). Alon Pipeline Logistics, LLC, a majority-owned subsidiary of Alon (“Alon Logistics”) entered into an agreement with the general partner of HEP providing for Alon Logistics to indemnify the general partner for cash payments such general partner has to make toward satisfaction of the principal or interest under the HEP Debt following a default by HEP (provided that such cash payments exceed the difference between the amount of HEP Debt over the indemnity amount). The initial indemnity amount was limited to the lower of (a) $110,850 or (b) the outstanding amount of HEP Debt. The indemnity terminates at such time as Alon Logistics no longer holds any HEP units and subject to other terms described in the indemnification agreement. The indemnification amount may be reduced from time to time per terms described in the indemnification agreement. The indemnification obligation is specific to Alon Logistics and does not extend to other Alon entities, even if the HEP units are transferred to such other entities. The fair value of this debt guarantee of $1,075 is recorded in other non-current liabilities in the December 31, 2005 consolidated balance sheet.
     The HEP transaction was recorded as a partial sale for accounting purposes resulting in a pre-tax gain of $102,461, net of transaction costs and the fair value of the indemnity to the general partner of HEP. Alon recognized an initial pre-tax gain of $26,742. The remaining $75,719 of the gain was deferred. As the HEP units received in the transaction are accounted for under the equity method of accounting for investments in limited partnerships, $6,715 of the pro rata gain was deferred and subtracted from the carrying value of the investment in the HEP units. The remaining deferred gain will be recognized as the indemnification obligation is reduced, over a period of approximately 12 years or less depending on circumstances described in the indemnification agreement. Alon exercised its rights under the indemnification agreement to reduce the indemnity amount by $10,000, resulting in an additional gain of $6,499, and a corresponding decrease in the deferred gain balance. The deferred gain is recorded $11,427 as a current liability and $52,433 as a long-term liability in the December 31, 2005 consolidated balance sheet.
(5) 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 2. 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 on operating income.
     (a) Refining and Marketing Segment
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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     The refining and marketing segment includes a complex sour crude oil refinery, its crude oil and refined products pipeline systems and its refined products terminalling operations. Alon’s refinery produces petroleum products including various grades of gasoline, diesel fuel, jet fuel, 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 1,250 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 and food and beverage products to the general public under the 7-Eleven and FINA brand names.
     (cCorporate
     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.
     Segment data as of and for the years ended December 31, 2005, 2004 and 2003 is presented below.
                                 
    Refining and                    
Year ended December 31, 2005   Marketing     Retail     Corporate     Total  
Net sales to external customers
  $ 2,001,970     $ 326,537     $     $ 2,328,507  
Intersegment sales/purchases
    145,420       (145,420 )            
Depreciation and amortization
    14,464       4,557       1,914       20,935  
Operating income (loss)
    188,243       2,925       (2,405 )     188,763  
Total assets
    676,750       69,794       12,236       758,780  
Turnaround, chemical catalyst and capital expenditures
    31,121       3,484       470       35,075  
                                 
    Refining and                    
Year ended December 31, 2004   Marketing     Retail     Corporate     Total  
Net sales to external customers
  $ 1,406,073     $ 301,491     $     $ 1,707,564  
Intersegment sales/purchases
    117,777       (117,777 )            
Depreciation and amortization
    13,392       4,192       1,480       19,064  
Operating income (loss)
    68,611       2,897       (2,069 )     69,439  
Total assets
    389,830       69,949       12,737       472,516  
Turnaround, chemical catalyst and capital expenditures
    25,877       3,134       612       29,623  
                                 
    Refining and                    
Year ended December 31, 2003   Marketing     Retail     Corporate     Total  
Net sales to external customers
  $ 1,132,577     $ 278,189     $     $ 1,410,766  
Intersegment sales/purchases
    92,468       (92,468 )            
Depreciation and amortization
    12,636       4,078       1,548       18,262  
Operating income (loss)
    42,020       2,443       (2,170 )     42,293  
Total assets
    304,046       73,747       9,189       386,982  
Turnaround, chemical catalyst and capital expenditures
    17,716       6,613       609       24,938  
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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     Operating income for each segment consists of net revenues 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 net property, plant and equipment, inventories, short-term investments, cash and cash equivalents, accounts receivables and other assets directly associated with the segment’s operations. Corporate assets consist primarily of corporate headquarters information technology and administrative equipment.
(6) 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 amounts 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.
Commodity Instruments
     Alon occasionally uses crude oil and refined product commodity futures 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 December 31, 2005, Alon held net forward contracts for purchases of 25 thousand barrels of refined products at an average price of $63.62 per barrel with a fair value of $1,796. At December 31, 2004, Alon held net forward contracts for sales of 5 thousand barrels of refined products at an average price of $48.38 per barrel with a fair value of $232. These contracts were not designated as hedges for accounting purposes. Accordingly, net unrealized gains of $206 and losses of $10 were recorded as an adjustment to net sales in the consolidated statement of operations for the years ended December 31, 2005 and 2004, respectively.
     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 Alon’s consolidated financial statements.
(7) Accounts Receivable
     Financial instruments that potentially subject Alon to concentration of credit risk consist primarily of trade accounts receivables. Credit risk is minimized as a result of the credit quality of Alon’s customer base and the large number of customers comprising Alon’s customer base. Alon performs ongoing credit evaluations of its customers and requires letters of credit, prepayments or other collateral or guarantees as management deems appropriate. Alon’s allowance for doubtful accounts is reflected as a reduction of accounts receivable in the consolidated balance
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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollar in thousands except as noted)
sheets. The balance in the allowance account was $1,145 and $1,322 at December 31, 2005 and 2004, respectively. For the three-year period ended December 31, 2005, no sales to a single customer accounted for more than 10% of Alon’s net sales.
(8) Inventories
     Alon’s inventories 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 merchandise inventories is determined under the retail inventory method and cost for convenience store fuel inventories is determined under the first-in, first-out (FIFO) method.
     Carrying value of inventories consisted of the following:
                 
    December 31,  
    2005     2004  
Crude oil, refined products, and blendstocks
  $ 57,822     $ 58,412  
Materials and supplies
    5,880       5,570  
Store merchandise
    12,977       12,860  
Store fuel
    2,502       2,487  
 
           
Total inventories
  $ 79,181     $ 79,329  
 
           
     Crude oil, refined products and blendstock inventories totaled 1,819 barrels and 1,907 barrels as of December 31, 2005 and 2004, respectively. A reduction of inventory volumes during 2005 resulted in a liquidation of LIFO inventory layers carried at lower costs which prevailed in prior years. The liquidation decreased cost of sales by approximately $2,493 in 2005.
     Market values of crude oil, refined products and blendstocks inventories exceeded LIFO costs by $52,198 and $25,756 at December 31, 2005 and 2004, respectively.
(9) Property, Plant, and Equipment, Net
     Property, plant, and equipment consisted of the following:
                 
    December 31,  
    2005     2004  
Refining facilities
  $ 171,346     $ 149,016  
Pipelines and terminals
    27,237       69,289  
Retail
    63,486       59,543  
Other
    10,691       9,323  
 
           
Property, plant, and equipment, gross
    272,760       287,171  
Less accumulated depreciation
    (61,350 )     (50,943 )
 
           
Property, plant, and equipment, net
  $ 211,410     $ 236,228  
 
           
     The useful lives on depreciable assets used to determine depreciation expense were as follows:
     
Refining facilities
  3 — 20 years; average 18 years
Pipelines and terminals
  5 — 25 years; average 23 years
Retail
  5 — 40 years; average 18 years
Other
  3 — 15 years; average 5 years
     Alon capitalized interest of $927, $301, and $297 for the years ended December 31, 2005, 2004, and 2003, respectively.
(10) Other Assets
     Other assets consisted of the following:
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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
                 
