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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, 2006
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. þ
     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 þ            Non-Accelerated Filer o
     Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes o No þ
     The aggregate market value for the Registrant’s common stock held by non-affiliates as of June 30, 2006, the last day of the Registrant’s most recently completed second fiscal quarter was $408,336,719.
     As of March 1, 2007, 46,806,443 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 8, 2007, which is incorporated into Part III of this Form 10-K.
 
 

 


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 First Amendment to Amended Revolving Credit Agreement
 Executive Employment Agreement
 Consent of KPMG LLP
 Certification 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 Annual Report, 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 a Delaware corporation formed in 2000 to acquire the Big Spring, Texas refinery and related pipeline, terminal and marketing assets from Atofina Petrochemicals, Inc., or FINA. In 2006, we acquired three additional refineries in Paramount and Long Beach, California and Willbridge, Oregon, together with the related pipeline, terminal and marketing assets, through the acquisitions of Paramount Petroleum Corporation and Edgington Oil Company. As of December 31, 2006 we also operated 206 7-Eleven branded convenience stores in West Texas and New Mexico. Our principal executive offices are located at 7616 LBJ Freeway, Suite 300, Dallas, Texas 75251, and our telephone number is (972) 367-3600. Our website can be found at www.alonusa.com.
     On July 28, 2005, our stock began trading on the New York Stock Exchange under the trading symbol “ALJ.” 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 72.3% 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 and also of Dor Alon Energy in Israel, a leading Israeli marketer, developer and operator of gas stations and shopping centers.
     We file annual, quarterly and current reports and proxy statements, and file or furnish other information, with the Securities Exchange Commission (“SEC”). Our SEC filings are available to the public over the Internet at the SEC’s web site at www.sec.gov. In addition, we make our SEC filings available free of charge through our internet website at www.alonusa.com as soon as reasonably practicable after we electronically file, or furnish, such material with the SEC. In addition, we will provide copies of our filings free of charge to our stockholders upon request to Alon USA Energy, Inc., Attention: Investor Relations, 7616 LBJ Freeway, Suite 300, Dallas, Texas 75251. We have also made the following documents available free of charge through our internet website at www.alonusa.com:
    Compensation Committee Charter;
 
    Audit Committee Charter;
 
    Corporate Governance Guidelines; and
 
    Code of Business Conduct and Ethics.
     We submitted our annual certification concerning corporate governance to the New York Stock Exchange on August 28, 2006 pursuant to section 303A.12(a) of the New York Stock Exchange Listed Company Manual.

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BUSINESS
     We are an independent refiner and marketer of petroleum products operating primarily in the South Central, Southwestern and Western regions of the United States. Our four sour and heavy crude oil refineries are located in Texas, California and Oregon and have a combined throughput capacity of approximately 170,000 barrels per day (“bpd”). Our refineries produce petroleum products including various grades of gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt, and other petroleum-based products. Our refineries located in Paramount and Long Beach are included in our refining and marketing segment, while our refinery in Willbridge, Oregon is included in our asphalt segment.
     Following the acquisitions of Paramount Petroleum Corporation and Edgington Oil Company in 2006, we began reporting our operating results in three operating segments: (1) refining and marketing, (2) asphalt and (3) retail. Additional information regarding our operating segments and properties is presented in Note 6 to our consolidated financial statements included elsewhere in this Annual Report on
Form 10-K.
Refining and Marketing
     Our refining and marketing segment includes three sour and heavy crude oil refineries that are located in Big Spring, Texas, and Paramount and Long Beach, California. These three refineries have a combined throughput capacity of approximately 158,000 bpd. At these refineries we refine crude oil into petroleum products, including gasoline, diesel, jet fuel, petrochemicals, feedstocks and asphalts, which are marketed primarily in the South Central, Southwestern and Western United States.
Big Spring Refinery
     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 Big Spring refinery is characterized as a “cracking refinery.” Major processing units at our Big Spring refinery include fluid catalytic cracking (“FCC”), naphtha reforming, vacuum distillation, hydrotreating and alkylation units. 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 approximately 93% of the Big Spring refinery’s crude oil input.
     Our Big Spring refinery produces gasoline, ultra low sulfur diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum products. This refinery typically converts approximately 90% of its feedstock into finished products such as gasoline, diesel, jet fuel and petrochemicals, with the remaining 10% primarily converted to asphalt and liquefied petroleum gas.
     During each full year of operations since our acquisition from FINA, we have averaged over 90% 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:

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    Year Ended December 31,
    2006   2005   2004
    Bpd   %   Bpd   %   Bpd   %
Refinery throughput:
                                               
Sweet crude
    2,987       4.6       5,072       7.8       4,321       7.0  
Sour crude
    58,529       89.4       55,643       86.0       53,646       87.0  
Blendstocks
    3,897       6.0       4,040       6.2       3,697       6.0  
 
                                               
Total refinery throughput (1)
    65,413       100.0       64,755       100.0       61,664       100.0  
 
                                               
 
                                               
Refinery production:
                                               
Gasoline
    29,671       46.0       29,499       45.8       28,711       46.8  
Diesel/jet
    20,651       32.0       21,903       34.0       19,939       32.5  
Asphalt
    6,147       9.5       5,824       9.1       5,781       9.4  
Petrochemicals
    4,465       6.9       4,256       6.6       4,492       7.3  
Other
    3,627       5.6       2,911       4.5       2,449       4.0  
 
                                               
Total refinery production (2)
    64,561       100.0       64,393       100.0       61,372       100.0  
 
                                               
 
                                               
Refinery utilization (3)
    90.8 %             94.3 %             95.0 %        
 
(1)   Total refinery throughput represents the total of crude oil and blendstock inputs in the refinery production process.
 
(2)   Total refinery production represents the bpd of various finished products produced from processing oil and other refinery feedstocks through the crude units and other conversion units at our Big Spring refinery.
 
(3)   Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds. In March 2005, we expanded the crude oil throughput capacity of the Big Spring refinery from 62,000 bpd to 70,000 bpd.
     Refinery throughput and production for 2006 reflects the effects of downtime associated with a planned turnaround in May 2006 for the installation and start-up of equipment to permit the Big Spring refinery to satisfy the ultra low sulfur diesel standards of the U.S. Environmental Protection Agency (“EPA”) and of reduced crude oil capacity due to a restriction in the crude vacuum tower heater during the months of June to December of 2006. Due to the vacuum tower heater restriction, average refinery throughput for the last two quarters of 2006 was 67,400 bpd compared to 70,529 bpd for the first quarter of 2006. Refinery throughput and production for 2005 reflects the effect of the downtime associated with a planned major turnaround and refinery expansion in the first quarter 2005. Following the expansion, 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.
          Big Spring Refinery Raw Material Supply
     Sour crude oil has typically accounted for over 90% of our crude oil input at the Big Spring refinery, of which approximately 93% has been West Texas Sour, or WTS, crude oil. Our Big Spring refinery is the closest refinery 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.
     Approximately 67% of our Big Spring refinery’s crude oil input 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. A small amount of locally gathered crude oil is also delivered directly to our Big Spring refinery. The remainder of the Big Spring refinery’s crude oil input requirements are purchased on the spot market. In addition, access to the Amdel and White Oil pipeline gives us the ability to optimize our refinery crude slate by transporting foreign and domestic crude oils to our Big Spring refinery from the Gulf Coast when the economics for processing those crude oils are more favorable than processing locally-sourced crude oils. Other

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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.
          Crude Oil Pipelines
     We receive WTS crude oil and West Texas Intermediate, or WTI, a light sweet crude oil, primarily from regional common carrier pipelines. We also have access to offshore 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. The crude oil pipelines we utilize provide our refinery access to Permian Basin crude oil and foreign and offshore domestic crude oil from the Gulf Coast, allowing us to optimize our Big Spring refinery’s crude oil supply at any given time. The crude oil pipelines we utilize consist of the following:
                 
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
Centurion
  Owned (leased to Centurion)     3     Centurion 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 Big Spring refinery through the 4-mile long, 16-inch diameter Mesa Interconnect pipeline which is connected to the Mesa pipeline system, a common carrier, and through our 3-mile long, 12-inch diameter connection pipeline which is leased to Centurion Pipeline L.P. (“Centurion”) and connected to the Centurion 12-inch and 8-inch diameter pipeline system from Midland, Texas to Roberts Junction.
     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, Inc., or 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 Sunoco, with an option to extend the agreement by four additional thirty-month periods. The Throughput and Deficiency Agreement allows us to maintain crude oil transportation rights on the pipelines from the Gulf Coast and from Midland to the Big Spring refinery. Pursuant to the Throughput and Deficiency Agreement, we have agreed to ship a minimum of 15,000 bpd on the pipelines during the term of the agreement. We commenced shipments of crude oil through the Amdel and White Oil pipelines under this agreement in October 2006.
     To further diversify crude oil delivery sources to our Big Spring refinery, we entered into a 15-year arrangement with Centurion in June, 2006. Pursuant to this arrangement, Centurion will provide us with crude oil transportation pipeline capacity, and we will ship a minimum of 21,500 bpd of crude oil from Midland to our Big Spring refinery using Centurion’s approximately forty-mile long pipeline system from Midland to Roberts Junction and our three mile pipeline from Roberts Junction to the Big Spring refinery which we lease to Centurion. We commenced shipments of crude oil through these pipelines in November 2006.
          Big Spring Refinery Production
     Gasoline. Gasoline has typically accounted for approximately 46% of our Big Spring 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 Big Spring 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 32% of our Big Spring refinery’s production. Following completion of our ultra low sulfur diesel project in May 2006, all of the on-road specification diesel fuel we produce meets the EPA’s ultra low sulfur diesel standard of 15 ppm (parts per million). 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.

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     Asphalt. Asphalt has typically accounted for approximately 10% of our Big Spring refinery’s production. Approximately 64% of our Big Spring refinery’s asphalt production is blended paving grades and 36% is asphalt blendstocks. 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. Because FINA ceased supplying rubber modifiers in the United States in the first quarter of 2005, we have been purchasing rubber modifiers from other sources since that time. Our 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. Asphalt produced at the Big Spring refinery is transferred to our asphalt segment at bulk wholesale market prices.
     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. Our Big Spring refinery has 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.
          Big Spring Refinery Transportation Fuel Marketing
     Our refining and marketing segment sales include sales of refined products from our Big Spring refinery in both the wholesale rack and bulk markets. Our marketing of transportation fuels produced at our Big Spring refinery is focused on five states in the Southwestern and South Central regions of the United States through our physically integrated and non-integrated systems.
     We market transportation fuels produced at our Big Spring refinery in West and Central Texas, Oklahoma, New Mexico and Arizona, which we refer to as our physically integrated system because we supply our FINA-branded and unbranded distributors in this region with motor fuels produced at our Big Spring refinery and distributed through a network of pipelines and terminals which we either own or have access to through leases or long-term throughput agreements. Our physically integrated system includes more than 650 of the approximately 1,200 FINA-branded retail sites that we supply, including our retail segment convenience stores. Our refining and marketing segment also markets motor fuels in East Texas and Arkansas, which we refer to as our non-integrated system because we supply our branded and unbranded distributors in this region with motor fuels we obtain from third parties.
     Branded Transportation Fuel Marketing. We primarily market gasoline and diesel fuels through a network of approximately 1,200 locations under the FINA brand name, which includes our 206 owned or leased 7-Eleven branded convenience stores located in Texas and New Mexico. During 2006, we sold over 35,000 bpd of gasoline and diesel fuel as branded fuels. Approximately 64% 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. 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 the diesel fuel, and 18.5% of the gasoline, produced at our Big Spring refinery on an unbranded basis. During 2006, we sold over 19,000 bpd of our Big Spring refinery’s diesel fuel and gasoline production as unbranded fuels, which were largely sold through our physically integrated system.
     Jet Fuel Marketing. We market substantially all the jet fuel produced at our Big Spring refinery 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

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Abilene, Texas and Sheppard Air 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.
          Big Spring Product Pipelines
     The product pipelines we utilize to deliver refined products from our Big Spring refinery are linked to the major third-party product pipelines in the geographic area around our Big Spring refinery. These pipelines provide 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 Delek 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:
                         
                    Expiration
Product Pipelines   Access   Miles   Connections   Date
Plains (1)
  Lease     38     Coahoma and Midland     2007  
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 Base     2020  
River
  HEP throughput     47     Wichita Falls and Duncan (Magellan)     2020  
Carswell
  Owned     148     Abilene and Fort Worth     N/A  
 
(1)   The description of the Plains pipeline does not include a four-mile pipeline that we own that connects Big Spring and Coahoma.
     In February 2005, we completed the contribution of our Fin-Tex, Trust, River and Dyess JP-8 product pipelines, and certain of our product terminals connected to these pipelines to Holly Energy Partners, LP (“HEP’). Simultaneous 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 5 of our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
     The Plains, Fin-Tex and Holly pipelines make up the Fin-Tex system. Our access to the Plains and Holly pipelines is secured by pipeline 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 the Big Spring refinery to El Paso, Texas and allows product 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.
     The Trust pipeline connects our Big Spring refinery to terminals in Abilene and Wichita Falls, while the River pipeline connects the terminal in Wichita Falls to our Duncan, Oklahoma 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.

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     Our Carswell pipeline system runs from Abilene to Fort Worth, Texas. The Carswell pipeline is currently inactive.
          Product Terminals
     We primarily utilize the following six product terminals for delivery of transportation fuels produced at our Big Spring refinery, of which three are owned and three are accessed through our Pipelines and Terminal Agreement with HEP:
                     
        Working        
Terminals   Access   Capacity (1)   Supply Source   Mode of Delivery
Big Spring, Texas (2)
  Owned     331     Pipeline/refinery   Pipeline/truck
Abilene, Texas
  HEP     111     Pipeline   Pipeline/truck
Wichita Falls, Texas
  HEP     155     Pipeline   Truck
Duncan, Oklahoma
  Owned (3)     154     Pipeline   Pipeline
Orla, Texas
  HEP     116     Pipeline   Pipeline
Southlake, Texas
  Owned     212     Pipeline   Truck
 
                   
Total
        1,079          
 
                   
 
(1)   Measured in thousands of barrels.
 
(2)   Includes the tankage located at our Big Spring refinery.
 
(3)   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 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.
West Coast Refineries and Terminals
     On August 4, 2006, we completed the purchase of the stock of Paramount Petroleum Corporation, a heavy crude oil refining company. Paramount Petroleum Corporation’s assets included refineries located in Paramount, California and Willbridge, Oregon with a combined refining capacity of 66,000 bpd, seven asphalt terminals located in Washington (Richmond Beach), California (Elk Grove and Mojave), Arizona (Phoenix, Fredonia and Flagstaff), and Nevada (Fernley) (50% interest), and a 50% interest in Wright Asphalt Products Company (“Wright”), which specializes in patented ground tire rubber modified asphalt products. Total consideration for the acquisition consisted of approximately $504.0 million, including the retirement of all of the Paramount Petroleum Corporation debt at closing of approximately $183.0 million and working capital of approximately $166.0 million.
     On September 28, 2006, we completed the acquisition of Edgington Oil Company, a heavy crude oil refining company located in Long Beach, California. Edgington Oil Company’s assets included a topping refinery with a nameplate capacity of approximately 40,000 bpd. Total consideration for the acquisition consisted of approximately $93.0 million in cash, including approximately $34.0 million for the value of certain inventories at closing.
     Our refineries located in Paramount and Long Beach are included in our refining and marketing segment, while our refinery in Willbridge is included in our asphalt segment.
     Our Paramount refinery has a crude oil throughput capacity of 54,000 bpd and is located on 63 acres in Paramount, California. In industry terms, the Paramount refinery is characterized as a “hydroskimming refinery.”

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     Our Long Beach refinery has a crude oil throughput capacity of 40,000 bpd and is located on 19 acres in Long Beach, California. Prior to our acquisition of Edgington Oil Company, the Long Beach refinery averaged approximately 9,000 bpd of throughput, which we increased to an average of 15,000 bpd of throughput in the fourth quarter of 2006. In industry terms, the Long Beach refinery is characterized as a “topping refinery.”
     Our Paramount and Long Beach refineries have the capability to process substantial volumes of less expensive sour and heavy crude oils. Since our acquisition of the Paramount and Long Beach refineries, sour crude oil has accounted for approximately 62.3% of crude oil input at these refineries and heavy crude oil has accounted for 37.7%. The Paramount and Long Beach refineries are connected by a pipeline owned by us. Following our acquisition of these refineries, asphalt is the only finished product produced at the Long Beach refinery. Approximately 70% of the unfinished motor fuels, jet fuel and other products produced at the Long Beach refinery are transferred to the Paramount refinery via our pipeline connection and by trucks for final processing and marketing, with the remainder sold to other area refineries and third parties. Because we operate the Long Beach refinery as an extension of the Paramount refinery, we refer to these refineries collectively as the “California refineries.” Major processing units at the California refineries include naphtha reforming, vacuum distillation, hydrotreating and Isom units.
     Our California refineries produce CARBOB gasoline, CARB diesel, jet fuel, asphalt and other petroleum products. Since our acquisition of the California refineries in 2006, these refineries converted approximately 30.5% of crude oil into higher value products such as gasoline, diesel and jet fuel, with 34.1% primarily converted to asphalt, fuel oil and sulfur. The remaining 35.4% of production at our California refineries was sold as unfinished feedstocks to other refineries and third parties.
     Since our acquisition of the California refineries, we have averaged approximately 83.8% utilization of our crude oil throughput capacity. The following table summarizes 2006 throughput and production data for our California refineries on a combined basis since the respective dates of their acquisition.
                 