    December 31,  
    2005     2004  
Receivable from FINA for environmental costs
  $ 3,257     $ 4,314  
Deferred debt issuance costs
    6,529       8,291  
Deferred turnaround, chemical catalyst cost
    9,865       2,399  
Retail license fees
    3,429       3,429  
Other
    4,422       3,400  
 
           
Total other assets
  $ 27,502     $ 21,833  
 
           
     In connection with the acquisition of the refinery, pipeline and terminal assets from Atofina Petrochemicals, Inc. (“FINA”) in August 2000, FINA agreed to indemnify Alon for the costs of environmental investigations, assessments, and clean-ups of known conditions that existed at the acquisition date. Such indemnification is limited to an aggregate of $20,000 over a ten-year period. Annual indemnification is limited to a ceiling of $5,000 except that the ceiling may be increased by the amount (up to $5,000) in cases by which the previous year’s ceiling exceeded actual costs. FINA retains liability for third-party claims received within ten years of the acquisition alleging personal injury or property damage resulting from FINA’s use of the acquired assets prior to the acquisition. Alon’s management does not expect expenditures for remediation of existing contamination to exceed the indemnification limitations. Alon also has insurance coverage for amounts in excess of $20,000, up to $40,000 during the ten-year indemnification period. Accordingly, at December 31, 2005 and 2004, Alon has recorded a current receivable of $1,750 and $3,000 and a non-current receivable of $3,257 and $4,314 from FINA, respectively, and corresponding accrued environmental liabilities (Note 19).
     Debt issuance costs are amortized over the term of the related debt using the effective interest method. Amortization of deferred debt issuance costs is recorded as interest expense in the accompanying statements of operations. Amortization of debt issuance costs was $1,883, $1,329, and $902 for the years ended December 31, 2005, 2004, and 2003, respectively.
(11) Accrued Liabilities
     Alon’s current accrued liabilities and non-current other liabilities at December 31, 2005 and 2004 consisted of the following:
                 
    December 31,  
    2005     2004  
Accrued Liabilities — Current:
               
Taxes other than income taxes, primarily excise taxes
  $ 21,206     $ 24,217  
Income taxes payable
    7,239       828  
Employee costs
    4,977       5,925  
Other
    14,706       19,876  
 
           
Total accrued liabilities
  $ 48,128     $ 50,846  
 
           
 
               
Accrued Liabilities — Non-Current:
               
Pension and other postemployment benefit liabilities, net (Note 12)
  $ 10,611     $ 11,792  
Environmental accrual (Note 19)
    2,986       4,058  
Asset retirement obligation
    2,211       2,524  
Other
    2,537       1,062  
 
           
Total other non-current liabilities
  $ 18,345     $ 19,436  
 
           
     Alon adopted the Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143), on January 1, 2003 and recognized a $336 cumulative effect of adoption, net of $173 of income tax benefit in connection with future estimated costs for dismantling certain refinery and pipeline assets. SFAS No. 143 requires that Alon record the fair value of liability associated with an asset retirement obligation. No additional accrual was recorded under FIN 47. Alon’s asset retirement obligation relates to the removal of underground storage tanks and debranding costs at Alon’s owned and leased retail sites and the dismantlement and disposal of certain pipeline, terminal, and refinery assets. The asset retirement obligation for storage tank removal
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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
on leased retail sites is accreted over the expected life of the underground storage tank which approximates the average retail site lease term. The following table summarizes the activity relating to Alon’s asset retirement obligations for the years ended December 31, 2005 and 2004:
                 
    December 31,  
    2005     2004  
Balance at beginning of year
  $ 2,524     $ 2,349  
Accretion expense
    53       178  
Retirements
    (366 )     (28 )
Additions
          25  
 
           
Balance at end of year
  $ 2,211     $ 2,524  
 
           
(12) Employee and Postretirement Benefits
     Alon has two defined benefit pension plans covering substantially all of its refining and marketing segment employees. The benefits are based on years of service and the employee’s final average monthly compensation. Alon’s funding policy is to contribute annually not less than the minimum required nor more than the maximum amount that can be deducted for federal income tax purposes. Contributions are intended to provide not only for benefits attributed to service to date but also for those benefits expected to be earned in the future.
     In addition to providing pension benefits, certain health care and life insurance benefits (other benefits) are provided to active and certain retired employees who meet eligibility requirements defined in the plan documents. The health care benefits in excess of certain limits are insured.
     Alon’s retiree medical plan provides prescription drug benefits, which were affected by the Medicare Prescription Drug Improvement and Modernization Act of 2003(the “Act”), signed into law in December 2003. The Act introduces a prescription drug benefit under Medicare (“Medicare Part D”), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In May 2004, the FASB issued FASB Staff Position No. 106-2 (“FSP 106-2”), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which provides guidance for the accounting of the federal subsidy. Alon incorporated the effects of the Act into the regular measurement of plan obligations as of December 31, 2004, which resulted in an immaterial reduction in the accumulated postretirement benefit obligation.
     The measurement dates used to determine pension and other postretirement benefit measures for the pension plan and the postretirement benefit plan is December 31, 2005 and 2004. Financial information related to Alon’s pension plans and other postretirement benefits is presented below.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
                                 
    Pension Benefits     Postretirement Benefits  
    2005     2004     2005     2004  
Change in projected benefit obligation:
                               
Benefit obligation at beginning of year
  $ 31,772     $ 27,356     $ 1,852     $ 3,435  
Service cost
    1,694       1,326       75       160  
Interest cost
    2,068       1,826       112       222  
Plan participants contributions
                      28  
Plan Amendments
    127                   (2,119 )
Actuarial loss (gain)
    4,113       1,980       (110 )     409  
Benefits paid
    (674 )     (716 )     (174 )     (283 )
 
                       
Projected benefit obligations at end of year
  $ 39,100     $ 31,772     $ 1,755     $ 1,852  
 
                       
Change in plan assets:
                               
Fair value of plan assets at beginning of period
    20,114       16,172              
Actual gain on plan assets
    1,883       1,929              
Employer contribution
    3,354       2,729       174       255  
Plan participants contributions
                      28  
Benefits paid
    (674 )     (716 )     (174 )     (283 )
 
                       
Fair value of plan assets at end of period
  $ 24,677     $ 20,114     $     $  
 
                       
Reconciliation of funded status:
                               
Fair value of plan assets at end of year
  $ 24,677     $ 20,114              
Less benefit obligation at end of year
    39,100       31,772       1,755       1,852  
 
                       
Funded status at end of year
    (14,423 )     (11,658 )     (1,755 )     (1,852 )
Unrecognized prior service costs
    100             (3,804 )     (4,117 )
Unrecognized net actuarial loss
    11,983       8,300       1,005       1,183  
 
                       
Accrued benefit costs
  $ (2,340 )   $ (3,358 )   $ (4,554 )   $ (4,786 )
 
                       
Amounts recognized in the consolidated balance sheets:
                               
Accrued benefit liability
  $ (6,656 )   $ (7,005 )   $ (4,554 )   $ (4,786 )
Intangible asset
    94                    
Accumulated other comprehensive loss
    4,222       3,647              
 
                       
Accrued pension cost
  $ (2,340 )   $ (3,358 )   $ (4,554 )   $ (4,786 )
 
                       
     As of December 31, 2005 and 2004, the accumulated benefit obligation for each of Alon’s pension plans was in excess of plan assets. The aggregate benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans were as follows:
                 
    December 31,  
    2005     2004  
Projected benefit obligation
  $ 39,100     $ 31,772  
Accumulated benefit obligation
    31,333       27,118  
Fair value of plan assets
    24,677       20,114  
     The weighted-average assumptions used to determine benefit obligations at December 31, 2005, 2004 and 2003 were as follows:
                                                 