    Period Ended December 31, 2006 (1)
    Bpd   %
Refinery throughput:
               
Sour crude
    37,171       61.9  
Heavy crude
    22,533       37.5  
Blendstocks
    362       .6  
 
               
Total refinery throughput (2)
    60,066       100.0  
 
               
 
               
Refinery production:
               
Gasoline
    6,806       11.6  
Diesel/jet
    11,026       18.9  
Asphalt
    19,500       33.3  
Other
    12,126       20.7  
Light Unfinished
    6,144       10.5  
Heavy Unfinished
    2,938       5.0  
 
               
Total refinery production (3)
    58,540       100.0  
 
               
 
               
Refinery utilization (4)
    83.8 %        
 
(1)   Represents throughput and production data for the period from August 1, 2006 through December 31, 2006 for the Paramount refinery and for the period from September 28, 2006 through December 31, 2006 for the Long Beach refinery.
 
(2)   Total refinery throughput represents the total of crude oil and blendstock inputs in the refinery production process.
 
(3)   Total refinery production represents the bpd of various finished products produced from processing crude oil and other refinery feedstocks through the crude units and other conversion units at our California refineries.

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(4)   Refinery utilization represents average daily crude oil throughput divided by crude oil capacity during the period in which we have operated the California refineries, excluding planned periods of downtime for maintenance and turnarounds. In December 2006, the Paramount refinery underwent a planned two-week turnaround on its Number 1 crude unit which resulted in a 24,000 bpd decrease in crude oil capacity for a two-week period.
          California Refineries Raw Material Supply
     Since our acquisition of the California refineries, sour crude oil has accounted for approximately 62.3% of our crude oil input of which approximately 34% has been local California sour crude oil. Heavy crude oil has accounted for approximately 37.7% of our crude oil input of which approximately 99.7% has been local California heavy crude oil. As a result of the proximity of the Paramount and Long Beach refineries to the Port of Los Angeles and the Port of Long Beach, we have access to a variety of domestic and foreign crude oils that are available on the West Coast. Our California refineries receive crude oil primarily from common carrier, private carrier and our owned pipelines. Approximately 68% of our California refineries’ crude oil input requirements are purchased through term contracts with several suppliers, including major oil companies. These term contracts are both short-term and long-term in nature with arrangements that contain market-responsive pricing provisions and provisions for renegotiation or cancellation by either party. The remainder of the California refineries’ crude oil input requirements are purchased on the spot market. Other feedstocks, including butane and gasoline blendstocks, are delivered by truck and pipeline.
          Crude Oil Pipelines
     The crude oil pipelines we utilize provide our California refineries access to California, Alaskan North Slope and foreign crude oils and consist of the following:
                 
Crude Oil Pipelines   Status   Miles     Connections
Paramount Crude
  Owned     2.5     Paramount and East Hynes Terminal
Chevron Crude
  Third Party     15     Paramount and local gathering system
No. 3/No. 4
  Owned     13     Long Beach and Long Beach Harbor
BP
  Third Party     1     Long Beach and East Hynes Terminal
     The Paramount refinery is supplied by the Chevron Crude pipeline (medium sour) and Paramount Crude pipeline (heavy sour). The Long Beach refinery is supplied by the No. 3/No. 4 pipelines (medium sour) and the BP pipeline (heavy sour). Additionally, we acquire California medium sour crude oil from the West Hynes terminal, the Plains Dominguez and Long Beach terminals pursuant to throughput arrangements. As a supplement to our on-site storage facilities, the California refineries lease crude oil storage tanks located at the BP-owned East Hynes, the Plains Dominguez, Long Beach and the Kinder Morgan Carson crude oil terminals. We have throughput arrangements from third party pipeline providers to transport crude on one or more pipelines to and from the above facilities. This combination of storage capacity and throughput arrangements allows the California refineries to receive and optimize the crude slate of waterborne domestic and foreign crude oil, along with California crude oil.
          California Refineries Production
     Gasoline. Since our acquisition of the California refineries, CARBOB gasoline, all of which is produced or finished at our Paramount refinery, has accounted for approximately 11.6% of our California refineries’ production. The Paramount refinery utilizes a computerized component blending system to optimize gasoline blending. In addition, our Paramount refinery is capable of producing specially formulated fuels, such as those required in the California, Nevada and Arizona markets.
     Distillates. Since our acquisition of the California refineries, CARB diesel and military jet fuel, all of which is produced or finished at our Paramount refinery, has accounted for approximately 18.9% of our California refineries’ production. All of the diesel fuel we produce is ultra low sulfur CARB diesel, while our military 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. Since our acquisition of the California refineries, asphalt has accounted for approximately 33.3% of our California refineries’ production. Approximately 65.3% of our California refineries’ asphalt production is

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paving grades and 34.7% is roofing asphalt. Asphalt produced at the California refineries is transferred to our asphalt segment at bulk wholesale market prices.
     Light and Heavy Unfinished Feedstocks. We produce LPG, naphtha, unfinished distillates and gas oils used as refinery feedstocks, along with other by-products such as sulfur, all of which is sold to third parties via pipeline and truck on either a contract or spot basis.
          California Refineries Transportation Fuel Marketing
     Our refining and marketing segment sales includes sales of refined products from our California refineries in both the wholesale rack and bulk markets. Our marketing of gasoline and diesel fuels is focused on the Southern California market. We market a portion of the CARB diesel produced at our Paramount refinery through the Paramount refinery rack on an unbranded and delivered basis to wholesale distributors. The remainder of our CARB diesel and our CARBOB gasoline production is sold through the spot market and term contracts to other refiners and to third parties and for delivery by pipeline.
     We market substantially all our jet fuel as JP-8 grade to the DESC. All DESC contracts are for a one-year term and are awarded through a competitive bidding process. Our current contract with the DESC expires in October 2007. JP-8 is delivered to the DESC via our Line 35 pipeline and is then allocated among United States Air Force bases and airports at the DESC’s discretion.
     We sell transportation fuel production in excess of our 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 to the Kinder Morgan Carson terminal by truck.
          California Product Pipelines/Terminal
     The Paramount refinery utilizes our Line 145 eight-mile product pipeline and our two-mile leased Line 166 pipeline to ship products to the Kinder Morgan product terminal in Carson, California. The Kinder Morgan product terminal gives us access to the Kinder Morgan product rack, the Kinder Morgan Pacific pipeline to Phoenix, Arizona, and the Kinder Morgan CalNev pipeline to Las Vegas, Nevada. The Paramount refinery utilizes our Line 35 to ship JP-8 from the refinery to the East Hynes terminal, where our Paramount subsidiary leases a storage tank. DESC then accesses the JP-8 grade jet fuel from the storage tank through a pipeline.
     The following table describes the product pipelines which we utilize:
                 
Product Pipelines   Access   Miles   Connections
Line 145
  Owned and Leased     8     Paramount to a connection with Line 166
Line 166
  Leased     2     Connects to Line 145 to Carson, California (Kinder Morgan)
Line 35
  Owned     4.5     Paramount and East Hynes terminal (BP/DESC)
     The Paramount refinery also utilizes its own terminal at the refinery to distribute product into the local market. This terminal is equipped with a truck loading rack that has permitted volumes of approximately 12,000 bpd of diesel and 13,000 bpd of gasoline.
Asphalt
     Due to the capability of our refineries to process heavy and sour crude oil, we have developed our asphalt business to maximize the value of the increased supply of residual oil remaining after we process gasoline and distillate products from these crude oils. We believe our asphalt production capabilities provides the opportunity to realize higher netbacks than those attainable by producing No. 6 Fuel Oil, which is an alternate product produced from residual oil by refiners lacking asphalt production capabilities. In addition, our asphalt production capabilities permit us to realize value from our residual oil without the significant costs and expenses required to construct and operate coker units.

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     The amount of asphalt produced at our refineries, as a percentage of throughput, varies depending on the configuration of the specific refinery, the crude oils processed at each refinery and the techniques used in the refining process. As part of our efforts to maximize the return generated by the production of asphalt, we have licensed advanced asphalt-blending technology from FINA, with respect to asphalt produced at our Big Spring refinery, and a patented ground tire rubber asphalt manufacturing process from Wright with respect to asphalt produced and sold in California.
     Our asphalt segment markets asphalt produced at our three refineries in the refining and marketing segment and transferred to the asphalt segment at bulk wholesale market prices. The asphalt segment also conducts operations at and markets asphalt produced by our fourth refinery located in Willbridge, Oregon. The Willbridge refinery is an asphalt topping refinery located on 42 acres and has a crude oil throughput capacity of 12,000 bpd. The Willbridge refinery processes primarily heavy crude oil with approximately 70% of its production sold as asphalt products. The Willbridge refinery operates approximately three months per year at times when cargos of heavy crude oil are available for delivery to the refinery. Heavy crude oil is delivered to the Willbridge refinery through our own port facility. Unfinished products produced by the Willbridge refinery include approximately 10% naphtha and approximately 90% gas oils. Asphalt produced at the Willbridge refinery is sold through our terminal at the Willbridge refinery or delivered by truck and railcar to terminals for further processing and resale. Gas oils are sold to local refiners and other third parties and are primarily delivered by barge.
Texas Asphalt Marketing
     Approximately 10% of our Big Spring refinery’s production has historically been asphalt. We can process up to 23 different grades of asphalt base stock, including PMA and GTR asphalts that meet the stringent and varied state highway road paving specifications for use in Texas, New Mexico and Arizona. Based on 2005 data, 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 according to the latest available industry data.
     Paving grade asphalts are predominantly sold from April through October through competitive bids to contractors involved in government projects. These asphalt sales are primarily made at our asphalt terminal at the Big Spring refinery and are delivered to project sites by truck. Our other asphalt blendstocks are sold to roofing companies and asphalt blenders and delivered by rail throughout the United States, including our asphalt blending facilities in Bakersfield and Mojave, California and Phoenix, Arizona.
West Coast Asphalt Marketing
     As a result of our acquisitions of Paramount Petroleum Corporation and Edgington Oil Company, our asphalt business was expanded significantly. Subsequent to these acquisitions, approximately 33.3% of our California refineries’ production has been asphalt and asphalt blendstocks. Our California refineries/terminals produce over 30 different grades of paving and roofing asphalt products. Paving asphalt products include various grades of Performance Graded (PG), Asphalt Cement (AC) and Aged Residue (AR) paving asphalts, cutbacks, emulsions, PMA and GTR. The products meet the California PG specification included in the recently enacted conversion to Federal Highway SHRP PG specifications and our GTR products conform to the specifications of the recently enacted California Assembly Bill 338 which requires usage of GTR asphalt on California road and highways. Roofing asphalt products include oxidized coatings, asphalt fluxes and saturants which are used in the roofing industry to manufacture shingles, roofing roll products and Built-Up Roofing asphalts. Production at the Willbridge refinery has averaged approximately 70% paving and roofing asphalt products. The paving and roofing products produced at our refineries can be sold from the on-site asphalt terminal facilities or it can be distributed through and sold at one of our eight asphalt terminals in the Western United States.
     Sales of paving asphalt are made primarily to paving contractors. Sales to paving contractors can be made either through contracts or they may result from competitive bidding. Sales of roofing asphalts are made primarily to shingle manufacturers or other industrial users through contracts. Sales of asphalt, particularly paving asphalts, are seasonal. Overall, approximately 65% of our West Coast paving asphalt products are sold between April and October.

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     Asphalt produced at our California refineries is marketed through the following owned asphalt terminals:
             
    Asphalt Storage        
Terminals   Capacity (1)   Receipt Capabilities   Delivery Capabilities
California Refineries
  1,800   Pipeline, Rail, Truck   Rail, Truck
Willbridge, OR refinery
  1,032 (2)   Pipeline, Rail, Truck, Marine   Rail, Truck, Marine
Elk Grove, CA
     300   Rail, Truck   Truck
Bakersfield, CA
     100   Rail, Truck   Truck
Mojave, CA
     240   Rail, Truck   Truck
Richmond Beach, WA
  1,060 (2)   Rail, Truck, Marine   Truck, Marine
Fernley, NV (3)
     250   Rail, Truck   Truck
Phoenix, AZ
     160   Rail, Truck   Truck
Flagstaff, AZ
       27   Rail, Truck   Truck
Fredonia, AZ
       60   Truck   Truck
 
(1)   Measured in thousands of barrels.
 
(2)   Storage figures for Willbridge and Richmond Beach include crude oil, fuel oil and other products.
 
(3)   Owned 50%.
     Deliveries of asphalt products to our non-refinery terminals are made primarily through leased railcars that are loaded at the Paramount, Long Beach and Big Spring refineries.
     Asphalt produced at our Willbridge refinery is sold primarily through our terminal located at the refinery but may also be delivered by rail or marine vessel to other terminals.
     Our Paramount subsidiary also owns a 50% interest in Wright, which holds the licensing rights to a patented GTR manufacturing process for paving asphalts. Wright licenses this proprietary technology from Neste/Wright Asphalt Company under a perpetual license that covers all of North America, except California, where Wright maintains an exclusive license. Wright’s operations consist of sublicensing the patented technology to parties to manufacture the GTR asphalt for Wright to sell at various Alon-owned or third party-owned facilities in Texas, Arizona, Oregon and Oklahoma. Wright also purchases and resells various other paving asphalts in these markets. Wright obtains approximately 27% of its asphalt requirements from refineries and terminals in our refining and marketing and asphalt business segments, and the remainder from other refineries. Wright sells GTR and its other asphalt products on either a contract or competitive bidding basis.
Retail
     As of December 31, 2006, we operated 206 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 through 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. We also have a significant presence in Wichita Falls, Texas and Albuquerque, New Mexico.

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Location   Owned   Leased   Total
Big Spring, Texas
    6       1       7  
El Paso, Texas
    13       76       89  
Lubbock, Texas
    17       5       22  
Midland, Texas
    9       9       18  
Odessa, Texas
    10       25       35  
Wichita Falls, Texas
    8       4       12  
Albuquerque, New Mexico
    12       11       23  
 
                       
Total stores
    75       131       206  
 
                       
     On July 3, 2006, we completed the purchase of 40 retail convenience stores from Good Time Stores, Inc. (“Good Time”) in El Paso, Texas. The purchase price for the 40 stores was approximately $27.0 million in cash, including approximately $2.3 million for inventories, and the assumption of certain lease obligations. The acquired stores have been branded 7-Eleven and FINA and our Big Spring refinery supplies these locations with substantially all of their gasoline and diesel needs. This acquisition provided us a leading market share in El Paso and furthered our strategy of strengthening our integrated marketing sector.
     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 ten 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, where we have approximately 52 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 from McLane at cost plus an agreed upon percentage mark-up. Our current contract with McLane expires at the end of December 2009. 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 perpetual license to use the 7-Eleven trademark, service name and trade name in West Texas and a majority of the counties in New Mexico in connection with our convenience store operations. 7-Eleven, Inc. has advised us that we are the largest 7-Eleven licensee in the United States based on the number of stores.
     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 regarding 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 continues to be highly competitive. Many of our principal competitors are integrated, multi-national oil companies (e.g., Valero, Chevron, ExxonMobil, Shell 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

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refining margins. Refining margins are impacted by, among other things, levels of crude oil 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 oil available for their own refineries. However, our Big Spring refinery is in close proximity to Midland, Texas, which is the largest origination terminal for West Texas crude oil, which we believe provides us with transportation cost advantages over many of our competitors in this region. In addition, the Amdel pipeline provides our Big Spring refinery with supply alternatives through access to Gulf Coast and foreign crude oils.
     The majority of our refined fuel products produced at our Big Spring refinery 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 in 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 region 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 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. In August 2006, Longhorn Pipeline Holdings LLC, the owner of the Longhorn pipeline, was acquired by Flying J Inc. Since Flying J’s acquisition, we have reduced shipments to El Paso via the Fin-Tex pipeline system, while increasing our sales through our Big Spring and Abilene terminals. 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-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.
     The majority of the refined fuel products produced at our California refineries is sold on the spot market and is shipped through our pipeline to the Kinder Morgan Carson terminal where it can be distributed to terminals in Arizona, Nevada and Southern California. The balance of our refined fuel products is sold through our Paramount refinery’s truck rack. 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 region 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.
     We compete in the asphalt market with various refineries including Valero, Shell, Tesoro, U.S. Oil, Western, San Joaquin Refining, Ergon and Holly as well as regional and national asphalt marketing companies including SEM Materials, that have no associated refining operations. The principal factors affecting competitiveness in asphalt markets are cost, supply reliability, consistency of product quality, transportation cost and capability to produce the range of high performance products necessary to meet the requirements of customers.
     Our major retail competitors include Valero, Chevron, ConocoPhillips, Town and Country, Allsups and Giant. 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, national grocery and dry goods retailers such as Albertson’s and Wal-Mart, as well as regional grocers and retailers, are entering the motor fuel retailing business. Many of these competitors are substantially larger than we are, and because of their diversity, integration of operations and greater resources, may be better able to withstand volatile market conditions and lower profitability because of competitive pricing and lower operating costs.

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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 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 December 2010 if the small refiner implemented the new diesel sulfur content standard of 15 ppm by June 1, 2006. Prior to the Paramount Petroleum Corporation acquisition, we were certified by the EPA as a small refiner for both gasoline and diesel. In May 2006, we completed upgrades at our Big Spring refinery to satisfy the required diesel and gasoline sulfur content standards under our status at that time as a small refiner. Our expenditures in 2006 to meet the diesel sulfur standards were approximately $12.8 million bringing the total investment to approximately $17.5 million.
     In November 2006, following consummation of the Paramount Petroleum Corporation and Edgington Oil Company acquisitions, we provided notice to the EPA that we no longer satisfied the criteria for a small refiner. We will therefore be required to comply with the 30 ppm gasoline sulfur content standards within 30 months of November 2006, or May 2009. The May 2009 deadline could be extended by the EPA to November 2009 in response to our request for a six-month extension, which we submitted in February 2007. We anticipate that compliance with the new gasoline sulfur standards will require capital expenditures of approximately $15.4 million through 2009, of which approximately $1.0 million is expected to be spent in 2007. Previously, we had budgeted this amount for expenditure through December 2010. Gasoline and diesel produced at our Paramount refinery currently meet the gasoline and diesel low sulfur standards.
     In October 2004, Paramount Petroleum Corporation entered into a Stipulated Order for Abatement (SOA) with the South Coast Air Quality Management District (SCAQMD), the air pollution agency for Orange County and the urban portions of Los Angeles, Riverside and San Bernadino counties. The SOA resolved a number of outstanding issues with the SCAQMD and allowed Paramount Petroleum Corporation to modify crude unit process heater permit descriptions and operate these heaters at firing rates sufficient to meet current and anticipated crude oil throughputs. The SOA required that Paramount Petroleum Corporation install NOx control equipment on specified heaters within a prescribed schedule, including installation of some equipment in 2007 and 2009. We expect that expenditures totaling $4.9 million, with $1.5 million spent in 2007 and $1.7 million spent in each of 2008 and 2009, will be required in order to comply with the SOA.
     On November 4, 2005, the SCAQMD adopted a stringent regulatory requirement, Rule 1118, designed to control emissions from refinery flares. We expect that expenditures required to comply with Rule 1118 will be approximately $3.7 million. The Paramount refinery has one flare which is subject to Rule 1118 and will require the installation of continuous emissions monitoring equipment in 2007 and installation of a vapor recovery system for the flare by 2009. Rule 1118 will not apply to our Long Beach refinery.
     In 2006, the Governor of California signed into law AB 32, the California Global Warming Solutions Act of 2006. Regulations implementing the goals stated in the law, i.e., the reduction of greenhouse gas emission levels to 1990 levels, have yet to be promulgated. Although development of such regulations is still in a very preliminary stage, it is expected that AB 32 mandated reductions will require increased emission controls on both stationary and non-stationary sources and will result in requirements to significantly reduce greenhouse gases from our California refineries and possibly our other California terminals.
     In February 2007, the EPA adopted final rules effective as of April 27, 2007, to reduce the levels of benzene in gasoline on a nationwide basis. More specifically, the rule would require that beginning in 2011 refiners meet an

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annual average gasoline benzene content standard of 0.62% by volume on all gasoline produced, both reformulated and conventional. Gasoline produced at our California refineries already meets the standards being proposed by the EPA. We have not yet determined the capital expenditures that may be necessary to comply with the proposed benzene limits at our Big Spring refinery.
     In October, 2006, we were contacted by Region 6 of the EPA and invited to enter into discussions under the EPA’s Petroleum Refinery Initiative. This Initiative addresses what the EPA deems to be the most significant Clean Air Act compliance concerns affecting the petroleum refining industry. On February 2, 2007, we committed in writing to enter into discussions with the EPA under the Petroleum Refinery Initiative. To date, the EPA has not made any specific claims or findings against us or any of our properties, and we have not determined whether we will ultimately enter into a settlement agreement with the EPA. Based on prior settlements that the EPA has reached with other petroleum refineries under the Petroleum Refinery Initiative, we anticipate that the EPA will seek relief in the form of the payment of civil penalties, the installation of air pollution controls and the implementation of environmentally beneficial projects. At this time, we cannot estimate the amount of any such civil penalties or the nature of any such environmental projects.
     Conditions may develop that cause additional future capital expenditures at our refineries, 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 Texas Commission on Environmental Quality (“TCEQ”). The compliance plan requires us to investigate and, if necessary, remediate 59 potentially contaminated areas on our refinery property. We completed the investigation of these areas during 2006.
     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 $3.5 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 is discussed below.
     We are currently engaged in four separate remediation projects in the Los Angeles area which are being conducted pursuant to Cleanup and Abatement Orders issued by the Los Angeles Regional Water Quality Control Board. Two projects focus on clean up efforts in and around the Paramount refinery and the Lakewood Tank Farm. Our Paramount subsidiary shares the cost of both these remediation projects with ConocoPhillips, the former owner of the Paramount refinery and Lakewood Tank Farm. As part of its acquisition of Line 145, Paramount Petroleum Corporation assumed an active remediation project designed to clean up a leak that occurred on this pipeline prior to Paramount Petroleum Corporation’s ownership. Our Paramount subsidiary bears the full costs of this pipeline remediation effort. We estimate that we will be required to spend approximately $1.1 million during 2007 for these remediation projects.
     We also have a limited ongoing remediation program at our Long Beach refinery. In conjunction with our purchase of the Long Beach refinery in September 2006, we acquired a seven year environmental insurance policy, the premiums for which have been prepaid in full. This policy provides us coverage for both known and unknown conditions existing at the time of our acquisition for off-site, third party bodily injury and property damage claims. The policy limit on a per occurrence and aggregate basis is $15 million and has a per occurrence deductible of $0.5 million.
     On March 1, 2005, Paramount Petroleum Corporation purchased Chevron’s Pacific Northwest Asphalt business. As part of the purchase and sale agreement the parties agreed to share the remediation costs at the Richmond Beach, Washington and Willbridge, Oregon terminals. We estimate that we will be required to spend approximately $1.2 million during 2007 for these remediation costs.
     In addition, we operate 206 owned and leased convenience stores with underground gasoline and diesel fuel storage tanks in West Texas and New Mexico. 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

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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, 2006, the remediation of the properties is on schedule, and we have expended approximately $13.4 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 an initial deductible of $20.0 million during the first ten years after the acquisition (coinciding with the FINA indemnity), which deductible is increased by $1.0 million annually during 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 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 a Contribution Agreement entered into as a part of the HEP transaction.
     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

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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 oil pipelines, 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 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 and located in Texas 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.
     The California State Fire Marshall’s Office enforces federal pipeline regulations for pipelines in the State of California. We are also required to have integrity management and other programs in place, and we anticipate spending approximately $2.0 million over the next five years to comply with these requirements. We are required to have a Pipeline Spill Response Plan for all California pipelines in our system. This requirement includes keeping the plan current, training employees to effect the plan and conducting annual, quarterly and more frequent spill drills. We are also required to maintain Certificates of Financial Responsibility with the State of California, Department of Fish and Game, an the Office of Spill Prevention and Response based on a worst case discharge.
     As required by the Oil Pollution Act of 1990 and state requirements, marine oil transfer operations at the Richmond Beach Terminal are conducted under the facility’s oil spill Facility Response Plan (FRP) approved and on file with the EPA, the U.S. Coast Guard, and the Washington Department of Ecology. The FRP provides guidance to facility personnel for emergency responses to spills. It provides specific information on internal and external agency and contractor notification requirements, appropriate oil spill response actions, the proper disposal of contaminated materials, hazard evaluation and personnel safety, spill response equipment and material lists, and operator and response personnel training. The Richmond Beach Terminal conducts four training drills per year for the purpose of assessing the adequacy of the Facility Response Plan and the effectiveness of personnel training. In addition to the Facility Response Plan, the Richmond Beach Terminal conducts all transfer operations under a Marine Oil Transfer Operations Manual approved and on file with the U.S. Coast Guard and the Washington Department of Ecology.
     The Petroleum Marketing Practices 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 branded distributors in connection with their distribution and sale of motor fuels. The PMPA provides that we may not terminate or fail to renew these 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, 2006, we had approximately 2,029 employees. Approximately 638 employees worked in our refining and marketing segment, of which 558 were employed at our refineries and approximately 80 were

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employed at our corporate and asphalt offices in Dallas, Texas. Approximately 120 of the 170 employees at our Big Spring refinery are covered by collective bargaining agreements that expire on March 31, 2009. Approximately 1,391 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.
Properties
     Our principal properties are described above under the captions “Refining and Marketing,” “Asphalt” and “Retail” 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, 2006, we were the lessee under a number of cancelable and non-cancelable leases for certain properties. Our leases are discussed more fully in Note 20 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, 2007, and their business experience during at least the past five years are set forth below.
             
Name   Age   Position
David Wiessman
    52     Executive Chairman of the Board of Directors
Jeff D. Morris
    55     Director, President and Chief Executive Officer
Claire A. Hart
    51     Senior Vice President
Joseph A. Concienne
    56     Senior Vice President of Refining and Transportation
Alan Moret
    52     Senior Vice President of Asphalt Operations
Shai Even
    38     Vice President, Chief Financial Officer and Treasurer
Jimmy C. Crosby
    47     Vice President of Refining and Supply
Joseph Israel
    35     Vice President of Mergers and Acquisitions
Harlin R. Dean
    40     Vice President, General Counsel and Secretary
Joseph Lipman
    61     President and Chief Executive Officer of SCS
     Set forth below is a brief description of the business experience of each of the 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 managed our operations prior to our initial public offering. 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. 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, Chairman of Blue Square Real Estate Ltd., which is listed on the Tel Aviv Stock Exchange, Acting Chairman of the Board of Directors of Blue Square Investments and Property Chain, Ltd., which is listed on the Tel Aviv Stock Exchange, and Chairman of the Board and President of Dor Alon Energy Israel (1988) Ltd, which is listed on the Tel Aviv Stock Exchange.
     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

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capacities, he was responsible for both the Big Spring refinery and FINA’s Port Arthur refinery and had responsibility for crude oil 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.
     Joseph A. Concienne has served as our Senior Vice President of Refining and Transportation since August 2006 and served as our Vice President of Refining and Transportation from March 2001 to August 2006. His primary role is oversight of our Texas refinery and supply system, and he is the 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 (now known as Valero Refining and Marketing, Inc.) from 1985 to 1998.
     Alan Moret has served as our Senior Vice President of Asphalt Operations since August 2006, with responsibility for asphalt operations and marketing at our refineries and asphalt terminals. Prior to joining Alon, Mr. Moret was President of Paramount Petroleum Corporation from November 2001 to August 2006. Prior to joining Paramount Petroleum Corporation, Mr. Moret held various positions with Atlantic Richfield Company, most recently as President of ARCO Crude Trading, Inc. from 1998 to 2000 and as President of ARCO Seaway Pipeline Company from 1997 to 1998.
     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.
     Jimmy C. Crosby has served as our Vice President of Refining and Supply since August 2006, with responsibility for refinery and supply operations at our California refineries. Mr. Crosby served as our Vice President of Supply and Planning from March 2005 to August 2006, with responsibility for all terminal and refinery supply for our Big Spring refinery’s 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 law, 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.

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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 strong refining margins throughout 2006. 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:
    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 United States;
 
    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, profitability and cash flows.
     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 refineries 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 earnings, profitability and cash flows.

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Our profitability depends, in part, on the sweet/sour crude oil price spread. A decrease in this spread could negatively affect our profitability.
     Because our refineries are configured to process substantial volumes of sour crude oils, our profitability depends, in part, on the price spread between sweet crude oil and sour crude oil, which we refer to as the sweet/sour spread. In recent years, higher demand for sweet crude oils resulted in a wider sweet/sour spread. However, a tightening of the sweet/sour spreads could negatively affect our profitability.
The profitability of our California refineries depends, in part, on the light/heavy crude oil price spread. A decrease in this spread could negatively affect our profitability.
     Our California refineries process significant volumes of heavy crude oils and, as a result, our profitability depends in part on the price spread between light crude oil and heavy crude oil, which we refer to as the light/heavy spread. Because processing light crude oils produces higher percentages of light products, light crude oils typically are priced higher than heavy crude oils. In 2006, the light/heavy spread was tighter than in 2005.
The dangers inherent in our operations could cause disruptions and could expose us to potentially significant losses, costs or liabilities.
     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.
     Any such events at our Big Spring refinery or our California refineries 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.
We are subject to interruptions of supply as a result of our reliance on pipelines for transportation of crude oil and refined products.
     Our refineries receive a substantial percentage of their crude oil and deliver a substantial percentage of their 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, earthquakes, 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, results of operations and cash flows.
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 asphalt 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. The acquisition of the Oregon and California refineries and their related asphalt business is expected to increase the amount of fixed-price supply contracts subject to this risk.
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

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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. This seasonality is more pronounced in our asphalt business, and the acquisition of the Oregon and California refineries and their related asphalt business is expected to increase the effect of seasonal changes on our overall operating results.
If the price of crude oil increases significantly, it could limit our ability to purchase enough crude oil to operate our refineries at full capacity.
     We rely in part on borrowings and letters of credit under our revolving credit facilities to purchase crude oil for our refineries. If the price of crude oil increases significantly, we may not have sufficient capacity under our revolving credit facilities to purchase enough crude oil to operate our refineries at full capacity. A failure to operate our refineries 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 refineries 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 suppliers 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 refineries at full capacity. A failure to operate our refineries at full capacity could adversely affect our profitability and cash flows.
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.
Competition in the asphalt industry is intense, and an increase in competition in the markets in which we sell our asphalt products could adversely affect our earnings and profitability.
     Our asphalt business competes with other refiners and with regional and national asphalt marketing companies. Many of these competitors are larger, more diverse companies with greater resources, providing them advantages in obtaining crude oil and other blendstocks and in competing through bidding process for asphalt supply contracts.
     We compete in large part on our ability to deliver specialized asphalt products which we produce under proprietary technology licenses. Recently, demand for these specialized products has increased due to new specification requirements by state and federal governments. If we were to lose our rights under our technology licenses, or if competing technologies for specialized products are developed by our competitors, our profitability could be adversely affected.
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, national high-volume grocery and dry-goods retailers, such as Albertson’s and Wal-Mart 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

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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 business, results of operations and cash flows.
     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 regulations lowering the permitted level of sulfur in gasoline will require us to spend approximately $15.4 million through 2009. Actual costs could, however, significantly exceed current estimates. As a result of no longer being classified as a small refiner, we will be required to incur such costs earlier than we had initially anticipated. 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.
     On February 2, 2007, we committed in writing to enter into discussions with the EPA under the Petroleum Refinery Initiative. To date, the EPA has not made any specific claims or findings against us or any of our properties and we have not determined whether we will ultimately enter into a settlement agreement with the EPA. Based on prior settlements that the EPA has reached with other petroleum refiners under the Petroleum Refinery Initiative, we anticipate that the EPA will seek relief in the form of the payment of civil penalties, the installation of air pollution controls and the implementation of environmentally beneficial projects. At this time, we cannot estimate the amount of any such civil penalties or the nature of any such environmental projects.
     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 results of operations 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 Big Spring refinery, terminals and convenience stores. Since August 2000, we have spent approximately $13.4 million with respect to the investigation and remediation of our Big Spring refinery and related terminals. We anticipate spending an additional $3.5 million in investigation and remediation expenses in connection with our Big Spring refinery and terminals over the next four years. Since their acquisition, we have spent approximately $0.75 million with respect to the investigation and remediation of our California refineries and related terminals. We anticipate spending an additional $10 to 15 million in investigation and remediation expenses in connection with our California refineries and terminals over the next five years. There can be no assurances, however, that we will not have to spend more than these anticipated amounts. 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