    Pension Benefits   Postretirement Benefits
    2005   2004   2003   2005   2004   2003
Discount rate
    6.00 %     6.00 %     6.25 %     6.00 %     6.00 %     6.25 %
Rate of compensation increase
    3.50 %     3.00 %     3.00 %                  

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Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     The weighted-average assumptions used to determine net periodic benefit costs for the years ended December 31, 2005, 2004 and 2003 were as follows:
                                                 
    Pension Benefits   Postretirement Benefits
    2005   2004   2003   2005   2004   2003
Discount rate
    6.00 %     6.25 %     6.75 %     6.00 %     6.25 %     6.75 %
Expected return on plan assets
    9.00 %     9.00 %     9.00 %                  
Rate of compensation increase
    3.00 %     3.00 %     3.00 %                  
     Alon’s overall expected long-term rate of return on assets is 9.0%. The expected long-term rate of return is based on the portfolio as a whole and not on the sum of the returns on individual asset categories. The return is based exclusively on historical returns.
     For measurement purposes, a 9.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005. The rate was assumed to decrease gradually to 6.0% through 2009 and remain at that level thereafter. The components of net periodic benefit cost for the years and periods are as follows:
                                                 
    Pension Benefits     Postretirement Benefits
    Year Ended December 31     Year Ended December 31
    2005     2004     2003     2005     2004     2003  
Components of net periodic Benefit cost:
                                               
Service cost
  $ 1,694     $ 1,326     $ 1,142     $ 75     $ 160     $ 231  
Interest cost
    2,068       1,826       1,616       112       222       307  
Amortization of prior service costs
    27                   (314 )     (157 )   (38 )
Expected return on plan assets
    (1,996 )     (1,388 )     (1,326 )                  
Recognized net actuarial loss.
    544       563       262       67       29       3  
 
                                   
Net periodic benefit cost
  $ 2,337     $ 2,327     $ 1,694     $ (60 )   $ 254     $ 503  
 
                                   
Plan Assets
     The weighted-average asset allocation of Alon’s pension benefits at December 31, 2005 and 2004 was as follows:
                 
    Pension Benefits
    Plan Assets
    2005   2004
Asset Category:
               
Equity securities
    82.0 %     70.0 %
Debt securities
    8.0 %     30.0 %
Real estate
    10.0 %     0.0 %
 
               
Total
    100.0 %     100.0 %
 
               
     The investment policies and strategies for the assets of Alon’s pension benefits and postretirement benefits plans is to provide returns in excess of the benchmark measured over a rolling five year period. The portfolio is expected to earn long-term returns from capital appreciation and a stable stream of current income. This approach recognizes that assets are exposed to risk and the market value of the plans’ assets may fluctuate from year to year. Risk tolerance is determined based on Alon’s specific risk management policies. In line with the investment return objective and risk parameters, the plans’ mix of assets includes a diversified portfolio of equity fixed-income and real estate investments. Equity investments include a blend of domestic and international stocks of various sizes of capitalization. The aggregate asset allocation is reviewed on an annual basis.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
Cash Flows
     Alon contributed $3,354 and $2,729 to the pension plan for the years ended December 31, 2005 and 2004, respectively, and expects to contribute $2,900 to the pension plan in 2006. There were no employee contributions to the plans.
     The following benefits expected to be paid in each year 2006 — 2010 are $808; $1,078; $937; $1,021; and $1,136, respectively. The aggregate benefits expected to be paid in the five years from 2011 — 2015 are $11,651. The expected benefits are based on the same assumptions used to measure Alon’s benefit obligation at December 31, 2005 and include estimated future employee service.
     During the period from January 1, 2003 through December 31, 2005, the return on plan assets and plan contributions did not increase sufficiently to cover the increase in benefits to be paid to participants. This put the plan into an unfunded accumulated pension obligation position and, in accordance with SFAS No. 87, Employer’s Accounting for Pensions, Alon recorded an unfunded accrued pension cost of $575, $1,196 and $506 at December 31, 2005, 2004 and 2003, respectively. Of the unfunded pension cost $335, net of a $240 tax benefit, $723, net of a $472 tax benefit and $313, net of a $193 tax benefit, was reflected as a component of comprehensive income for the years ended December 31, 2005, 2004 and 2003, respectively.
     The assumed health care cost trend rates used to determine the projected postretirement benefit obligation are as follows:
                 
    December 31,
    2005   2004
Health care cost trend rate for next year
    9.00 %     10.00 %
Rate to which the cost trend rate is assumed to decline
    6.00 %     6.00 %
Year that the rate reaches the ultimate trend rate
    2009       2009  
     Assumed health care cost trend rates have a significant effect on the amounts reported for the health care and life insurance plans. A one-percentage-point change in assumed health care cost trend rates could have the following effects:
                 
    1% Increase   1% Decrease
Effect on total of service and interest components
  $ 8     $ (10 )
Effect on post retirement benefit obligation
    81       (91 )
     Alon sponsors a 401(k) plan in which employees of Alon’s retail segment may participate by contributing up to 15% of their pay after completing one year of service. Alon matches from 25% to 75% of the employee contribution, depending on the employee’s years of service. This match is limited to 6% of employee pay with full vesting of matching and contributions occurring after five years of service. Alon’s contribution for the years ended December 31, 2005 and 2004 was $165 and $164, respectively.
(13)   Long-Term Debt
     A summary of Alon’s long-term debt follows:
                 
    December 31,  
    2005     2004  
Secured term loan
  $ 100,000     $ 100,000  
Revolving credit facility
           
Retail mortgages and equipment loans
    31,989       33,610  
FINA deferred purchase price
          3,978  
Subordinated notes payable
          49,200  
Other debt
    401       918  
 
           
Total debt
    132,390       187,706  
Less current portion
    (4,487 )     (16,115 )
 
           
Total long-term debt
  $ 127,903     $ 171,591  
 
           

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
  (a)   Secured Term Loan
     On January 14, 2004 Alon entered into a senior secured term loan facility (secured term loan) in the aggregate amount of $100,000 maturing in January 2009. The term loan accrues interest at LIBOR (4.37% at December 31, 2005 and 2.56% at December 31, 2004) plus 6.5% per year, but not less than 10% per annum, and is subject to a minimum annual payment of $2,500 per year which can be increased under certain circumstances or declined by lenders as defined in the agreement. This facility includes certain restrictions and covenants, including, among other things, limitations on capital expenditures, dividend restrictions and minimum net worth and coverage ratios. On January 19, 2006 the $100,000 principal was paid in full with available cash on hand (Note 21).
  (b)   Revolving Credit Facility
     As of December 31, 2005, Alon had a revolving credit facility which provides for commitments of $141,600 for a three-year term. In addition, Alon has a separate credit facility for the issuance of letters of credit for up to $20,000. Subject to commitment amounts and terms, the revolving credit facility provides for the issuance of letters of credit and up to $82,000 of which is available for revolving credit loans. The revolving credit facility is primarily used for issuance of letters of credit (principally for crude oil purchases). Alon is charged various fees and expenses in connection with this facility, including facility fees and various letter of credit fees. No amounts were outstanding under this revolving credit facility at December 31, 2005. Amounts outstanding under this revolving credit facility accrue interest at the Eurodollar plus 2.5%. This facility includes certain restrictions and covenants, including, among other things, limitations on capital expenditures, dividend restrictions and minimum net worth and coverage ratios.
     On February 15, 2006 the above revolving credit facility was amended, increasing the facility to $240,000 with a minimum of $160,000 and extending the term to January 2010. Amounts outstanding under this revolving credit facility accrue interest at the Eurodollar rate plus 1.5% per year (Note 21).
     As of December 31, 2005 and 2004, Alon had $131,727 and $100,676, respectively, of outstanding letters of credit under the revolving credit facility and the other credit facility.
  (c)   Retail Mortgages and Equipment Loans
     On October 1, 2002, Alon entered into a $35,000 term loan agreement. The agreement consists of a 20-year $22,300 mortgage loan bearing a fixed interest rate of 8.06% per annum and a 10-year $12,700 equipment loan at a fixed rate of 8.30% per annum, secured by certain property, plant, and equipment used in Alon’s retail segment.
     These mortgages and equipment loans are to be repaid in monthly principal and interest installments of $346 beginning December 1, 2002, decreasing to $187 after December 1, 2012.
     In 2003, Alon obtained $1,545 in mortgage loans to finance the acquisition of new retail locations. The interest rates on these loans range between 5.5% and 9.7%, with 5 to 15 year payment terms.
  (d)   Atofina Deferred Purchase Price
     Deferred payments due to FINA in connection with the acquisition of marketing assets in 2000 were paid in full in August, 2005.
  (e)   Subordinated Notes Payable
     As of December 31, 2004, Alon had unsecured subordinated notes payable to its parent company, Alon Israel (“Alon Israel”) of $36,300, subordinated notes payable to former minority interest owners of $3,700, and subordinated notes payable to certain members of executive management of $13. In 2005 Alon paid the outstanding balances in full.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
  (f)   Maturity of Long-Term Debt
     The aggregate scheduled maturities of long-term debt for each of the five years subsequent to December 31, 2004 are as follows: 2006 — $4,487; 2007 — $4,590; 2008 — $4,795; 2009 — $94,714; 2010 — $2,406 and 2011 and thereafter — $21,398. At December 31, 2005, the debt maturities in 2006 through 2008 reflect the scheduled $2,500 annual payments on the secured term loan and 2009 reflects the $92,500 final payment on the secured term loan. The secured term loan was prepaid on January 19, 2006 (Note 21).
  (g)   Interest and Financing Expense
     Interest and finance expense included in the accompanying statements of operations consisted of the following:
                         
    December 31,  
    2005     2004     2003  
Interest expense
  $ 15,422     $ 19,261     $ 12,868  
Letters of credit and finance costs
    3,385       3,415       2,811  
Amortization of debt issuance costs
    1,446       1,329       902  
Capitalized interest
    (927 )     (301 )     (297 )
 
                 
Total interest expense
  $ 19,326     $ 23,704     $ 16,284  
 
                 
(14)   Income Taxes
     Income tax expense included the following:
                         
    December 31,  
    2005     2004     2003  
Current:
                       
Federal
  $ 41,886     $ 15,554     $ 2,336  
State
    6,986       1,092       528  
 
                 
Total current
    48,872       16,646       2,864  
 
                 
Deferred:
                       
Federal
    16,009       1,487       5,341  
State
    637       182       900  
 
                 
Total deferred
    16,646       1,669       6,241  
 
                 
Income tax expense
  $ 65,518     $ 18,315     $ 9,105  
 
                 
     A reconciliation between the income tax expense computed on pretax income at the statutory federal rate and the actual provision for income taxes is as follows:
                         
    December 31,  
    2005     2004     2003  
Computed expected tax expense
  $ 61,481     $ 16,104     $ 8,349  
State and local income taxes, net of federal benefit
    4,895       828       921  
Deduction for qualified production income
    (1,111 )            
Other, net
    253       1,383       (165 )
 
                 
Income tax expense
  $ 65,518     $ 18,315     $ 9,105  
 
                 

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     The following table sets forth the tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities.
                 
    December 31,  
    2005     2004  
Current deferred income tax assets and liabilities:
               
Accounts receivable, allowance
  $ 327     $  
Deferred gain
    2,009        
Accrued liabilities and other
    205        
Inventories
    (826 )      
 
           
Current deferred income tax assets, net
    1,715        
 
           
Noncurrent deferred income tax liabilities and assets:
               
Deferred charges
          (1,821 )
Inventories
          (1,510 )
Property, plant, and equipment
    (35,370 )     (34,619 )
Other noncurrent
    (19,635 )     (111 )
Post retirement benefits
    1,742       3,722  
Noncurrent accrued liabilities and other
    841       2,510  
 
           
Noncurrent deferred income tax liabilities, net
  $ (52,422 )   $ (31,829 )
 
           
     In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of taxable income and projections for future taxable income, over the periods which the deferred tax assets are deductible, management believes it is more likely than not that Alon will realize the benefits of these deductible differences in future periods.
(15)   Related-Party Transactions
     Alon and Alon Israel are parties to a consulting agreement whereby Alon Israel provides strategic planning and management consulting services to Alon for an annual fee of $1,500 through September 30, 2003 and $4,000 a year beginning October 1, 2003. In July 2005, the term of the agreement was extended until December 31, 2009 and Alon’s payment obligations under the agreement were terminated in exchange for an aggregate payment to Alon Israel of $6,000, $2,000 of which was paid and expensed in 2005 and the remainder of which was paid in the first quarter 2006 and will be amortized over the remaining term of the contract. Alon Israel’s obligations to provide consulting services under the amended agreement will remain in effect through the end of the term of the agreement.
     At January 1, 2005, Alon had subordinated notes payable to Alon Israel, the former minority owners of Alon USA Capital and certain members of executive management totaling $49,200, including accrued interest. All balances outstanding under these notes were paid in full during 2005 (Note 13).
(16)   Stockholders’ Equity
  (a)   Common and preferred stock
     The authorized capital stock of Alon consists of 100,000,000 shares of common stock, $0.01 par value, and 10,000,000 shares of preferred stock, $0.01 par value. Issued and outstanding shares were 46,809,857 and 35,001,120 shares of common stock as of December 31, 2005 and 2004, respectively. There were no issued and outstanding shares of preferred stock as of December 31, 2005 and 2004.
     For the years ended December 31, 2005, 2004 and 2003, activity in the number of common stock was as follows:

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Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
         
    Common
    Stock
    (in thousands)
Balance as of January 1, 2003
    35,001  
Balance as of December 31, 2003
    35,001  
Balance as of December 31, 2004
    35,001  
Sale of common stock
    11,730  
Shares issued in connection with stock plans (Note 18)
    79  
 
       
Balance as of December 31, 2005
    46,810  
 
       
  (b)   Initial Public Offering
     On August 2, 2005 Alon completed an initial public offering of 11,730,000 shares of its common stock at an aggregate price of $187,680 (Note 3).
  (c)   Stock Split
     On July 6, 2005 Alon (i) increased its common stock to 100,000,000 and (ii) effected a 33,600-for-1 stock split of its common shares, resulting in 35,001,120 common shares outstanding. The earnings per share information and all common share information have been retroactively restated for all prior periods presented to reflect this stock split (Note 2).
  (d)   Dividends
     Upon the completion of Alon’s initial public offering on August 2, 2005 (Note 3), the board of directors of each of Alon and Alon USA Operating, Inc. approved the payment of special dividends to pre-offering stock holders of record. The applicable stock holders of record of Alon were paid aggregate cash dividends of $68,479 and the minority interest stockholders of record of Alon USA Operating, Inc were paid aggregate cash dividends of $4,652.
     On February 15, 2006, Alon announced a quarterly and special cash dividend (Note 21).
(17)   Earnings per Share
     Basic earnings per share is calculated as net income divided by the average number of shares of common stock outstanding. Diluted earnings per share included the dilutive effective of restricted shares using the treasury stock method.
                         