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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 business, results of operations and cash flows.
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 business, results of operations and cash flows.
We could encounter significant opposition to our refining operations at our Paramount refinery.
     Our Paramount refinery is located in a highly-residential area. The refinery is located near schools, apartment complexes, private homes and shopping establishments. Any loss of community support for our refining operations could result in higher than expected expenses in connection with opposing any community action to restrict or terminate the operation of the refinery. Any community action in opposition to our current and planned use of the Paramount refinery could have a material adverse effect on our business, results of operations and cash flows.
Certain of our facilities are located in areas that have a history of earthquakes, the occurrence of which could materially impact our operations.
     Our refineries located in California and the related pipeline and asphalt terminals, and to a lesser extent our refinery and operations in Oregon, are located in areas with a history of earthquakes, some of which have been quite severe. In the event of an earthquake that causes damage to our refining, pipeline or asphalt terminal assets, or the infrastructure necessary for the operation of these assets, such as the availability of usable roads, electricity, water, or natural gas, we may experience a significant interruption in our refining and/or marketing operations. Such an interruption could have a material adverse effect on our business, results of operations and cash flows.
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 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.
The occurrence of a release of hazardous materials or a catastrophic event affecting our Paramount refinery could endanger persons living nearby.
     Because our Paramount refinery is located in a highly-residential area, any release of hazardous material or catastrophic event could cause injuries to persons outside the confines of the Paramount refinery. In the event that non-employees were injured as a result of such an event, we would be likely to incur substantial legal costs as well as any costs resulting from settlements or adjudication of claims from such injured persons. The extent of these

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expenses and costs could be in excess of the limits provided by our insurance policies. As a result, any such event could have a material adverse effect on our business, results of operations and cash flows.
Covenants in our debt instruments could limit our ability to undertake certain types of transactions and adversely affect our liquidity.
     Our credit agreements contain negative and financial covenants and events of default that may limit our financial flexibility and ability to undertake certain types of transactions. For example, we are subject to negative covenants that restrict our activities, including changes in control of Alon or certain of our subsidiaries, restrictions on creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, entering into certain lease obligations, making certain capital expenditures, and making certain dividend, debt and other restricted payments. Should we desire to undertake a transaction that is limited by the negative covenants in our credit agreements, we will need to obtain the consent of our lenders or refinance our credit facilities. Such refinancings may not be possible or may not be available on commercially acceptable terms, or at all.
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 affected.
     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 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, 2006, we employed approximately 170 people at our Big Spring refinery, approximately 120 of whom were covered by a collective bargaining agreement. The collective bargaining agreement expires

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March 31, 2009. 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.
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

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March 1, 2007, 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.”
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 2006.

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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:
                 
Quarterly Period   High   Low
2006
               
Fourth Quarter
  $ 31.85     $ 26.28  
Third Quarter
    42.97       25.10  
Second Quarter
    36.20       24.05  
First Quarter
    25.65       18.83  
2005
               
Fourth Quarter
    25.05       18.05  
Third Quarter
    26.50       17.05  
Holders
     As of December 31, 2006, there were approximately 28 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 did not pay dividends on our common stock in 2005.
     On March 21, 2006, we paid a regular quarterly cash dividend of $0.04 per share and a special cash dividend of $0.37 per share of our common stock. In connection with our cash dividend payment to stockholders, the minority interest owners of Alon Assets and Alon Operating received an aggregate cash dividend of approximately $1.1 million.
     On June 14, 2006, we paid a regular quarterly cash dividend of $0.04 per share of our common stock. In connection with our cash dividend payment to stockholders, the minority interest owners of Alon Assets and Alon Operating received an aggregate cash dividend of approximately $0.1 million.
     On September 14, 2006, we paid a regular quarterly cash dividend of $0.04 per share and a special cash dividend of $2.50 per share of our common stock. In connection with our cash dividend payment to stockholders, the minority interest owners of Alon Assets and Alon Operating received an aggregate cash dividend of approximately $6.7 million.
     On December 14, 2006, we paid a regular quarterly cash dividend of $0.04 per share of our common stock. In connection with our cash dividend payment to stockholders, the minority interest owners of Alon Assets and Alon Operating received an aggregate cash dividend of approximately $0.1 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.

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Recent Sales of Unregistered Securities
     None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
     None.
Stockholder Return Performance Graph
     The following performance graph compares the cumulative total stockholder return on Alon common stock as traded on the NYSE with the Standard & Poor’s 500 Stock Index (the “S&P 500”) and our peer group for the 17-month period from July 28, 2005 (the date on which trading in Alon’s common stock on the NYSE commenced) to December 31, 2006, assuming an initial investment of $100 and the reinvestment of all dividends, if any. The “Peer Group” includes Frontier Oil Corporation, Tesoro Petroleum Corp. and Valero Energy Corporation.
(PERFORMANCE GRAPH)
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 years ended December 31, 2003 and 2002, and the selected consolidated balance sheet data as of December 31, 2004, 2003 and 2002 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, 2006, 2005 and 2004, and the selected consolidated balance sheet data as of December 31, 2006 and 2005, are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
     Our financial statements for the year ended December 31, 2006 include the results of Paramount Petroleum Corporation and its subsidiaries, which we acquired on August 4, 2006 with an effective date of July 31, 2006, and of Edgington Oil Company, which we acquired on September 28, 2006. As a result of these transactions, the financial and operating data for periods prior to the effective date of these transactions may not be comparable to the data for the year ended December 31, 2006.

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     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.
                                         
    Year Ended December 31,  
    2006     2005     2004     2003     2002  
    (dollars in thousands, except per share data)  
STATEMENT OF OPERATIONS DATA:
                                       
Net sales (1)
  $ 3,198,084     $ 2,328,507     $ 1,707,564     $ 1,410,766     $ 1,207,723  
Operating costs and expenses (1)
    2,982,005       2,178,335       1,638,300       1,368,473       1,182,663  
 
                             
Gain on disposition of assets (2)
    63,255       38,591       175              
 
                             
Operating income
    279,334       188,763       69,439       42,293       25,060  
Net income
    157,368       103,988       25,132       14,068       4,352  
 
                                       
Earnings per share (3)
  $ 3.37     $ 2.61     $ .72     $ .40     $ .12  
Cash dividends per common share
    3.03       1.96                    
Weighted average shares outstanding (3)
    46,738       39,889       35,001       35,001       35,001  
 
                                       
CASH FLOW DATA:
                                       
Net cash provided by (used in):
                                       
Operating activities
  $ 142,977     $ 137,895     $ 76,743     $ 76,173     $ 5,001  
Investing activities
    (421,070 )     (106,962 )     (39,886 )     (34,664 )     (70,918 )
Financing activities
    205,439       42,530       19,244       (39,667 )     62,238  
 
                                       
BALANCE SHEET DATA (end of period):
                                       
Cash, cash equivalents and short-term investments
  $ 64,166     $ 322,140     $ 63,357     $ 7,256     $ 5,414  
Working capital
    228,779       275,996       44,443       5,071       30,962  
Total assets
    1,408,785       758,780       472,516       386,982       392,066  
Total debt
    498,669       132,390       187,706       166,816       214,539  
Stockholders’ equity
    290,330       279,493       71,472       46,923       33,128  
 
(1)   Our buy/sell arrangements involve linked purchases and sales related to refined product contracts entered into to address location or grade requirements. As of January 1, 2006, such buy/sell transactions are included on a net basis in sales in the consolidated statements of operations and profits are recognized when the exchanged product is sold. Prior to January 1, 2006, the results of buy/sell transactions were recorded separately in sales and cost of sales in the consolidated statements of operations. 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 2006 reflects the $52.5 million pre-tax gain recognized in connection with the Amdel and White Oil transaction and the recognition of $10.8 million deferred gain recorded in connection with the HEP transaction.
 
(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, 2006 and December 31, 2005.

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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:
    the synergies and accretion to reported earnings estimated to result from our acquisitions of Paramount Petroleum Corporation and Edgington Oil Company may not be realized;
 
    our ability to successfully integrate the operations and employees of Paramount Petroleum Corporation and Edgington Oil Company and the timing of such integration;
 
    expected cost savings from the Paramount Petroleum Corporation and Edgington Oil Company acquisitions may not be fully realized or recognized within the expected time frame, and costs or expenses relating to the acquisitions may be higher than expected;
 
    revenues or margins following the Paramount Petroleum Corporation and Edgington Oil Company acquisitions may be lower than expected;
 
    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;
 
    changes in the light/heavy spread;
 
    the effects of transactions involving forward contracts and derivative instruments;
 
    actions of customers and competitors;

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    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.
Overview
     We are an independent refiner and marketer of petroleum products operating primarily in the South Central, Southwestern and Western regions of the United States. Our business consists of three operating segments: (1) refining and marketing, (2) asphalt and (3) retail.
     Refining and Marketing Segment. Our refining and marketing segment includes three sour and heavy crude oil refineries that are located in Big Spring, Texas, and Paramount and Long Beach, California. These three refineries have a combined throughput capacity of approximately 158,000 bpd. At these refineries we refine crude oil into petroleum products, including gasoline, diesel, jet fuel, petrochemicals, feedstocks and asphalts, which are marketed primarily in the South Central, Southwestern and Western United States.
     We market refined products produced at our Big Spring refinery in West and Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in these regions as our “physically integrated system” because we supply our FINA-branded and unbranded distributors in this region with motor fuels produced at our Big Spring refinery and distributed through a network of pipelines and terminals which we either own or have access to through leases or long-term throughput agreements. Our physically integrated system includes more than 600 of the approximately 1,200 FINA-branded retail sites that we supply, including our retail segment convenience stores. Our marketing operations market motor fuels obtained from third parties to our branded and unbranded distributors in East Texas and Arkansas, which we refer to as our non-integrated system.
     We market refined products produced at our Paramount refinery on an unbranded basis to wholesale distributors, other refiners and third parties primarily on the West Coast. Our Long Beach refinery produces asphalt products. Unfinished fuel products and intermediates produced at our Long Beach refinery are transferred to our Paramount refinery via pipeline for further processing or sold to third parties.
     Asphalt Segment. Our asphalt segment markets asphalt produced at our three refineries included in the refining and marketing segment and at our Willbridge, Oregon refinery. Asphalt produced by the three refineries in our refining and marketing segment is transferred to the asphalt segment at bulk wholesale market prices. Our asphalt segment markets asphalt through 12 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington (Richmond Beach), Nevada (Fernley) and Arizona (Phoenix, Flagstaff and Fredonia). We produce both paving and roofing grades of asphalt, including performance-graded asphalts, emulsions and cutbacks.

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     Retail Segment. Our retail segment operates 206 owned and leased 7-Eleven branded convenience store sites located 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. Our Big Spring refinery supplies the convenience stores in the retail segment with substantially all of their gasoline and diesel needs.
Summary of 2006 Developments
     On January 19, 2006, we made a payment of approximately $103.9 million in satisfaction of our outstanding borrowings under our secured term loan. Of this amount, $100.0 million represented a voluntary prepayment of the 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 March 1, 2006, we sold our Amdel and White Oil crude oil 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 Sunoco, with an option to extend the agreement by four additional thirty-month periods. The Throughput and Deficiency Agreement allows us to maintain crude oil transportation rights on pipelines from the Gulf Coast and from Midland to the Big Spring refinery. Pursuant to the Throughput and Deficiency Agreement, we have agreed to ship a minimum of 15,000 bpd on the pipelines during the term of the agreement. We commenced shipment of crude oil through the Amdel and White Oil pipelines in October 2006.
     On June 14, 2006, we entered into a 15-year arrangement with Centurion to further diversify crude oil delivery sources to our Big Spring refinery. Pursuant to this arrangement, Centurion will provide us with pipeline capacity, and we will ship a minimum of 21,500 bpd of crude oil from Midland, Texas to our Big Spring refinery. Crude oil delivery under this arrangement began in November 2006.
     On July 3, 2006, we completed the purchase of 40 retail convenience stores from Good Time stores in El Paso, Texas. The purchase price for the 40 stores was approximately $27.0 million in cash, including approximately $2.3 million for inventories, and assumption of certain lease obligations.
     In conjunction with the Good Time stores acquisition, we completed a draw down of $50.0 million under a new credit agreement dated June 6, 2006. Of this $50.0 million, $19.8 million was used to finance the acquisition and $30.2 million was used to refinance existing retail segment debt.
     On August 4, 2006, we completed the acquisition of Paramount Petroleum Corporation, a heavy crude oil refining company. Paramount Petroleum Corporation’s assets included refineries located in Paramount, California and Willbridge, Oregon with a combined refining capacity of 66,000 bpd, seven asphalt terminals located in Washington (Richmond Beach), California (Elk Grove and Mojave), Arizona (Phoenix, Fredonia and Flagstaff), and Nevada (Fernley) (50% interest), and a 50% interest in Wright Asphalt Product Company, or Wright, which specializes in patented ground tire rubber modified asphalt products. Total consideration for the acquisition consisted of approximately $504.0 million, including the retirement of all of the Paramount Petroleum Corporation debt at closing of approximately $183.0 million and working capital of approximately $166.0 million.
     On September 28, 2006, we completed the acquisition of Edgington Oil Company, a heavy crude oil refining company located in Long Beach, California. Edgington Oil Company’s assets included a topping refinery with a nameplate capacity of approximately 40,000 bpd. Total consideration for the acquisition consisted of approximately $93.0 million in cash, including approximately $34.0 million for the value of certain inventories at closing.
     The acquisition of Paramount Petroleum Corporation and Edgington Oil Company were funded primarily with $450.0 million of indebtedness under a new term loan credit facility. This facility is secured by substantially all of our assets, other than our retail assets, and matures in August 2013.

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2006 Operations Highlights
     The strong industry fundamentals we experienced throughout 2005 continued during 2006, resulting in net income of $157.4 million, a 51% increase compared to our net income in 2005. Our profitability is substantially determined by the spread between the price of refined products and the price of crude oil, referred to as the “refined product margin.” Refined product margins for 2006, both for gasoline and distillates, were comparable to the strong refined product margins realized in 2005. Heavy industry-wide turnaround activity, the implementation of more restrictive sulfur regulations on gasoline and diesel, increased use of ethanol and decreased use of MTBE in the reformulated gasoline pool, and limited capacity expansions due to the high cost of compliance with environmental regulations resulted in tighter supplies of refined products and strong refined product margins during most of 2006.
     Highlights for 2006 include:
    Our average refinery operating margin for the Big Spring refinery increased by $0.94 per barrel to $13.63 per barrel for the year ended December 31, 2006, compared to 2005.
 
    Refinery production at our Big Spring refinery increased to 64,561 barrels per day (“bpd”) in 2006 compared to 64,393 bpd for 2005.
 
    The average sweet/sour spread for the year ended December 31, 2006 was $5.15 per barrel compared to $4.62 per barrel for the year ended December 31, 2005. The average light/heavy spread for the year ended December 31, 2006 was $14.74 per barrel compared to $15.55 per barrel for the year ended December 31, 2005.
 
    Our capital expenditures and turnaround spending for 2006 totaled approximately $43.8 million, of which $3.9 million was spent on catalysts, $14.2 million was spent on regulatory and compliance projects and $25.7 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 margins to certain industry benchmarks. We compare our Big Spring refinery’s per barrel operating margin to 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. We calculate the refinery per barrel operating margin for our Big Spring refinery by dividing the margin between net sales and cost of sales attributable to our Big Spring refinery, 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 because the refined products we sell in this region are obtained from third-party suppliers and are not produced at our Big Spring refinery.
     We compare our California refineries’ per barrel operating margin to the West Coast 3/2/1 crack spreads. We calculate the West Coast 3/2/1 crack spread using the market values of West Coast LA CARB pipeline gasoline and

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LA #2 CARB pipeline diesel and the market value of WTI crude oil. We calculate our California refineries’ per barrel operating margin by dividing the margin between net sales and cost of sales attributable to our California refineries by our California refineries’ combined throughput volumes.
     Our Big Spring refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. We measure the cost advantage of refining sour crude oil of our Big Spring refinery 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 Big Spring refinery’s operating margin. Our California refineries also benefit from processing significant volumes of sour and heavy crude oils. We calculate the sweet/sour spread for our California refineries based on the difference between the value of WTS crude oil and WTI crude oil. In addition, our California refineries are capable of processing significant volumes of heavy crude oils which historically have cost less than light crude oils. We measure the cost advantage of refining heavy crude oils by calculating the difference between the value of MAYA crude oil less the value of WTI crude oil, which we refer to as the light/heavy spread. A widening of the light/heavy spread can also favorably influence the refinery operating margins for our California refineries.
     The results of operations from our refining and marketing segment are also significantly affected by our refineries’ operating costs, particularly the cost of natural gas used for fuel and the cost of electricity. Natural gas prices have historically been volatile. For example, natural gas prices ranged between $10.63 and $4.20 per million British thermal units, or MMBTU, in 2006. Typically, electricity prices fluctuate with natural gas prices.
     Demand for gasoline products is generally higher during summer months than during winter months due to seasonal increases in highway traffic. 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 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.
     Asphalt. Our earnings from our asphalt segment depend primarily upon the margin between the price at which we sell our asphalt and the bulk wholesale market prices at which asphalt is transferred from our three refineries in the refining and marketing segment. The asphalt segment also conducts operations at and markets asphalt produced by our fourth refinery located in Willbridge, Oregon. A portion of our asphalt sales are made using fixed price contracts for delivery of asphalt products at future dates. Because we price these contracts based on the price of asphalt at the time of the contract, an increase in the cost of crude oil between the time we enter into the contract and the time we produce the asphalt can positively or negatively influence the earnings of our asphalt segment. Demand for paving asphalt products is higher during warmer months than during colder months due to seasonal increases in road construction work. As a result, the operating results for our asphalt segment for the first and fourth calendar quarters are expected to be lower than those for the second and third calendar quarters.
     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 represents the difference between merchandise sales revenues less the delivered cost of merchandise purchases, net of rebates and commissions, expressed as a percentage of merchandise sales revenue. Our retail merchandise sales are driven by convenience, branding and competitive pricing. Motor fuel margin represents the difference between motor fuel revenues and the net cost of purchased fuel, including transportation

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costs and associated motor fuel taxes, expressed 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.
Factors Affecting Comparability
     Our financial condition and operating results over the three year period ended December 31, 2006 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.
Prepayment of Term Loan
     In January 2004, we entered into a $100.0 million term loan scheduled to mature in January 2009. On January 19, 2006, we made a payment of approximately $103.9 million in satisfaction of our outstanding borrowings under this term loan. Of this amount, $100.0 million represented a voluntary prepayment of the 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.
Amdel and White Oil Pipeline Transaction
     On March 1, 2006, we sold our Amdel and White Oil crude oil pipelines to an affiliate of Sunoco, for a total consideration of approximately $68.0 million. The sale of assets in connection with the Amdel and White Oil pipeline transaction on March 1, 2006, reduced property, plant and equipment, net, by approximately $15.2 million. In connection with the Amdel transaction, we recognized a pre-tax gain of $52.5 million in 2006.
Retail Store Acquisition
     On July 3, 2006, we completed the purchase of 40 retail convenience stores from Good Time stores for consideration of approximately $27.0 million in cash, including approximately $2.3 million for inventories and assumption of certain lease obligations. The purchase of the Good Time stores assets increased property, plant and equipment, net, by $5.0 million, intangible assets by $4.0 million and goodwill by $15.3 million. Interest expense increased by an estimated $0.7 million as a result of the incurrence of $19.8 million in additional debt in connection with the acquisition.
Refinery Acquisitions
     On August 4, 2006, we completed the acquisition of Paramount Petroleum Corporation, an independent refiner of petroleum products. Paramount Petroleum Corporation’s assets include refineries, located in Paramount, California and Portland, Oregon with an aggregate refining capacity of 66,000 bpd, seven asphalt terminals located in Richmond Beach, Washington, Elk Grove and Mojave, California, Phoenix, Fredonia and Flagstaff, Arizona, and Fernley, Nevada (50% interest), and a 50% interest in Wright, which specializes in patented tire rubber modified asphalt products. Total consideration for the acquisition consisted of approximately $504.0 million, including the retirement of all of the Paramount Petroleum Corporation debt at closing of approximately $183.0 million and working capital of approximately $166.0 million.
     On September 28, 2006, we completed the acquisition of Edgington Oil Company for consideration of approximately $98.8 million in cash, including approximately $34.0 million for the value of certain inventories at closing. The purchase of Edgington Oil Company increased property, plant and equipment, net, by $63.4 million, current assets by $1.0 million and inventory by $34.4 million.

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Unscheduled Turnaround.
     In September 2005, we completed a reformer catalyst regeneration that had been previously planned for January 2006. As a result of the downtime associated with the regeneration, refinery throughput for the third quarter 2005 was approximately 66,747 bpd compared to 68,023 bpd for the third quarter of 2006.
Hurricane Activity
     The aftermath of Hurricanes Katrina and Rita in September 2005 resulted in the shutdown of approximately 25% of the refining capacity in the United States which greatly influenced the production and supply of both crude oil and refined products throughout the United States. The average crack spread was extremely strong in the third quarter of 2005 as a result of this interruption.
HEP Transaction
     The contribution of assets in connection with the HEP transaction on February 28, 2005 reduced property, plant and equipment, net, by approximately $37.8 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 5 of the consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
Increased Crude Oil Throughput Capacity.
     In the first quarter of 2005, we successfully completed a major turnaround at our Big Spring refinery. In connection with this turnaround, we expanded our crude oil throughput capacity from 62,000 bpd to 70,000 bpd. The resulting increased production and higher sales volumes affects the comparability of operating results after the expansion to periods prior to the expansion. Average refinery production was 64,561 bpd for the year ended December 31, 2006 compared to 64,393 bpd for the year ended December 31, 2005 and 61,372 bpd for the year ended December 31, 2004.
Results of Operations
     Net Sales. Net sales consist primarily of sales of refined petroleum products through our refining and marketing segment, asphalt products through our asphalt segment and sales of merchandise, including food products and motor fuels, through our retail segment.
     For the refining and marketing segment, net sales consist of gross sales, net of customer rebates, discounts and excise taxes. Net sales for our refining and marketing segment include inter-segment sales to our retail and asphalt segments, which are eliminated through consolidation of our financial statements. Asphalt sales consist of gross sales, net of any discounts. Retail net sales consist of gross merchandise sales, less rebates, commissions and discounts, and gross fuel sales, including motor fuel taxes. For our petroleum and asphalt products, net sales are

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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. Asphalt cost of sales includes costs of purchased asphalt, blending materials and 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 sales excludes depreciation and amortization expense.
     Direct Operating Expenses. Direct operating expenses, which relate to our refining and marketing and asphalt segments, include costs associated with the actual operations of our refineries, 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 and asphalt 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 three operating segments for the years ended December 31, 2006, 2005 and 2004. The summary financial data for our three 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,  
    2006     2005     2004  
    (dollars in thousands)  
STATEMENT OF OPERATIONS DATA:
                       
Net sales
  $ 3,198,084     $ 2,328,507     $ 1,707,564  
Operating costs and expenses:
                       
Cost of sales
    2,733,698       1,990,338       1,469,940  
Direct operating expenses
    129,277       93,843       75,742  
Selling, general and administrative expenses (1)
    84,756       73,219       73,554  
Depreciation and amortization (2)
    34,274       20,935       19,064  
 
                 
Total operating costs and expenses
    2,982,005       2,178,335       1,638,300  
 
                 
Gain on disposition of assets (3)
    63,255       38,591       175  
 
                 
Operating income
    279,334       188,763       69,439  
Interest expense (4)
    (30,658 )     (19,326 )     (23,704 )
Equity earnings of investees
    3,161       1,086        
Other income, net
    7,740       4,775       277  
 
                 
Income before income tax expense and minority interest in income of subsidiaries
    259,577       175,298       46,012  
Income tax expense
    93,968       65,518       18,315  
 
                 
Income before minority interest in income of subsidiaries
    165,609       109,780       27,697  
Minority interest in income of subsidiaries
    8,241       5,792       2,565  
 
                 
Net income
  $ 157,368     $ 103,988     $ 25,132  
 
                 
 
                       
Earnings per share (5)
  $ 3.37     $ 2.61     $ .72  
Weighted average shares outstanding (5)
    46,738       39,889       35,001  
Cash dividends per share
  $ 3.03     $ 1.96      
 
                       
CASH FLOW DATA:
                       
Net cash provided by (used in):
                       
Operating activities
  $ 142,977     $ 137,895     $ 76,743  
Investing activities
    (421,070 )     (106,962 )     (39,886 )
Financing activities
    205,439       42,530       19,244  
 
                       
BALANCE SHEET DATA (end of period):
                       
Cash, cash equivalents and short-term investments
  $ 64,166     $ 322,140     $ 63,357  
Working capital
    228,779       275,996       44,443  
Total assets
    1,408,785       758,780       472,516  
Total debt
    498,669       132,390       187,706  
Stockholders’ equity
    290,330       279,493       71,472  
 
                       
OTHER DATA:
                       
Adjusted EBITDA (6)
  $ 261,254     $ 176,968     $ 88,605  
Capital expenditures (7)
    39,832       23,034       27,301  
Capital expenditures for turnarounds and catalysts
    3,940       12,041       2,322  
 
(1)   Includes corporate headquarters selling, general and administrative expenses of $511, $491 and $589 for the years ended December 31, 2006, 2005 and 2004, respectively, which are not allocated to our three operating segments.
 
(2)   Includes corporate depreciation and amortization of $1,613, $1,914 and $1,480 for the years ended December 31, 2006, 2005 and 2004, respectively, which are not allocated to our three operating segments.
 
(3)   Gain on disposition of assets reported in 2006 reflects the $52,500 pre-tax gain recognized in connection with the Amdel and White Oil transaction and the recognition of $10,800 deferred gain recorded in connection with the HEP transaction.

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(4)   Interest expense for the year ended December 31, 2006 includes a $3,000 prepayment premium and $3,894 of unamortized debt issuance costs written off as a result of the prepayment of our $100,000 term loan in January 2006. Additionally, we prepaid $30,200 of retail debt in July 2006. This resulted in $600 in prepayment premiums and the write-off of $2,197 of unamortized debt issuance costs, both of which were recorded to interest expense in 2006.
 
(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, 2006 and December 31, 2005.
 
(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 $188, $470 and $612 for the years ended December 31, 2006, 2005 and 2004, respectively, which are not allocated to our three operating segments.

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REFINING AND MARKETING SEGMENT
                         
    Year Ended December 31,  
    2006     2005     2004  
    (dollars in thousands, except per barrel data and  
    pricing statistics)  
STATEMENT OF OPERATIONS DATA:
                       
Net sales (1) (2)
  $ 2,849,137     $ 2,136,807     $ 1,443,629  
Operating costs and expenses:
                       
Cost of sales (2)
    2,491,457       1,846,739       1,264,462  
Direct operating expenses
    108,673       88,145       75,027  
Selling, general and administrative expenses
    19,192       21,405       22,187  
Depreciation and amortization
    24,961       14,330       13,194  
 
                 
Total operating costs and expenses
    2,644,283       1,970,619       1,374,870  
 
                 
Gain on disposition of assets (3)
    63,251       38,628        
 
                 
Operating income
  $ 268,105     $ 204,816     $ 68,759  
 
                 
 
                       
KEY OPERATING STATISTICS AND OTHER DATA:
                       
Total sales volume (bpd) (11)
    131,662       87,251       85,950  
Non-integrated marketing sales volume (bpd) (4)
    17,995       20,335       19,926  
Non-integrated marketing margin (per barrel sales volume) (4)
  $ (.47 )   $ (1.32 )   $ 0.03  
Per barrel of throughput:
                       
Refinery operating margin – Big Spring (5)
  $ 13.63     $ 12.69     $ 7.95  
Refinery operating margin – CA Refineries (5)(11)
    3.50            
Refinery direct operating expenses – Big Spring (6)
    3.63       3.73       3.33  
Refinery direct operating expenses – CA Refineries (6)(11)
    2.38              
Capital expenditures
  $ 27,740     $ 18,910     $ 23,555  
Capital expenditures for turnarounds and catalysts
    3,940       12,041       2,322  
 
                       
PRICING STATISTICS:
                       
WTI crude oil (per barrel)
  $ 66.06     $ 56.49     $ 41.42  
WTS crude oil (per barrel)
    60.91       51.87       37.45  
MAYA crude oil (per barrel)
    51.26       40.89        
Crack spreads (3/2/1) (per barrel):
                       
Gulf Coast
  $ 12.48     $ 11.45     $ 6.77  
Group III
    14.37       11.44       8.02  
West Coast
    24.30       21.43        
Crude differentials (per barrel):
                       
WTI less WTS
  $ 5.15     $ 4.62     $ 3.97  
WTI less MAYA
    14.74       15.55        
Product price (per gallon):
                       
Gulf Coast unleaded gasoline
    182.9 ¢     158.8 ¢     116.4 ¢
Gulf Coast low-sulfur diesel
    195.1       167.6       111.0  
Group III unleaded gasoline
    186.6       159.4       119.0  
Group III low-sulfur diesel
    201.4       166.5       115.1  
West Coast LA Carbob (unleaded gasoline)
    219.6       188.5        
West Coast LA ultra low-sulfur diesel
    206.0       180.0        
Natural gas (per MMBTU)
  $ 6.98     $ 9.01     $ 6.19  

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    Year Ended December 31,  
    2006     2005     2004  
    Bpd     %     Bpd     %     Bpd     %  
THROUGHPUT AND PRODUCTION DATA:
                                         
Big Spring Refinery
                                               
Refinery throughput:
                                               
Sweet crude
    2,987       4.6       5,072       7.8       4,321       7.0  
Sour crude
    58,529       89.4       55,643       86.0       53,646       87.0  
Blendstocks
    3,897       6.0       4,040       6.2       3,697       6.0  
 
                                   
Total refinery throughput (7)(8)
    65,413       100.0       64,755       100.0       61,664       100.0  
 
                                   
 
                                               
Refinery production:
                                               
Gasoline
    29,671       46.0       29,499       45.8       28,711       46.8  
Diesel/jet
    20,651       32.0       21,903       34.0       19,939       32.5  
Asphalt
    6,147       9.5       5,824       9.1       5,781       9.4  
Petrochemicals
    4,465       6.9       4,256       6.6       4,492       7.3  
Other
    3,627       5.6       2,911       4.5       2,449       4.0  
 
                                   
Total refinery production (9)
    64,561       100.0       64,393       100.0       61,372       100.0  
 
                                   
 
                                               
Refinery utilization (10)
            90.8 %             94.3 %             95.0 %
                 
    Period Ended December 31, 2006  
    Bpd     %  
THROUGHPUT AND PRODUCTION DATA: (11)
               
California refineries
               
Refinery throughput:
               
Sour crude
    37,171       61.9  
Heavy crude
    22,533       37.5  
Blendstocks
    362       .6  
 
           
Total refinery throughput (7)
    60,066       100.0  
 
           
 
               
Refinery production:
               
Gasoline
    6,806       11.6  
Diesel/jet
    11,026       18.9  
Asphalt
    19,500       33.3  
Other
    12,126       20.7  
Light Unfinished
    6,144       10.5  
Heavy Unfinished
    2,938       5.0  
 
           
Total refinery production (9)
    58,540       100.0  
 
           
 
               
Refinery utilization (10)
    83.8 %        
 
(1)   Net sales include inter-segment sales to our asphalt and retail segments at prices which approximate wholesale market price. These inter-segment sales are eliminated through consolidation of our financial statements. Net sales for the year ended 2006 includes $3,300 for the sale of sulfur credits. Following the acquisition of Paramount Petroleum Corporation and Edgington Oil Company, we notified the Environmental Protection Agency that we no longer qualify as a “small refiner” which will limit our ability to generate sulfur credits in the future.
 
(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.
 
(3)   Gain on disposition of assets reported in 2006 reflects the $52,500 pre-tax gain recognized in connection with the Amdel and White Oil transaction and the recognition of $10,800 deferred gain recorded in connection with the HEP transaction.

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(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 for Big Spring is a per barrel measurement calculated by dividing the margin between net sales (exclusive of sale of sulfur credits for $3,300 for the year-ended December 31, 2006) and cost of sales attributable to our refining and marketing segment, exclusive of net sales and cost of sales relating to our non-integrated system, by our Big Spring refinery’s throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margins to these crack spreads to assess our operating performance relative to other participants in our industry. The refinery operating margin for our California refineries is calculated by dividing the margin between the net sales and cost of sales by the throughput volumes at the California refineries. The refinery operating margin for California includes inventory adjustments related to acquisitions of $19,987 to cost of sales.
 
(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)   2006 throughput reflects downtime associated with a turnaround necessary to become compliant with the new ultra low sulfur diesel requirements during the second quarter of 2006. 2005 throughput reflects the effect of the downtime associated with the planned major turnaround in the first quarter of 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.
 
(9)   Total refinery production represents the barrels per day of various finished products produced from processing crude oil and other refinery feedstocks through the crude units and other conversion units at the applicable refinery.
 
(10)   Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.
 
(11)   Represents throughput and production data for the period from August 1, 2006 through December 31, 2006 for our Paramount refinery and for the period from September 28, 2006 through December 31, 2006 for our Long Beach refinery.