    December 31  
    2005     2004     2003  
Net income
  $ 103,988     $ 25,132     $ 14,068  
Average number of shares of common stock outstanding
    39,889       35,001       35,001  
Effect of dilutive restricted shares
    19              
 
                 
Average number of shares of common stock outstanding assuming dilution
    39,908       35,001       35,001  
 
                 
Earnings per share — basic
  $ 2.61     $ .72     $ .40  
 
                 
Earnings per share — diluted
  $ 2.61     $ .72     $ .40  
 
                 
(18)   Stock Based Compensation
     Alon has two employee incentive compensation plans, (i) the 2005 Incentive Compensation Plan and (ii) the 2000 Incentive Stock Compensation Plan.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
  (a)   2005 Incentive Compensation Plan
     The 2005 Incentive Compensation Plan was approved by the stockholders in November, 2005, and is a component of Alon’s overall executive incentive compensation program. The 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 share grants discussed below, there have been no other awards granted under this program.
     In August 2005, Alon granted an award of 10,791 shares of restricted stock to certain directors, officers and key employees in connection with the initial public offering. 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. In November 2005, Alon granted an award of 65,172 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 2005, 2,774 shares of restricted stock were awarded to two of Alon’s non-employee directors with a stock grant date fair value of $18.03 per share. All restricted shares granted under the Incentive Compensation Plan vest over a period of three years, assuming continued service at vesting.
     Pursuant to SFAS No. 123, Accounting for Stock-Based Compensation, Alon has elected to account for its stock-based compensation under APB Opinion No. 25. Under APB Opinion No. 25, Alon uses the intrinsic value method to account for compensation cost related to stock awards. Accordingly, compensation expense is recorded over the vesting period based on the excess of the estimated fair value of the common stock over the exercise price. Alon recognizes stock compensation expense using the accelerated vesting method prescribed by FASB Interpretation No. 28. Such compensation expense amounted to $388 for the year ended December 31, 2005, the first year such awards were available under the 2005 Incentive Compensation Program.
  (b)   2000 Incentive Stock Compensation Plan
     At August 1, 2000 (inception), Alon USA Operating, Inc. (“Alon Operating”) and Alon Assets, Inc (“Alon Assets”), majority owned, fully consolidated subsidiaries of Alon, adopted a stock option plan (the “Plan”) pursuant to which Alon’s board of directors may grant stock options to certain officers and executive management. The 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. All stock options have ten-year terms. 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 (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 $2,336, $530, and $683 at December 31, 2005, 2004, and 2003, respectively.
     The following table summarized the stock option activity for Alon Assets and Alon Operating 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  
 
                       

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Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     At December 31, 2005, the number of options exercisable was 1,212 for Alon Assets and 455 for Alon Operating.
  (c)   Stock Warrants
     At December 31, 2004, Discount Bank Corp. Inc. (“DBC”), the parent company of one of our lenders, held warrants to purchase 1,435 shares of non-voting common stock of Alon Assets and 538 shares of non-voting common stock of Alon Operating for an aggregate exercise price of $659. In 2005 DBC exercised its rights to purchase shares of Alon Assets and Alon Operating and Alon reacquired the shares for an aggregate payment of $3,040.
(19)   Commitments and Contingencies
  (a)   Leases
     Alon has long-term lease commitments for land, office facilities, retail facilities and related equipment and various equipment and facilities used in the storage and transportation of refined products. In most cases Alon expects that in the normal course of business, Alon’s leases will be renewed or replaced by other leases. Alon has commitments under long-term operating leases for certain buildings, land, equipment, and pipelines expiring at various dates over the next fifteen years. Certain long-term operating leases relating to buildings, land and pipelines include options to renew for additional periods. At December 31, 2005, minimum lease payments on operating leases were as follows:
         
Year ending December 31:
       
2006
  $ 12,469  
2007
    11,886  
2008
    10,803  
2009
    10,372  
2010
    7,050  
2011 and thereafter
    9,136  
 
     
Total
  $ 61,716  
 
     
     Total rental expense was $11,235, $12,042, and $13,163 for the years ended December 31, 2005, 2004, and 2003, respectively. Contingent rentals and subleases were not significant.
  (b)   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.
     Under the terms of the Pipelines and Terminals Agreement with HEP, Alon has committed to transport and store minimum volumes of refined products in the pipelines and terminals acquired by HEP for an initial period of 15 years. Tariffs and services fees are set at competitive rates and the agreement provides for a reduction of the minimum volume requirement under certain circumstances.
     Alon is involved in various other claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on Alon’s financial position, results of operations or liquidity.

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Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
  (c)   Environmental
     Alon is subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These rules regulate the discharge of materials into the environment and may require Alon to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites; to compensate others for damage to property and natural resources and 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. Alon may in the future 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. 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.
     In connection with the HEP transaction, Alon entered into an Environmental Agreement with HEP pursuant to which Alon agreed to indemnify HEP against costs and liabilities incurred by HEP to the extent resulting from the existence of environmental conditions at the pipelines or terminals prior to February 28, 2005 or from violations of environmental laws with respect to the pipelines and terminals occurring prior to February 28, 2005. Alon’s environmental indemnification obligations under the Environmental Agreement expire after February 28, 2015. In addition, Alon’s indemnity obligations are subject to HEP first incurring $0.1 million of damages as a result of pre-existing environmental conditions or violations. Alon’s environmental indemnity obligations are further limited to an aggregate indemnification amount of $20.0 million, including any amounts paid by Alon to HEP with respect to indemnification for breaches of Alon’s representations and warranties under the Contribution Agreement. With respect to any remediation required for environmental conditions existing prior to February 28, 2005, Alon has the option under the Environmental Agreement to perform such remediation itself in lieu of indemnifying HEP for their costs of performing such remediation. Pursuant to this option, Alon is continuing to perform the ongoing remediation at the Wichita Falls terminal which is subject to Alon’s environmental indemnity from FINA. Any remediation required under the terms of the Environmental Agreement is limited to the standards under the applicable environmental laws as in effect at February 28, 2005.
     In connection with the sale of the Amdel and White Oil Pipelines, on March 1, 2006, Alon entered into a Purchase and Sale Agreement with Sunoco pursuant to which Alon agreed to indemnify Sunoco against costs and liabilities incurred by Sunoco to the extent resulting from the existence of environmental conditions at the pipelines prior to March 1, 2006 or from violations of environmental laws with respect to the pipelines occurring prior to March 1, 2006. With respect to any remediation required for environmental conditions existing prior to March 1, 2006, Alon has the option under the Purchase and Sale Agreement to perform such remediation itself in lieu of indemnifying Sunoco for their costs of performing such remediation.
     Alon has accrued environmental remediation obligations of $4,736 ($1,750 current payable and $2,986 non-current liability), at December 31, 2005 and $7,058 ($3,000 current payable and $4,058 non-current liability), at December 31, 2004.
     Alon completed the construction of a new $14,600 gasoline desulfurization facility in the fourth quarter 2003, ensuring compliance with the small refiner status regulations mandated by the Federal Clean Air Act, which requires a reduction of the sulfur content in gasoline by January 1, 2004. Alon continues to evaluate new Environmental Protection Agency standards that will require a reduction in sulfur content in diesel fuel manufactured for on-road

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
consumption by 2010. Alon spent approximately $5,113 in 2005 and expects to spend approximately $25,300 over the next five years to comply with these regulations.
     Alon has elected to join the Voluntary Emission Reduction Permit program, sponsored by the Texas Commission on Environmental Quality. This program allows facilities to permit grandfathered emission sources through a phased installation of emission control equipment using ten-year Best Available Control Technology. To qualify as a grandfathered source, the equipment must not have been modified since 1972. Alon’s emission control installation plan ends in December 2006. As of December 31, 2005, Alon had spent approximately $11,151 and had completed substantially all of the expenditures required to meet regulatory requirements under the Voluntary Emission Reduction Permit program.
(20)   Quarterly Information (unaudited)
     