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ASPHALT SEGMENT
                         
    Year Ended December 31,  
    2006     2005     2004  
    (dollars in thousands, except per ton data)  
STATEMENT OF OPERATIONS DATA:
                       
Net sales
  $ 389,634     $ 114,910     $ 80,221  
Operating costs and expenses:
                       
Cost of sales (1)
    346,839       124,124       77,964  
Direct operating expenses
    20,604       5,698       715  
Selling, general and administrative expenses
    8,773       1,527       1,492  
Depreciation and amortization
    2,247       134       198  
 
                 
Total operating costs and expenses
    378,463       131,483       80,369  
 
                 
Operating income
  $ 11,171     $ (16,573 )   $ (148 )
 
                 
 
                       
KEY OPERATING STATISTICS AND OTHER DATA:
                       
Number of terminals (end of period)
    12       2       2  
Asphalt sales (in thousands of tons)
    1,153       487       450  
Sales price per ton
  $ 337.93     $ 235.95     $ 178.27  
Asphalt margin per ton (2)
    37.12       (18.92 )     5.01  
Capital expenditures
    3,156       170       258  
 
(1)   Cost of sales includes inter-segment purchases of asphalt from our refining and marketing segment at prices which approximate wholesale market price. These inter-segment purchases are eliminated through consolidation of our financial statements.
 
(2)   Asphalt margin represents the difference between asphalt revenues and the related net cost of purchased asphalt, including transportation costs and discounts.

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RETAIL SEGMENT
                         
    Year Ended December 31,  
    2006     2005     2004  
    (dollars in thousands, except per gallon data)  
STATEMENT OF OPERATIONS DATA:
                       
Net sales
  $ 351,493     $ 326,537     $ 301,491  
Operating costs and expenses:
                       
Cost of sales (1)
    287,582       269,222       245,291  
Selling, general and administrative expenses
    56,280       49,796       49,286  
Depreciation and amortization
    5,453       4,557       4,192  
 
                 
Total operating costs and expenses
    349,315       323,575       298,769  
 
                 
Gain (loss) on disposition of assets
    4       (37 )     175  
 
                 
Operating income
  $ 2,182     $ 2,925     $ 2,897  
 
                 
 
                       
KEY OPERATING STATISTICS AND OTHER DATA:
                       
Number of stores (end of period)
    206       167       167  
Fuel sales (thousands of gallons)
    75,969       87,714       97,541  
Fuel sales (thousands of gallons per site per month) (2)
    34       45       49  
Fuel margin (cpg) (3)
    16.0 ¢     14.9 ¢     12.9 ¢
Fuel sales price (dollar per gallon) (4)
  $ 2.55     $ 2.20     $ 1.76  
Merchandise sales
  $ 157,468     $ 133,305     $ 130,117  
Merchandise sales (per site per month) (2)
    70       68       65  
Merchandise margin (5)
    32.9 %     33.2 %     33.5 %
Capital expenditures
    8,748       3,484       3,134  
 
(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 and merchandise sales per site were adjusted to include 167 stores for six months and 206 stores for six months as a result of the 40 stores purchased on July 3, 2006.
 
(3)   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.
 
(4)   Fuel sales price per gallon represents the average sales price for motor fuels sold through our retail segment.
 
(5)   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.
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
Net Sales
     Consolidated. Net sales for 2006 were $3,198.1 million compared to $2,328.5 million for 2005, an increase of $869.6 million or 37.3%. This increase was primarily due to the acquisition of Paramount Petroleum Corporation and Edgington Oil Company and higher than average refined product prices.
     Refining and Marketing Segment. Net sales for our refining and marketing segment were $2,849.1 million for 2006, compared to $2,136.8 million for 2005, an increase of $712.3 million or 33%. The increase in net sales was primarily due to the acquisition of the California refineries and to significantly higher refined product prices. The increase in refined product prices that we experienced was similar to the price increases experienced in the Gulf

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Coast markets. The average price of Gulf Coast gasoline in 2006 increased 24 cpg, or 15%, to 182.9 cpg, compared to 158.8 cpg in 2005. The average Gulf Coast diesel price in 2006 increased 27 cpg, or 16%, to 195.1 cpg compared to 167.6 cpg in 2005.
     Asphalt Segment. Net sales for our asphalt segment were $389.6 for 2006, compared to $114.9 for 2005, an increase of $274.7 or 239.1%. This increase was due primarily to the acquisition of Paramount Petroleum Corporation’s seven asphalt terminals effective July 31, 2006 and the acquisition of Edgington Oil Company effective September 28, 2006. The average selling price was $337.93 per ton in 2006 compared to $235.95 per ton in 2005.
     Retail Segment. Net sales for our retail segment were $351.5 million for 2006, compared to $326.5 million for 2005, an increase of $25.0 million or 7.7%. This increase was primarily due to a 35 cent, or 16% increase in average fuel sales price from $2.20 in 2005 to $2.55 in 2006, an increase in merchandise sales of $24.2 million or 18.2%, and the acquisition of 40 Good Time stores on July 3, 2006.
Cost of Sales
     Consolidated. Cost of sales was $2,733.7 million for 2006, compared to $1,990.3 million for 2005, an increase of $743.4 million or 37.4%. This increase was primarily due to the acquisition of Paramount Petroleum Corporation and Edgington Oil Company and higher crude oil prices during 2006 as compared to 2005.
     Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $2,491.5 million for 2006, compared to $1,846.7 million for 2005, an increase of $644.8 million or 34.9%. This increase was primarily due to the purchase of the California refineries and the increase in crude oil prices during 2006 as compared to 2005. The average price per barrel of WTS for 2006 increased $9.04 per barrel to $60.91 per barrel, compared to $51.87 per barrel for 2005, an increase of 17.4%.
     Asphalt Segment. Cost of sales for our asphalt segment was $346.8 million for 2006, compared to $124.1 million for 2005, an increase of $222.7 million or 179.5%. This increase was primarily due to the acquisition of Paramount Petroleum Corporation’s seven asphalt terminals effective July 31, 2006 and the acquisition of Edgington Oil Company effective September 28, 2006.
     Retail Segment. Cost of sales for our retail segment was $287.6 million for 2006, compared to $269.2 million for 2005, an increase of $18.4 million or 6.8%. This increase was primarily due to the acquisition of 40 Good Time stores on July 3, 2006.
Direct Operating Expenses
     Consolidated. Direct operating expenses were $129.3 million for 2006, compared to $93.8 million for 2005, an increase of $35.5 million or 37.8%. This increase was primarily attributable to the acquisition of Paramount Petroleum Corporation and Edgington Oil Company.
     Refining and Marketing Segment. Direct operating expenses for our refining and marketing were $108.7 million for 2006, compared to $88.1 million for 2005, an increase of $20.6 million or 23.4%. This increase was primarily attributable to the acquisition of the California refineries.
     Asphalt Segment. Direct operating expenses for our asphalt segment were $20.6 million for 2006, compared to $5.7 million for 2005, an increase of $14.9 million or 261.4%. This increase was primarily due to the acquisition of Paramount Petroleum Corporation’s seven asphalt terminals and the acquisition of Edgington Oil Company.
Selling, General and Administrative Expenses
     Consolidated. SG&A expenses for 2006 were $84.8 million, compared to $73.2 million for 2005, an increase of $11.6 million or 15.8%. This increase is primarily due to higher corporate costs associated with the full year effect of being a public company which significantly increased audit expenditures and added costs associated with

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becoming compliant with the Sarbanes-Oxley Act of 2002. These costs were partially offset by lower selling and advertising expenses. Also contributing to this increase was a $3.0 million employee bonus payment related to special dividend payments on September 14, 2006 and to the purchase of Paramount Petroleum Corporation and Edgington Oil Company.
     Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for 2006 were $19.2 million, compared to $21.4 million for 2005, a decrease of $2.2 million or 10%. This decrease was due to allocating a larger portion of SG&A expenses to the asphalt segment.
     Asphalt Segment. SG&A expenses for our asphalt segment were $8.8 million for 2006, compared to $1.5 million for 2005, an increase of $7.3 million or 486.7%. This increase was primarily due to the acquisition of Paramount Petroleum Corporation’s seven asphalt terminals effective July 31, 2006 and the acquisition of Edgington Oil Company effective September 28, 2006.
     Retail Segment. SG&A expenses for our retail segment for 2006 were $56.3 million, compared to $49.8 million for 2005, an increase of $6.5 million or 13.1%. This increase was primarily attributable to higher maintenance and credit card costs and the acquisition of 40 Good Time stores on July 3, 2006.
Depreciation and Amortization
     Depreciation and amortization for 2006 was $34.3 million, compared to $20.9 million for 2005, an increase of $13.4 million or 64.1%. This increase was primarily attributable to the acquisition of the California refineries and to the completion of capital projects in 2006. Partially offsetting this increase was a reduction in depreciation due to the disposition of assets to HEP and the Amdel and White Oil transactions.
Operating Income
     Consolidated. Operating income for 2006 was $279.3 million, compared to $188.8 million for 2005. Excluding $52.5 million of net gain on disposition of assets resulting from the Amdel and White Oil transaction and $10.8 million amortization of deferred gain relating to the 2005 HEP transaction, which management believes enhances period-to-period comparability, operating income was $216.0 million for 2006, compared to $150.2 million for 2005, an increase of $65.8 million or 43.8%. This increase was primarily attributable to higher operating income in our refining and marketing segment.
     Refining and Marketing Segment. Operating income for our refining and marketing segment was $268.1 million for 2006, compared to $204.8 million for 2005. Excluding gains resulting from the disposition of assets in 2006 ($52.5 million relating to the Amdel and White Oil transaction and $10.8 million relating to the 2005 HEP transaction) and 2005 ($38.6 million relating to the 2005 HEP transaction), operating income for our refining and marketing segment was $204.8 million for 2006, compared to $166.2 for 2005, an increase of $38.6 million or 23.2%. This increase was primarily attributable to the increase in our refinery operating margins. Our operating margin for the Big Spring refinery for 2006 increased $0.94 per barrel to $13.63 per barrel. This increase was attributable, in part, to higher differentials between refined product prices and crude oil prices, which management believes is the result of continued market concern over adequate refinery capacity to meet demand. Also contributing to the higher refinery operating margins at our Big Spring refinery were the supply constraints associated with the logistics of the introduction of new reformulated fuels in 2006. Refining and marketing segment operating income also benefited from an increase in the Gulf Coast 3/2/1 crack spread from an average of $11.45 per barrel in 2005 to $12.48 per barrel in 2006, an increase of 9% and a widening of the sweet/sour spread from $4.62 per barrel in 2005 to $5.15 per barrel for 2006, an increase of 11.5%.
     Asphalt Segment. Operating income for our asphalt segment was $11.2 million for 2006, compared to a loss of $16.6 million for 2005, an increase of $27.8 million. This increase was primarily due to the acquisition of Paramount Petroleum Corporation’s asphalt terminals and the acquisition of Edgington Oil Company.
     Retail Segment. Operating income for our retail segment was $2.2 million for 2006, compared to $2.9 million for 2005, a decrease of $0.7 or 24.1%. This decrease was primarily attributable to higher operating expenses and lower motor fuel volumes.

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Interest Expense
     Interest expense was $30.7 million for 2006, compared to $19.3 million in 2005, an increase of $11.4 million or 59.1%. This increase was primarily attributable to $3.6 million in prepayment premiums and the write-off of $6.1 million of unamortized debt issuance costs resulting from the prepayment of our $100 million term loan in January 2006, and the prepayment of our $30.2 million retail debt in 2006. Interest expense also increased due to our new $450 million term debt related to the acquisitions of the California refineries. Partially offsetting this increase was the reduction of interest expense associated with the term loan and interest from subordinated debt paid off in the third quarter of 2005.
Income Tax Expense
     Income tax expense was $94.0 million for 2006, compared to $65.5 million in 2005, an increase of $28.5 million. The increase in income tax expense was attributable to our increased 2006 taxable income compared to 2005. Our effective tax rate for 2006 was 36.2% compared to 37.4% for 2005, and reflects a $2.0 million benefit in 2006 resulting from tax credits under the 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 of 2004”).
Minority Interest In Income of Subsidiaries
     Minority interest in income of subsidiaries represents the proportional share of net income related to non-voting common stock owned by minority shareholders in two of our subsidiaries, Alon Assets and Alon Operating. Minority interest in income of subsidiaries was $8.2 million for 2006, compared to $5.8 million for 2005, an increase of $2.4 million. This increase was attributable to our increased after-tax income in 2006 as a result of the factors discussed above.
Net Income
     Net income was $157.4 million for 2006, compared to $104.0 million for 2005, an increase of $53.4 million or 51.3%. This increase was attributable to the factors discussed above.
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 at our Big Spring refinery in the first quarter of 2005.
     Refining and Marketing Segment. Net sales for our refining and marketing segment were $2,136.8 million for 2005, compared to $1,443.6 million for 2004, an increase of $693.2 million or 48.0%. 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 at our Big Spring refinery 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

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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.
     Asphalt Segment. Net sales for our asphalt segment were $114.9 million for 2005 compared to $80.2 million for 2004, an increase of $34.7 million or 43.3%. The increase in sales is primarily due to a 32.4% increase in per ton sales price. The average selling price was $235.95 per ton in 2005 compared to $178.27 per ton in 2004.
     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 $1,846.7 million for 2005, compared to $1,264.5 million for 2004, an increase of $582.2 million or 46.0%. 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.
     Asphalt Segment. Cost of sales for our asphalt segment were $124.1 million for 2005, compared to $78.0 million for 2004, an increase of $46.1 million or 59.1%. The increase resulted primarily from a change in the internal valuation method of cost of sales related to inter-segment sales of asphalt products from the Big Spring Refinery to the asphalt segment.
     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
     Consolidated. 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.
     Refining and Marketing Segment. Direct operating expenses for our refining and marketing were $88.1 million for 2005, compared to $75.0 million for 2004, an increase of $13.1 million or 17.5%.
     Asphalt Segment. Direct operating expenses for our asphalt segment was $5.7 million for 2005, compared to $0.7 million for 2004, an increase of $5.0 million. The increase resulted primarily from a change in the allocation of expenses from the Big Spring refinery to the asphalt segment.

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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 $21.4 million, compared to $22.2 million for 2004, a decrease of $0.8 million or 3.6%. This decrease was primarily due to a reduction of bad debt expense and professional fees.
     Asphalt Segment. SG&A expenses for 2005 were $1.5 million, compared to $1.5 million for 2004.
     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 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 $204.8 million. Excluding $38.6 million of gain on disposition of assets resulting from the HEP transaction, operating income for 2005 was $166.2 million, compared to operating income for 2004 of $68.8 million, an increase of $97.4 million or 141.6%. 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 $4.74 per barrel to $12.69 per barrel, compared to $7.95 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%.
     Asphalt Segment. Operating loss for our asphalt segment was $16.6 million for 2005 and $0.1 million for 2004. The decrease in operating income is primarily the result of a change to cost of sales due to in the change in internal valuation method of inter-segment sales of asphalt products from the Big Spring refinery to the asphalt segment.
     Retail Segment. Operating income for our retail segment was $2.9 million for 2005 and $2.8 million (excluding the $0.1 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.

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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.
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 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.
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 facilities. We believe that our cash on hand, cash flows from operating activities, borrowings under our revolving credit facilities 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.
     Depending upon conditions in the capital markets and other factors, we will from time-to-time consider the issuance of debt or equity securities, or other possible capital markets transactions, the proceeds of which could be used to refinance current indebtedness or for other corporate purposes. Pursuant to our growth strategy, we will also consider from time to time acquisitions of, and investments in, assets or businesses that complement our existing assets and businesses. Acquisition transactions, if any, are expected to be financed through cash on hand and from operations, bank borrowings, the issuance of debt or equity securities or a combination of two or more of those sources.