    Selected financial data by quarter is set forth in the table below:
                                         
    Quarters
    First   Second   Third   Fourth   Total Year
2005
                                       
Net sales
  $ 407,974     $ 590,366     $ 648,135     $ 682,032     $ 2,328,507  
Operating income
    44,278       49,475       44,232       50,778       188,763  
Net income
    22,436       27,482       24,388       29,682       103,988  
Earnings per share(1)(2)
  $ .64     $ .79     $ .57     $ .64     $ 2.61  
Weighted average shares outstanding (1)
    35,001       35,001       42,821       46,731       39,889  
 
                                       
2004
                                       
Net sales
  $ 352,723     $ 440,179     $ 445,386     $ 469,276     $ 1,707,564  
Operating income
    8,751       33,815       17,032       9,841       69,439  
Net income
    1,497       15,288       6,100       2,247       25,132  
Earnings per share
  $ .04     $ .44     $ .17     $ .06     $ .72  
Weighted average shares outstanding
    35,001       35,001       35,001       35,001       35,001  
 
(1)   Weighted average shares outstanding and earnings per share for the periods presented reflect the effect of a 33,600-for-one split of Alon’s common shares which was effected on July 6, 2005. On August 2, 2005 Alon completed an initial public offering 11,730,000 shares of its common stock. The shares issued in our initial public offering are reflected in the number of weighted average shares outstanding for the quarters ended September 30, 2005 and December 31, 2005, respectively, and for the year ended December 31, 2005.
 
(2)   Alon granted awards of 78,737 shares of restricted stock under its 2005 Incentive Compensation Plan. There is no dilutive effect on earnings per share.
(21)   Subsequent Events
  (a)   Debt Prepayment
     On January 19, 2006, Alon made a payment of approximately $103,900 in satisfaction of its outstanding borrowings under the secured term loan agreement, including applicable accrued interest and prepayment premiums, with available cash on hand. $100,000 represents a voluntary prepayment of the outstanding principal under the term loan agreement, approximately $3,000 represents a prepayment premium and $900 represents accrued and unpaid interest on the principal balance. Alon entered into the $100,000 term loan facility, on January 14, 2004. The term loan facility matured in January 2009. The $3,000 prepayment premium and $3,894 of unamortized debt issuance costs will be reflected as interest expense in the first quarter 2006 consolidated statement of operations.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
  (b)   Dividend Announcement
     On February 15, 2006 Alon’s Board of Directors announced a quarterly cash dividend of $0.04 per share on the company’s common stock, payable on March 21, 2006 to stockholders of record at the close of business on March 1, 2006. The Board of Directors also announced a special cash dividend of $0.37 per share on the company’s common stock, payable on March 21, to stockholders of record at the close of business on March 1, 2006. In connection with Alon’s cash dividend payment to shareholders on March 21, 2006, Alon’s minority interest owners of Alon Assets and Alon Operating will receive an aggregate cash dividend of approximately $1,088.
  (c)   Revolving Credit Facility Amendment
     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 for, among other things, working capital, acquisitions and other general corporate purposes. The initial size of the facility is $160,000 with options to increase the size to $240,000.
     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 limitation 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 receivable, inventory and related assets. All fixed assets previously securing the facility have been released.
  (d)   Crude Oil Pipelines Disposition
     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 a total consideration of approximately $68,000. In conjunction with the sale of the Amdel and White Oil pipelines, which had been inactive since December 2002, Alon entered into a 10-year pipeline Throughput and Deficiency Agreement with Sunoco Logistics Partners L.P., with an option to extend the agreement by four additional thirty month periods. The Throughput and Deficiency Agreement will allow Alon to maintain our physically integrated system by retaining crude oil transportation rights on the pipelines from the Gulf Coast. Pursuant to the Throughput and Deficiency Agreement, Alon has agreed to ship a minimum of 15,000 barrels per day on the pipelines during the term of the agreement.

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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Alon USA Energy, Inc.:
          Under date of March 13, 2006, we reported on the consolidated balance sheets of Alon USA Energy, Inc. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2005. Our report refers to a change in the method of accounting for asset retirement obligations in 2003. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related consolidated financial statement schedule. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement schedule based on our audits.
          In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
         
 
      /s/ KPMG LLP
      Dallas, Texas
       
      March 13, 2006
       

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ALON USA ENERGY, INC. (PARENT COMPANY ONLY)
CONDENSED BALANCE SHEETS
(dollars in thousands)
     1. (b) SCHEDULES TO THE FINANCIAL STATEMENTS (PARENT ONLY) — SCHEDULE I
                 
    December 31,     December 31,  
    2005     2004  
ASSETS
               
Current assets
  $ 89,298     $ 2,126  
Investment in subsidiary
    190,355       111,558  
 
           
Total assets
  $ 279,653     $ 113,684  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities
  $     $ 511  
Long-term debt
          41,701  
Long-term liabilities
    160        
 
           
Total liabilities
    160       42,212  
 
           
Shareholders’ equity:
               
Shareholders’ investment
    181,576       8,729  
Accumulated other comprehensive loss
    (2,596 )     (2,261 )
Retained earnings
    100,513       65,004  
 
           
Total stockholders’ equity
    279,493       71,472  
 
           
Total liabilities and stockholders’ equity
  $ 279,653     $ 113,684  
 
           

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ALON USA ENERGY, INC. (PARENT COMPANY ONLY)
CONDENSED STATEMENTS OF OPERATIONS
(dollars in thousands)
                         
    For the Year Ended December 31,  
    2005     2004     2003  
Interest income
  $ 1,086     $     $  
General and administrative expenses
    (248 )     (3 )     (7 )
Interest expense
    (1,082 )     (2,946 )     (2,728 )
Other income, net
                20  
 
                 
Loss before income tax benefit and equity earnings in subsidiary
    (244 )     (2,949 )     (2,715 )
Income tax benefit
    101       1,165       1,045  
 
                 
Loss before equity earnings in subsidiary
    (143 )     (1,784 )     (1,670 )
Equity earnings in subsidiary
    104,131       26,916       15,738  
 
                 
Net income
  $ 103,988     $ 25,132     $ 14,068  
 
                 

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ALON USA ENERGY, INC. (PARENT COMPANY ONLY)
CONDENSED STATEMENTS OF CASH FLOWS
(unaudited, dollars in thousands)
                         
    December 31,  
    2005     2004     2003  
Cash flows from operating activities:
                       
Net income
  $ 103,988     $ 25,132     $ 14,068  
Stock compensation
    388              
Adjustments:
                       
Accrued interest on subordinated notes to stockholders
          18       2  
Equity earnings in subsidiary, net
    (104,131 )     (26,916 )     (15,738 )
Changes in operating assets and liabilities:
                       
Other assets
    (222 )        
Other non-current liabilities
    160        
Accounts payable and accrued liabilities
    (558 )     (1,321 )     (366 )
 
                 
Net cash used in operating activities
    (375 )     (3,087 )     (2,034 )
 
                 
 
                       
Cash flows from investing activities:
                       
Purchase of short-term investments
    (29,400 )        
Dividends received from subsidiary
    25,000              
 
                 
Net cash provided by investing activities
    (4,400 )            
 
                 
 
                       
Cash flows from financing activities:
                       
Stock issuance and payments from stockholders
    172,459       140       40  
Dividends paid
    (68,479 )            
Additions to long-term debt
    2,826       2,727        
Payments on long-term debt
    (44,527 )            
 
                 
Net cash provided by financing activities
    62,279       2,867       40  
 
                 
 
                       
Net increase in cash and cash equivalents
    57,504       (220 )     (1,994 )
Cash and cash equivalents, beginning of period
    44       264       2,258  
 
                 
Cash and cash equivalents, end of period
  $ 57,548     $ 44     $ 264  
 
                 

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ALON USA ENERGY, INC. (PARENT COMPANY ONLY)
NOTES TO CONDENSED FINANCIAL STATEMENTS
(unaudited, dollars in thousands, except share and per share data)
(1)   Basis of Presentation
     At December 31, 2005, the agreements governing indebtedness of certain direct and indirect subsidiaries of Alon, such subsidiaries are restricted from making dividend payments, loans or advances to Alon. These restrictions result in restricted net assets (as defined in Rule 4-08(e)(3) of Regulation S-X) of Alon’s direct and indirect subsidiaries exceeding 25% of the consolidated net assets of Alon and its subsidiaries. Upon the prepayment of the secured term loan on January 19, 2006 and the amendment of the revolving credit facility on February 15, 2006, these restrictions are no longer in effect.
     The accompanying condensed financial statements summarize Alon’s unaudited financial position as of December 31, 2005 and December 31, 2004 and the unaudited results of operations and cash flows for the years ended December 31, 2005, 2004 and 2003.
     The Alon USA Energy, Inc. (Parent Company Only) condensed financial statements should be read in conjunction with the consolidated financial statements of Alon and Subsidiaries included elsewhere herein.
(2)   Initial Public Offering
     On August 2, 2005, Alon completed an initial public offering of 11,730,000 shares of its common stock at a price of $16.00 per share for an aggregate offering price of $187,680. Alon received approximately $172,158 in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15,522, or $1.32 per share. The initial public offering represented the sale of a 25.1% interest in Alon (Note 3 of the consolidated financial statements).
(3)   Long-Term Debt
     As of December 31, 2004, Alon had unsecured subordinated notes payable to its parent company, Alon Israel, of $36,300. Alon retired $25,000 of the subordinated debt in February 2005, with the cash received in the form of a dividend from its wholly-owned subsidiary, Alon USA, Inc. The remaining principal and related accrued interest totaling $20,709 was paid in full on August 2, 2005 with proceeds received in Alon’s initial public offering of common stock (Notes 3 and 13 of the consolidated financial statements).
(4)   Dividends Paid
     In August 2005, Alon paid $68,479 in the form of a cash dividend to its pre-offering stockholders of record. The dividend represented a portion of the proceeds from the initial public offering (Notes 3 and 16 of the consolidated financial statements).
(5)   Dividends Received
     In February 2005, Alon received $25,000 in the form of a cash dividend from its wholly-owned subsidiary, Alon USA, Inc. The dividend represented a portion of the proceeds Alon USA, Inc., through its subsidiaries, received as a result of the HEP transaction (Note 4 of the consolidated financial statements).

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Table of Contents

SIGNATURES
     Pursuant to the requirements of Section 13 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.
         
     
  By:   /s/ Jeff D. Morris    
Date: March 14, 2006    Jeff D. Morris   
    Chief Executive Officer   
 
     Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on behalf of the registrant and in the capacities and on the dates indicated have signed this report below.
         
     
Date: March 14, 2006  By:   /s/ David Wiessman    
    David Wiessman   
    Executive Chairman   
 
     
Date: March 14, 2006  By:   /s/ Jeff D. Morris    
    Jeff D. Morris   
    President, Chief Executive Officer and Director   
 
     
Date: March 14, 2006  By:   /s/ Shai Even    
    Shai Even   
    Chief Financial Officer and Treasurer   
 
     
Date: March 14, 2006  By:   /s/ Ron W. Haddock    
    Ron W. Haddock   
    Director   
 
     
Date: March 14, 2006  By:   /s/ Itzhak Bader    
    Itzhak Bader   
    Director   
 
     
Date: March 14, 2006  By:   /s/ Shaul Gliksberg    
    Shaul Gliksberg   
    Director   
 
     
Date: March 14, 2006  By:   /s/ Avraham Baiga Shochat    
    Avraham Baiga Shochat   
    Director   
 
     
Date: March 14, 2006  By:   /s/ Yeshayahu Pery    
    Yeshayahu Pery   
    Director   
 
     
Date: March 14, 2006  By:   /s/ Zalman Segal    
    Zalman Segal   
    Director   


Table of Contents

         
     
Exhibit No.   Description of Exhibit
3.1
  Amended Restated Certificate of Incorporation of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.1 to Form S-1/A, 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/A, 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/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.1 †
  Area License Agreement, dated as of June 2, 1993, between Southwest Convenience Stores, Inc. and The Southland Corporation (incorporated by reference to Exhibit 10.1 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
10.2 †
  Amendment to Area License Agreement and Consent to Assignment, dated as of December 20, 1996, between The Southland Corporation and Permian Basin Investments, Inc. d/b/a Southwest Convenience Stores, Inc. (incorporated by reference to Exhibit 10.2.1 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
10.3 †
  Amendment No. 2 to Area License Agreement, dated as of August 14, 1997, between Southwest Convenience Stores LLC and The Southland Corporation (incorporated by reference to Exhibit 10.2.2 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
10.4
  Trademark License Agreement, dated as of June 31, 2000, among Finamark, Inc., Atofina Petrochemicals, Inc. and SWBU, L.P. (incorporated by reference to Exhibit 10.3 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.5
  First Amendment to Trademark License Agreement, dated as of April 11, 2001, among Finamark, Inc., Atofina Petrochemicals, Inc. and SWBU, L.P. (incorporated by reference to Exhibit 10.4 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.6
  Pipeline Lease Agreement, dated as of January 22, 2001, between Chevron Pipe Line Company and Fin-Tex Pipe Line Company (incorporated by reference to Exhibit 10.5 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.7
  Pipeline Lease Agreement, dated as of February 21, 1997, between Navajo Pipeline Company and American Petrofina Pipe Line Company (incorporated by reference to Exhibit 10.6 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.8
  Contribution Agreement, dated as of January 25, 2005, among Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., T & R Assets, Inc., Fin-Tex Pipe Line Company, Alon USA Refining, Inc., Alon Pipeline Assets, LLC, Alon Pipeline Logistics, LLC, Alon USA, Inc. and Alon USA, LP. (incorporated by reference to Exhibit 10.7 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.9
  Pipelines and Terminals Agreement, dated as of February 28, 2005, between Alon USA, LP and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.8 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.10
  Master Lease, dated as of October 1, 2002, between SCS Finance I, L.P. and Southwest Convenience Stores, LP (incorporated by reference to Exhibit 10.9 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.11
  Loan Agreement, dated as of October 1, 2002, between GE Capital Franchise Finance Corporation and SCS Finance I, L.P. (incorporated by reference to Exhibit 10.10 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.12
  Equipment Loan and Security Agreement, dated as of October 1, 2002, between GE Capital Franchise Finance Corporation and SCS Finance I, L.P. (incorporated by reference to Exhibit 10.11 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).