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Cash Flow
     The following table sets forth our consolidated cash flows for the years ended December 31, 2006, 2005 and 2004:
                         
    Year Ended December 31  
    2006     2005     2004  
    (dollars in thousands)  
Cash provided by (used in):
                       
Operating activities
  $ 142,977     $ 137,895     $ 76,743  
Investing activities
    (421,070 )     (106,962 )     (39,886 )
Financing activities
    205,439       42,530       19,244  
 
                 
Net increase (decrease) in cash and cash equivalents
  $ (72,654 )   $ 73,463     $ 56,101  
 
                 
Cash Flows Provided By Operating Activities
     Net cash provided by operating activities for 2006 was $143.0 million, compared to net cash provided by operating activities of $137.9 million for 2005. The $5.1 million net increase in cash provided by operating activities was primarily due to increased net income (excluding after-tax gains on dispositions of assets).
     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 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.
Cash Flows Used In Investing Activities
     Net cash used in investing activities increased to $421.1 million in 2006 from $107.0 million in 2005. This increase in cash used in investing activities is due to the Good Time stores, Paramount Petroleum Corporation and Edgington Oil Company acquisitions in 2006 less the proceeds from the net sale of $185.3 million of short-term investments and the $68.0 million of proceeds from the sale of the Amdel and White Oil crude oil pipelines. Capital expenditures in 2006 totaled $39.8 million and included $14.2 million for regulatory and compliance projects, $16.9 million for refining and terminal improvement projects, and $8.7 million for retail improvements and the re-branding of the 40 Good Time stores purchased in July 2006.
     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.
Cash Flows Provided By Financing Activities
     Net cash provided by financing activities was $205.4 million in 2006, compared to net cash provided by financing activities of $42.5 million in 2005. Cash provided by financing activities in 2006 included net borrowings of $357.5 million incurred substantially for the finance of the Good Time stores, Paramount Petroleum Corporation and Edgington Oil Company acquisitions less cash dividends paid of $149.8 million.
     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

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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 dividends to minority interest stockholders. In addition, cash used in financing activities during 2005 included additional debt reduction of $31.0 million.
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.
     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.
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, 2006, our total cash and cash equivalents were $64.2 million, with no short-term investments, and we had total debt of approximately $498.7 million.
     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, 2006:
                         
    As of December 31, 2006  
    (dollars in thousands)  
    Amount Outstanding     Total Facilities     Total Availability (2)  
Debt, including current portion:
                       
Term loan credit facility
  $ 447,750     $ 447,750     $  
Revolving credit facilities
          540,000  (1)     257,903  
Retail credit facilities
    50,919       50,919        
 
                 
Totals
  $ 498,669     $ 1,038,669     $ 257,903  
 
                 
 
(1)   Total facilities includes the total size of the Paramount Credit Facility that was signed on March 1, 2007 as described below.
 
(2)   Total availability was calculated as the lesser of (a) the total size of the facilities less outstanding borrowings and letters of credit as of December 31, 2006 which was $362.4 million, and (b) total borrowing base less outstanding borrowings and letters of credit as of December 31, 2006 which was $257.9 million.

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Credit Facilities
     Israel Discount Bank Credit Facility. We entered into a revolving credit facility (the “IDB Credit Facility”) on January 14, 2004, which was amended and restated on February 15, 2006 and further amended and restated on June 22, 2006, as amended on August 4, 2006 and February 28, 2007. The Israel Discount Bank of New York, or Israel Discount Bank, acts as administrative agent, co-arranger, collateral agent and lender, and Bank Leumi USA acts as co-arranger and lender under the revolving credit facility. The initial size of the IDB Credit Facility is $160.0 million with options to increase the size of the facility to $240.0 million if crude oil prices increase above certain levels or we increase our throughput capacity. Prior to the February 15, 2006 amendment, the amount available under the previous revolving credit facility was $141.6 million. The IDB Credit Facility is used to finance the working capital needs of the refining and marketing and asphalt segments, exclusive of the working capital needs related to the assets acquired in the acquisition of Paramount Petroleum Corporation and Edgington Oil Company.
     Borrowing availability under the IDB Credit Facility is limited at any time to the lower of the total current size of the credit facility at that time, which is initially $160.0 million, or the amount of the borrowing base under the revolving credit agreement. As of December 31, 2006, the borrowing base under the IDB Credit Facility was $228.0 million. The entire IDB Credit Facility is available in the form of letters of credit and revolving loans. The borrowings under the IDB Credit Facility bear interest at the Eurodollar rate plus 1.50% per annum. The IDB Credit Facility is jointly and severally guaranteed by all of our subsidiaries except for our retail subsidiaries and the subsidiaries of Alon Paramount Holdings, Inc. (“Alon Holdings”) (excluding Alon Pipeline Logistics, LLC (“Alon Logistics”)). The IDB Credit Facility is secured by a first lien on cash, accounts receivables, inventories and related assets and a second lien on our fixed assets, excluding assets of our retail subsidiaries and the subsidiaries of Alon Holdings (excluding Alon Logistics).
     The IDB 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. The IDB 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 IDB Credit Facility contains financial covenants requiring that we 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, 2006 was $233.9 million and our actual consolidated tangible net worth was $264.1 million);
 
    a ratio of total consolidated indebtedness less freely transferable cash and permitted investments not subject to any lien (other than liens in favor of Israel Discount Bank) to consolidated EBITDA for the last four fiscal quarters of no greater than 4.0 to 1.0 (the ratio as of December 31, 2006 was 1.5 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, 2006 was 1.9 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, 2006 was 8.3 to 1.0).
     Compliance with these covenants is determined in the manner specified in the documentation governing the IDB Credit Facility. Consolidated EBITDA under the IDB 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, 2006, we were in compliance with the terms of the agreement.

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     The IDB Credit Facility expires on January 1, 2010. As of December 31, 2006 there were no borrowings outstanding and approximately $102.1 million of letters of credit outstanding under the IDB Credit Facility.
     Bank of America Credit Facility. In conjunction with our acquisition of Paramount Petroleum Corporation, Alon Holdings assumed a Revolving Credit Agreement (“Paramount Initial Credit Facility”) between Paramount Petroleum Corporation and Bank of America N.A. as Agent and a group of financial institutions, secured by the assets of Paramount Petroleum Corporation. Borrowings under the Paramount Initial Credit Facility were limited to up to $215.0 million, consisting of revolving loans and letters of credit. As of December 31, 2006, the borrowing base under the Paramount Initial Credit Facility was $202.1 million. There were no borrowings outstanding under the Paramount Initial Credit Facility at December 31, 2006 and outstanding letters of credit were approximately $75.5 million. As of December 31, 2006, we were in compliance with the terms of the agreement.
     On March 1, 2007, our Paramount subsidiary entered into an amended and restated credit agreement (“Paramount Credit Facility”) with Bank of America N.A. as agent, sole lead arranger and book manager, primarily secured by the assets of Alon Holdings (excluding Alon Logistics). Borrowings under the Paramount Credit Facility are limited to up to $300.0 million, consisting of revolving loans and letters of credit. Amounts borrowed under the Paramount Credit Facility accrue interest at the Eurodollar plus a margin based on excess availability grid. Based on the availability as of December 31, 2006, such interest rate would be 1.25% over the Eurodollar. The Paramount Credit Facility expires on February 28, 2012. Paramount is required to comply with certain restrictive covenants related to working capital and operations under the Paramount Credit Facility. The Paramount Credit Facility is used to finance the working capital needs of Paramount Petroleum Corporation and Edgington Oil Company.
     Credit Suisse Credit Facility. On June 22, 2006, we entered into a Credit Agreement with Credit Suisse (the “Credit Suisse Credit Facility”) with an aggregate available commitment of $450 million. On August 4, 2006, we borrowed $400 million as a term loan upon consummation of the acquisition of Paramount Petroleum Corporation. September 28, 2006, we borrowed an additional $50 million as a term loan to finance the acquisition of Edgington Oil Company. The loans under the Credit Suisse Credit Facility will mature on August 2, 2013. At December 31, 2006, the loan rate was Eurodollar plus 2.25%. Principal payments of 1% per annum are to be paid in quarterly installments beginning September 30, 2006. At December 31, 2006, the outstanding balance was $447.8 million.
     The borrowings under the Credit Suisse Credit Facility bear interest at the range of Eurodollar rate plus 2.50% to the Eurodollar rate plus 1.75% per annum based upon the ratings of the loans by Standard & Poor’s Rating Service and Moody’s Investors Service, Inc. The Credit Suisse Credit Facility is jointly and severally guaranteed by all of our subsidiaries except for our retail subsidiaries. The Credit Suisse Credit Facility is secured by a second lien on our cash, accounts receivable and inventory and a first lien on most of the remaining assets of Alon.
     We may, from time to time, request an additional $100 million of term loans provided that the sum of the incremental loans and the then outstanding loans under the Credit Suisse Credit Facility does not exceed $550 million.
     We may prepay at any time a portion or all of the outstanding loan balance under the Credit Suisse Credit Facility with no prepayment premium.
     The Credit Suisse Credit Facility contains restrictive covenants, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, different businesses, certain lease obligations, and certain restricted payments. This facility does not contain any financial maintenance covenants. As of December 31, 2006, we were in compliance with the terms of the agreement.
     Wachovia Credit Facility. On June 6, 2006, SCS, our wholly-owned subsidiary, entered into a Credit Agreement (the “Wachovia Credit Facility”) by and among SCS, as borrower, and Wachovia Bank. Borrowings under the Wachovia Credit Facility are available in the form of (i) a term loan commitment in an aggregate principal amount of $30.0 million maturing on June 30, 2016, and (ii) a revolving credit commitment (available in the form of revolving loans and letters of credit) in an aggregate principal amount of $20.0 million maturing on June 30, 2009. Revolving loans may be converted by SCS at any time to a term loan maturing on the tenth anniversary of conversion. At the request of SCS, the revolving credit commitment may be increased by an amount not to exceed $10.0 million. The aggregate amount of the lenders’ commitments under the entire Wachovia Credit Facility may not exceed $60.0 million. On July 3, 2006, SCS borrowed $50.0 million of which $30.2 million was used to refinance existing debt and approximately $19.8 million was used to finance the acquisition of Good Time stores.

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At December 31, 2006, the outstanding balances were $29.8 million in the form of a term loan and $20.0 million in the form of a revolving loan.
     Borrowings under the Wachovia Credit Facility bear interest at a Eurodollar rate plus 1.5% per annum. Principal payments of term loan borrowings under this credit facility are being paid in monthly installments based on a 15-year amortization term.
     Obligations under the Wachovia Credit Facility are jointly and severally guaranteed by us, our wholly-owned subsidiaries Alon USA Interests, LLC and all subsidiaries of SCS. The obligations under the Wachovia Credit Facility are secured by a pledge of substantially all of the assets of SCS and its subsidiaries, including cash, accounts receivable and inventory.
     The Wachovia Credit Facility includes a financial covenant that requires SCS to maintain a ratio of total consolidated EBITDA less income tax expense in cash to total consolidated scheduled principal payments of indebtedness plus interest expense, as of the end of each fiscal year, of not less than 1.25 to 1.0. Compliance with this covenant is determined in the manner specified in the documentation governing the credit facility. Consolidated EBITDA under the Wachovia Credit Facility represents net income plus depreciation, amortization, taxes, interest expense and minority interest less gain on disposition of assets.
     The Wachovia Credit Facility contains customary restrictive covenants on the activities of SCS and its subsidiaries, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, different businesses, certain lease obligations, and certain restricted payments. As of December 31, 2006, we were in compliance with the terms of the agreement.
Debt Repayment
     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.
     Mortgage Loans and Equipment Loans. We entered into mortgage and equipment loan agreements with GE Capital Franchise Finance Corporation on October 1, 2002. On July 3, 2006, we made a payment of approximately $30.2 million in satisfaction of our outstanding borrowings under the GE mortgage and equipment loans, including approximately $0.6 million in prepayment premiums.
Capital Spending
     Each year our Board of Directors approve 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 2007 and 2008 are $76.4 million and $76.0 million, respectively. The following table summarizes our expected capital expenditures for 2007 and 2008 by operating segment and major category:

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    2007     2008  
    (dollars in thousands)  
Refining and Marketing Segment:
               
Sustaining maintenance
  $ 14,542     $ 21,844  
Growth/profit improvement/other
    17,250       27,100  
Chemical catalyst and turnaround
    11,144       7,624  
 
           
Total
    42,936       56,568  
 
           
Asphalt Segment:
               
Sustaining maintenance
    2,290       1,900  
Growth/profit improvement
    12,814       7,000  
 
           
Total
    15,104       8,900  
 
           
Retail Segment:
               
Sustaining maintenance
    1,284       1,740  
Growth/profit improvement
    14,520       8,480  
 
           
Total
    15,804       10,220  
 
           
Corporate Segment:
               
Sustaining
    2,535       262  
 
           
 
               
Total Capital Expenditures
  $ 76,379     $ 75,950  
 
           
     Clean Air Capital Expenditures. We expect to spend approximately $15.4 million in the aggregate in 2007, 2008 and 2009 to comply with the Federal Clean Air Act regulations requiring a reduction in sulfur content in gasoline. Our regulatory spending for 2006 included $12.8 million of expenditures associated with meeting the diesel sulfur standards bringing the total for the project to $17.5 million.
     Turnaround and Chemical Catalyst Costs. Expenditures for chemical catalyst in 2006 were approximately $3.9 million.
     In 2005 we completed a major turnaround on substantially all of our major processing units at our Big Spring refinery, 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.
     Between our major turnarounds, we also perform periodic scheduled turnaround projects on various units at our Big Spring and California refineries.
                                         
    2007     2008     2009     2010     2011  
    (dollars in thousands)  
Scheduled turnaround costs
  $ 200     $ 1,100     $ 8,750     $ 500     $ 500  
Chemical catalyst costs
    10,944       6,524       9,053       12,595       9,000  
 
                             
Total
  $ 11,144     $ 7,624     $ 17,803     $ 13,095     $ 9,500  
 
                             
Contractual Obligations and Commercial Commitments
     Information regarding our known contractual obligations of the types described below as of December 31, 2006 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
  $ 6,739     $ 39,855     $ 13,076     $ 438,999     $ 498,669  
Operating lease obligations
    24,105       55,661       21,339       55,534       156,639  
Pipelines and Terminals Agreement (1)
    27,549       82,647       55,099       206,671       371,966  
Other commitments (2)
    2,827       8,483       5,654       26,153       43,117  
 
                             
Total obligations
  $ 61,220     $ 186,646     $ 95,168     $ 727,357     $ 1,070,391  
 
                             

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(1)   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, as well as our minimum requirements with Sunoco.
 
(2)   Other commitments include refinery maintenance services costs.
 
    As of December 31, 2006, 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 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, 2006. However, certain expected payments related to our anticipated pension contributions in 2007 and other post-retirement benefits obligations are discussed in Note 13 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.
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 and asphalt for the asphalt 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, asphalts and blendstocks exceeded LIFO costs by $26.9 million at December 31, 2006.
     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

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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 chemical catalyst used in the 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 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 in 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 costs. 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.
     Goodwill and Intangible Assets. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over one to 40 years. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. We use December 31 of each year as our valuation date for annual impairment testing purposes.
New Accounting Standards and Disclosures
     In November 2004, the Financial Accounting Standards Board, or 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

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the production facilities. Statement No. 151 is effective for fiscal years beginning after June 15, 2005 and was adopted on January 1, 2006. The adoption of Statement No. 151 did not have a material effect on our financial position or results of operations.
     In December 2004, the FASB issued Statement No. 123R, Share-Based Payment, which requires expensing of stock options and other share-based compensation payments to employees and supersedes Statement 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 applies to all awards granted, modified, cancelled or repurchased after that date as well as the unvested portion of prior rewards. Because we used the minimum value method of measuring equity share options for pro forma disclosure purposes under Statement No. 123, we apply Statement No. 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006. The adoption of Statement No. 123R did not have a material effect on our financial position or results of operations.
     We previously accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Accordingly, we measured compensation cost for stock options as the excess of the estimated fair value of our common stock over the exercise price, and we recognized compensation cost for stock options over the scheduled vesting period on an accelerated basis. Stock compensation expense is presented as selling, general and administrative expenses in the accompanying consolidated statements of operations. All pre-IPO stock-based awards continue to be accounted for under Opinion 25.
     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 and was adopted on January 1, 2006. The adoption of Statement No. 153 did not have a material effect on our financial position or results of operations.
     In December 2004, the FASB issued Staff Position FAS 109-1, the Jobs Creation Act of 2004, 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 Statement No. 109, Accounting for Income Taxes, as opposed to an adjustment of recorded deferred tax assets and liabilities. We have included the $2.0 million effects of this special deduction for the year-ended December 31, 2006 and $1.1 million effects of this special deduction for the year-ended December 31, 2005 in our calculation of the deferred income tax provision.
     In March 2005, the FASB issued 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 May 2005, the FASB issued 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 is effective for all accounting changes and any error corrections occurring after January 1, 2006. The adoption of Statement No. 154 did not have a material effect on our consolidated financial position or results of operations.
     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