Table of Contents

     
Exhibit No.   Description of Exhibit
10.13
  Master Lease, dated as of October 1, 2002, between SCS Finance II, L.P. and Southwest Convenience Stores, LP. (incorporated by reference to Exhibit 10.12 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.14
  Loan Agreement, dated as of October 1, 2002, between GE Capital Franchise Finance Corporation and SCS Finance II, L.P. (incorporated by reference to Exhibit 10.13 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.15
  Equipment Loan and Security Agreement, dated as of October 1, 2002, between GE Capital Franchise Finance Corporation and SCS Finance II, L.P. (incorporated by reference to Exhibit 10.14 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.16
  Amended and Restated Credit Agreement, dated as of January 14, 2004, among Alon USA, Inc., the lenders listed therein and Credit Suisse First Boston (incorporated by reference to Exhibit 10.15 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.17
  First Amendment, dated as of February 10, 2005, to the Amended and Restated Credit Agreement, dated as of January 14, 2004, among Alon USA, Inc., the lenders listed therein and Credit Suisse First Boston, and the Guarantee and Collateral Agreement, dated as of January 14, 2004, among Credit Suisse First Boston, Alon USA, Inc., the subsidiaries of Alon USA, Inc. identified therein and Alon USA, Inc. (incorporated by reference to Exhibit 10.17 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.18
  Second Amendment, dated as of May 6, 2005, to the Amended and Restated Credit Agreement, dated as of January 14, 2004, among Alon USA Energy, Inc., the lenders listed therein and Credit Suisse First Boston (incorporated by reference to Exhibit 10.18 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.19
  Guarantee and Collateral Agreement, dated as of January 14, 2004, among Credit Suisse First Boston, Alon USA, Inc., the subsidiaries of Alon USA, Inc. identified therein and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.16 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.20
  Amended Revolving Credit Agreement, dated as of January 14, 2004, among Alon USA, LP, the guarantor companies and financial institutions identified therein and Israel Discount Bank of New York (incorporated by reference to Exhibit 10.19 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.21
  First Amendment, dated as of February 10, 2005, to the Amended Revolving Credit Agreement, dated as of January 14, 2005, among Alon USA, LP, the guarantor companies and financial institutions identified therein and Israel Discount Bank of New York (incorporated by reference to Exhibit 10.20 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.22
  Second Amendment, dated as of June 16, 2005, to the Amended Revolving Credit Agreement, dated as of January 14, 2005, among Alon USA, LP, the guarantor companies and financial institutions identified therein and Israel Discount Bank of New York (incorporated by reference to Exhibit 10.20.1 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.23
  Amending Revolving Credit Agreement, dated as of February 15, 2006, among Alon USA, LP, the guarantor companies and financial institutions named therein, Israel Discount Bank of New York and Bank Leumi USA (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on February 16, 2006, SEC File No. 001-32567).
 
   
10.24
  Management and Consulting Agreement, dated August 1, 2003, among Alon USA, Inc., Alon Israel Oil Company, Ltd. and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.21 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.25
  Amendment, dated as of June 17, 2005, to the Management and Consulting Agreement, dated as of August 1, 2003, among Alon USA, Inc., Alon Israel Oil Company, Ltd. and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.21.1 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).


Table of Contents

     
Exhibit No.   Description of Exhibit
10.26
  Registration Rights Agreement, dated as of July 6, 2005, between Alon USA Energy, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.22 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
10.27*
  Executive Employment Agreement, dated as of July 31, 2000, between Jeff D. Morris and Alon USA GP, Inc., as amended on May 4, 2005 (incorporated by reference to Exhibit 10.23 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.28*
  Executive Employment Agreement, dated as of July 31, 2000, between Claire A. Hart and Alon USA GP, Inc., as amended on May 4, 2005 (incorporated by reference to Exhibit 10.24 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.29*
  Executive Employment Agreement, dated as of February 5, 2001, between Joseph A. Concienne, III and Alon USA GP, Inc., as amended on May 4, 2005 (incorporated by reference to Exhibit 10.25 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.30*
  Management Employment Agreement, dated as of October 1, 2002, between Harlin R. Dean and Alon USA GP, LLC, as amended on May 4, 2005 (incorporated by reference to Exhibit 10.26 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.31*
  Amendment, dated as of October 1, 2003, to the Management Employment Agreement, dated as of October 1, 2002, between Harlin Dean and Alon USA GP, LLC, as amended on May 4, 2005 (incorporated by reference to Exhibit 10.26.1 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.32*
  Amendment to Executive/Management Employment Agreement, dated as of November 7, 2005, between Harlin Dean and Alon USA GP, LLC (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on November 8, 2005, SEC File No. 001-32567).
 
   
10.33+*
  Management Employment Agreement , dated September 1, 2000, between Yosef Israel and Alon USA, GP, LLC.
 
   
10.34+*
  Amendment to Executive/Management Employment Agreement, dated May 1, 2005 between Yosef Israel and Alon USA. GP, LLC.
 
   
10.35*
  Annual Cash Bonus Plan (incorporated by reference to Exhibit 10.27 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.36*
  Description of 10% Bonus Plan (incorporated by reference to Exhibit 10.28 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.37*
  Change of Control Incentive Bonus Program (incorporated by reference to Exhibit 10.29 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.38*
  Description of Director Compensation (incorporated by reference to Exhibit 10.30 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.39*
  Form of Director Indemnification Agreement (incorporated by reference to Exhibit 10.31 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.40*
  Form of Officer Indemnification Agreement (incorporated by reference to Exhibit 10.32 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.41*
  Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.33 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
 
   
10.42
  Liquor License Purchase Agreement, dated as of May 12, 2003, between Southwest Convenience Stores, LLC and SCS Beverage, Inc. (incorporated by reference to Exhibit 10.34 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.43
  Premises Lease, dated as of May 12, 2003, between Southwest Convenience Stores, LLC and SCS Beverage, Inc. (incorporated by reference to Exhibit 10.35 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).


Table of Contents

     
Exhibit No.   Description of Exhibit
10.44*
  Alon Assets, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.36 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.45*
  Alon USA Operating, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.37 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.46*
  Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended on June 30, 2002 (incorporated by reference to Exhibit 10.38 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.47
  Shareholder Agreement, dated as of July 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended on June 30, 2002 (incorporated by reference to Exhibit 10.39 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.48*
  Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Jeff D. Morris, as amended on June 30, 2002 (incorporated by reference to Exhibit 10.40 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.49
  Shareholder Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Jeff D. Morris, as amended on June 30, 2002 (incorporated by reference to Exhibit 10.41 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.50*
  Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended on June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.42 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.51
  Shareholder Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended on June 30, 2002 (incorporated by reference to Exhibit 10.43 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.52*
  Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended on June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.44 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.53
  Shareholder Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended on June 30, 2002 (incorporated by reference to Exhibit 10.45 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.54*
  Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III, as amended on July 25, 2002 (incorporated by reference to Exhibit 10.46 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.55
  Shareholder Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.47 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.56*
  Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III, as amended on July 25, 2002 (incorporated by reference to Exhibit 10.48 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.57
  Shareholder Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.49 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.58*
  Agreement of Principles of Employment, dated as of July 6, 2005, between David Wiessman and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.50 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
10.59*
  Alon USA Energy, Inc. 2005 Incentive Compensation Plan, as amended on November 7, 2005 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on November 8, 2005, SEC File No. 001-32567).


Table of Contents

     
Exhibit No.   Description of Exhibit
10.60*
  Agreement, dated as of July 6, 2005, by and among Alon USA Energy, Inc., Alon USA, Inc., Alon USA Capital, Inc., Alon USA Operating, Inc., Alon Assets, Inc., Jeff D. Morris, Claire A. Hart and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.52 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
 
   
10.61*
  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).
 
   
10.62*
  Form of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 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 23, 2005, SEC File No. 001-32567).
 
   
10.63*
  Form II of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed by the Company on November 8, 2005, SEC File No. 001-32567).
 
   
10.64
  Purchase and Sale Agreements between Alon Petroleum Pipe Line, LP and Sunoco Pipelines, LP, dated February 13, 2006 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on February 13, 2006, SEC File No. 001-32567).
 
   
21.1+
  List of Subsidiaries of Alon USA Energy, Inc.
 
   
23.1+
  Consent of KPMG LLP.
 
   
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+
  Certification 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.
 
+   Filed herewith.
 
*   Identifies management contracts and compensatory plans or arrangements.
 
  Filed under confidential treatment request.