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applied to new buy/sell arrangements entered in reporting periods beginning after March 15, 2006. The impact of this EITF Issue No. 04-13 consensus did not have a material effect on our financial position or results of operations.
     In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 or FIN 48. This interpretation prescribes a “more-likely-than-not” recognition threshold and measurement attribute (the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement with tax authorities) for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provided guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We will adopt the provisions of FIN 48 on January 1, 2007 and do not expect these provisions to have a material effect on our results of operations, financial condition or liquidity.
     In September 2006, the FASB issued Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. Statement No. 158 requires recognition of the funded status of the plans, measured as of the fiscal year end. We adopted the recognition provision prospectively as of December 31, 2006. We previously used the required measurement date. The adoption Statement No. 158 as of December 31, 2006, increased accumulated other comprehensive loss, net of income tax, by approximately $4.6 million.
     SEC Staff Guidance – Quantifying Financial Statement Misstatements. During September 2006, the Staff of the U.S. Securities Exchange Commission issued Staff Bulletin No. 108, which discusses the process of quantifying financial statement misstatements. During the fourth quarter of 2006, we adopted this guidance and it had no material impact on our consolidated financial statements.
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 in income of subsidiaries, income tax expense, interest expense, depreciation and amortization. Adjusted EBITDA represents EBITDA, exclusive of gain on disposition of assets. EBITDA and Adjusted EBITDA are not recognized measurements under GAAP; however, the amounts included in EBITDA and Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of minority interest in income of subsidiaries, income tax expense, interest expense, gain on disposition of assets and the accounting effects of capital expenditures and acquisitions, items which may vary for different companies for reasons unrelated to overall operating performance. EBITDA is the basis for calculating selected financial ratios as required per our debt agreements. See “—Liquidity and Capital Resources – Credit Facilities.” EBITDA and Adjusted EBITDA have limitations as analytical tools, and you should not consider them in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:
 
    EBITDA and Adjusted EBITDA do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
 
    EBITDA and Adjusted EBITDA do not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;
 
    EBITDA and Adjusted EBITDA do not reflect the prior claim that minority stockholders have on the income generated by non-wholly-owned subsidiaries;

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    EBITDA and Adjusted EBITDA do not reflect changes in or cash requirements for our working capital needs; and
 
    Our calculation of EBITDA and Adjusted EBITDA may differ from the EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.
     Because of these limitations, EBITDA and Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only supplementally.
     The following table reconciles net income to EBITDA and Adjusted EBITDA for the years ended December 31, 2006, 2005 and 2004, respectively:
                         
    For the Year Ended December 31,  
    2006     2005     2004  
    (dollars in thousands)  
Net income
  $ 157,368     $ 103,988     $ 25,132  
Minority interest in income of subsidiaries
    8,241       5,792       2,565  
Income tax expense
    93,968       65,518       18,315  
Interest expense
    30,658       19,326       23,704  
Depreciation and amortization
    34,274       20,935       19,064  
 
                 
EBITDA
    324,509       215,559       88,780  
Gain on disposition of assets
    (63,255 )     (38,591 )     (175 )
 
                 
Adjusted EBITDA
  $ 261,254     $ 176,968     $ 88,605  
 
                 
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Quantitative and Qualitative Disclosure About Market Risk
     Changes in commodity prices and purchased fuel prices and interest rate risk 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, refined products, blendstocks and asphalt, 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, 2006, we held approximately 5.3 million barrels of crude oil and product inventories valued under the LIFO valuation method with an average cost of $53.18 per barrel. Market value exceeded carrying value of LIFO costs by $26.9 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced by $5.3 million.
Interest Rate Risk
     As of December 31, 2006, $497.6 million of our outstanding debt was at floating interest rates. Outstanding borrowings under the Credit Suisse Credit Facility and the Wachovia Credit Facility bear interest at Eurodollar plus 2.25% and 1.5% per annum, respectively. An increase of 1% in the Eurodollar rate would result in an increase in our interest expense of approximately $5.0 million per year.

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     In accordance with Statement 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.
     The following table provides information about our derivative commodity instruments as of December 31, 2006:
                                                 
            Wtd Avg                
Description   Contract   Purchase   Wtd Avg   Contract        
of Activity   Volume   Price   Sales Price   Value   Fair Value   Gain (Loss)
                            (in thousands)
Futures-long (Crude)
    150,000       61.69             9,254       9,158       (96 )
Futures-short (Crude)
    (150,000 )           63.51       (9,526 )     (9,158 )     368  
Futures-long (RBOB)
    175,000       70.91             12,408       11,775       (633 )
Futures-short (RBOB)
    (175,000 )           69.03       (12,080 )     (11,775 )     305  
Futures-long (Heating Oil)
    90,000       75.00             6,750       6,040       (710 )
Futures-short (Heating Oil)
    (90,000 )           72.81       (6,553 )     (6,040 )     513  
Forwards-long (refined products)
    10,000       67.44             674       670       (4 )
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
     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.
Disclosure Controls and Procedures
     Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended (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.

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Management’s Report on Internal Control over Financial Reporting
     Our management is responsible for establishing and maintaining adequate “internal control over financial reporting” (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) for Alon. Our management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2006. In managements evaluation, it used the criteria set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management believes that as of December 31, 2006, our internal control over financial reporting was effective based on those criteria.
     We acquired Paramount Petroleum Corporation (Paramount) and Edgington Oil Company (Edgington) during 2006, and management excluded from our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 Paramount and Edgington’s internal control over financial reporting associated with total assets of $879 million and total revenues of $691 million included in the consolidated financial statements of Alon USA Energy, Inc. and subsidiaries as of and for the year ended December 31, 2006.
     Our independent registered public accounting firm has issued an attestation report on management’s assessment of our internal control over financial reporting, which begins on page F-3 of this report.
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, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Certifications
     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 Exchange Act. This section includes the information concerning the controls and controls evaluation referred to in the certifications.
     Additionally, our Chief Executive Officer certified to the New York Stock Exchange (“NYSE”) that he was not aware of any violation by us of the NYSE corporate governance listing standards.
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 8, 2007 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 Items 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” 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 is 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).

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Exhibit No.   Description of Exhibit
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).
 
   
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).

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Exhibit No.   Description of Exhibit
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, 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 10.20 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, 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 10.20.1 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.23
  Amended 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
  Amended Revolving Credit Agreement, dated as of June 22, 2006, among Alon USA, LP, EOC Acquisition, LLC, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.2 to Form 8-K filed by the Company on June 26, 2006, SEC File No. 001-32567).
 
   
10.25
  First Amendment to Amended Revolving Credit Agreement, dated as of August 4, 2006, to the Amended Revolving Credit Agreement, dated as of June 22, 2006, among Alon USA, LP, EOC Acquisition, LLC, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein.
 
   
10.26
  Waiver, Consent, Partial Release and Second Amendment, dated as of February 28, 2007, to the Amended Revolving Credit Agreement, dated as of June 22, 2006, Alon USA, LP, Edgington Oil Company, LLC, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.2 to Form 8-K filed by the Company on March 5, 2007, SEC File No. 001-32567).
 
   
10.27
  Credit Agreement, dated as of June 6, 2006, among Southwest Convenience Stores, LLC, the lenders party thereto and Wachovia Bank, National Association (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on June 7, 2006, SEC File No. 001-32567).
 
   
10.28
  Credit Agreement, dated as of June 22, 2006, among Alon USA Energy, Inc., the lenders party thereto and Credit Suisse (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on June 26, 2006, SEC File No. 001-32567).

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Exhibit No.   Description of Exhibit
 
   
10.29
  Amended and Restated Credit Agreement, dated as of July 26, 2005, among Paramount Petroleum Corporation, Bank of America, N.A. and Société Générale (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on August 9, 2006, SEC File No. 001-32567).
 
   
10.30
  First Amendment to Amended and Restated Credit Agreement, dated as of January 26, 2006, among Paramount Petroleum Corporation, Bank of America, N.A. and the lenders party thereto (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on August 9, 2006, SEC File No. 001-32567).
 
   
10.31
  Second Amendment to Amended and Restated Credit Agreement, dated as of February 28, 2006, among Paramount Petroleum Corporation, Bank of America, N.A. and the lenders party thereto (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on August 9, 2006, SEC File No. 001-32567).
 
   
10.32
  Third Amendment to Amended and Restated Credit Agreement, dated as of June 12, 2006, among Paramount Petroleum Corporation, Bank of America, N.A. and the lenders party thereto (incorporated by reference to Exhibit 10.4 to Form 8-K, filed by the Company on August 9, 2006, SEC File No. 001-32567).
 
   
10.33
  Fourth Amendment to Amended and Restated Credit Agreement, dated as of June 16, 2006, among Paramount Petroleum Corporation, Bank of America, N.A. and the lenders party thereto (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on August 9, 2006, SEC File No. 001-32567).
 
   
10.34
  Fifth Amendment to Amended and Restated Credit Agreement, dated as of June 22, 2006, among Paramount Petroleum Corporation, Bank of America, N.A., Banc of America Securities LLC and the lenders party thereto (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on August 9, 2006, SEC File No. 001-32567).
 
   
10.35
  Sixth Amendment to Amended and Restated Credit Agreement, dated as of December 21, 2006, among Paramount Petroleum Corporation, Bank of America, N.A. and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on December 22, 2006, SEC File No. 001-32567).
 
   
10.36
  Second Amended and Restated Credit Agreement, dated as of February 28, 2007, among Paramount Petroleum Corporation, Bank of America, N.A. and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on March 5, 2007, SEC File No. 001-32567).
 
   
10.37
  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 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
10.38
  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).
 
   
10.39
  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).
 
   
10.40*
  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).
 
   
10.41*
  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).
 
   
10.42*
  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).
 
   
10.43*
  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).
 
   
10.44*
  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).
 
   
10.45*
  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).
 
   
10.46*
  Amended and Restated Management Employment Agreement, dated as of August 9, 2006, between Harlin R. Dean and Alon USA GP, LLC (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on August 9, 2006, SEC File No. 001-32567).
 
   
10.47*
  Management Employment Agreement, dated as of September 1, 2000, between Yosef Israel and Alon USA GP, LLC (incorporated by reference to Exhibit 10.33 to Form 10-K filed by the Company on March 15, 2006, SEC File No. 001-32567).
 
   
10.48*
  Amendment to Executive/Management Employment Agreement, dated as of May 1, 2005 between Yosef Israel and Alon USA GP, LLC (incorporated by reference to Exhibit 10.34 to Form 10-K filed by the Company on March 15, 2006, SEC File No. 001-32567).
 
   
10.49*
  Executive Employment Agreement, dated as of August 1, 2003 between Shai Even and Alon USA GP, LLC.
 
   
10.50*
  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).

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Exhibit No.   Description of Exhibit
10.51*
  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).
 
   
10.52*
  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).
 
   
10.53*
  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).
 
   
10.54*
  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).
 
   
10.55*
  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).
 
   
10.56*
  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).
 
   
10.57
  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).
 
   
10.58
  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).
 
   
10.59*
  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).
 
   
10.60*
  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).
 
   
10.61*
  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).
 
   
10.62
  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).
 
   
10.63*
  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).
 
   
10.64
  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).
 
   
10.65*
  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).

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Exhibit No.   Description of Exhibit
10.66
  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).
 
   
10.67*
  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).
 
   
10.68
  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).
 
   
10.69*
  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).
 
   
10.70
  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).
 
   
10.71*
  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).
 
   
10.72
  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).
 
   
10.73*
  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).
 
   
10.74*
  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).
 
   
10.75*
  Agreement, dated as of July 6, 2005, 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).
 
   
10.76*
  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).
 
   
10.77*
  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).
 
   
10.78*
  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).

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Exhibit No.   Description of Exhibit
10.79
  Purchase and Sale Agreements, dated as of February 13, 2006, between Alon Petroleum Pipe Line, LP and Sunoco Pipelines, LP, (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on February 13, 2006, SEC File No. 001-32567).
 
   
10.80
  Stock Purchase Agreement, dated as of April 28, 2006, among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy, III and Mark R. Milano (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on May 2, 2006, SEC File No. 001-32567).
 
   
10.81
  First Amendment to Stock Purchase Agreement, dated as of June 30, 2006, among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy III and Mark R. Milano (incorporated by reference to Exhibit 10.1 to Form 10-Q filed by the Company on November 14, 2006, SEC File No. 001-32567).
 
   
10.82
  Second Amendment to Stock Purchase Agreement, dated as of July 31, 2006, among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy III and Mark R. Milano (incorporated by reference to Exhibit 10.2 to Form 10-Q filed by the Company on November 14, 2006, SEC File No. 001-32567).
 
   
10.83
  Agreement and Plan of Merger, dated as of April 28, 2006, among Alon USA Energy, Inc., Apex Oil Company, Inc., Edgington Oil Company, and EOC Acquisition, LLC (incorporated by reference to Exhibit 10.2 to Form 8-K filed by the Company on May 2, 2006, SEC File No. 001-32567).
 
   
10.84
  Agreement and Plan of Merger, dated March 2, 2007, by and among Alon USA Energy, Inc., Alon USA Interests, LLC, ALOSKI, LLC, Skinny’s, Inc. and the Davis Shareholders (as defined therein) (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on March 6, 2007, SEC File No. 001-32567).
 
   
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.
 
*   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-4  
    F-5  
    F-6  
    F-7  
    F-9  

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 as of December 31, 2006 and 2005, 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, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
As discussed in note 2 to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Post Retirement Plans, as of December 31, 2006 and Statement of Financial Accounting Standards No. 123(R), Share-Based Payment, on January 1, 2006.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Alon USA Energy Inc.’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 14, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
         
  KPMG LLP
 
 
     
     
     
 
Dallas, Texas
March 14, 2007

F-2


Table of Contents

Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Alon USA Energy, Inc.:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting (Item 9A), that Alon USA Energy, Inc. (the Company) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that Alon USA Energy, Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
The Company acquired Paramount Petroleum Corporation (Paramount) and Edgington Oil Company (Edgington) during 2006, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 Paramount and Edgington’s internal control over financial reporting associated with total assets of $879 million and total revenues of $691 million included in the consolidated financial statements of Alon USA Energy, Inc. and subsidiaries as of and for the year ended December 31, 2006. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Paramount and Edgington.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Alon USA Energy, Inc. and subsidiaries as of December 31, 2006 and 2005, 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, 2006, and our report dated March 14, 2007 expressed an unqualified opinion on those consolidated financial statements.
         
  KPMG LLP
 
 
     
     
     
 
Dallas, Texas
March 14, 2007

F-3


Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands except share data)
                 
    As of December 31,  
    2006     2005  
ASSETS
               
 
               
Current assets:
               
Cash and cash equivalents
  $ 64,166     $ 136,820  
Short-term investments
          185,320  
Accounts and other receivables, net
    126,634       89,529  
Inventories
    311,464       79,181  
Prepaid expenses and other current assets
    12,909       6,264  
 
           
Total current assets
    515,173       497,114  
 
           
Equity method investments
    38,298       22,754  
Property, plant, and equipment, net
    775,836       211,410  
Other assets
    79,478       27,502  
 
           
Total assets
  $ 1,408,785     $ 758,780  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
 
               
Current liabilities:
               
Accounts payable
  $ 202,447     $ 157,076  
Accrued liabilities
    66,808       48,128  
Current portion of deferred gain on disposition of assets
    10,400       11,427  
Current portion of long-term debt
    6,739       4,487  
 
           
Total current liabilities
    286,394       221,118  
 
           
Other non-current liabilities
    65,885       18,345  
Deferred gain on disposition of assets
    42,299       52,433  
Long-term debt
    491,930       127,903  
Deferred income tax liability
    222,415       52,422  
 
           
Total liabilities
    1,108,923       472,221  
 
           
Commitments and contingencies (Note 20)
               
Minority interest in subsidiaries
    9,532       7,066  
 
           
Stockholders’ equity:
               
Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding
           
Common stock, par value $0.01, 100,000,000 shares authorized; 46,806,443 and 46,809,857 shares issued and outstanding at December 31, 2006 and 2005, respectively
    468       468  
Additional paid-in capital
    181,622       181,108  
Accumulated other comprehensive loss, net of income tax
    (7,816 )     (2,596 )
Retained earnings
    116,056       100,513  
 
           
Total stockholders’ equity
    290,330       279,493  
 
           
Total liabilities and stockholders’ equity
  $ 1,408,785     $ 758,780  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

F-4


Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands except per share data)
                         
    Year Ended December 31,  
    2006     2005     2004  
Net sales
  $ 3,198,084     $ 2,328,507     $ 1,707,564  
Operating costs and expenses:
                       
Cost of sales
    2,733,698       1,990,338       1,469,940  
Direct operating expenses
    129,277       93,843       75,742  
Selling, general and administrative expenses
    84,756       73,219       73,554  
Depreciation and amortization
    34,274       20,935       19,064  
 
                 
Total operating costs and expenses
    2,982,005       2,178,335       1,638,300  
 
                 
Gain on disposition of assets
    63,255       38,591       175  
 
                 
Operating income
    279,334       188,763       69,439  
Interest expense
    (30,658 )     (19,326 )     (23,704 )
Equity earnings of investees
    3,161       1,086        
Other income, net
    7,740       4,775       277  
 
                 
Income before income tax expense and minority interest in income of subsidiaries
    259,577       175,298       46,012  
Income tax expense
    93,968       65,518       18,315  
 
                 
Income before minority interest in income of subsidiaries
    165,609       109,780       27,697  
Minority interest in income of subsidiaries
    8,241       5,792       2,565  
 
                 
Net income
  $ 157,368     $ 103,988     $ 25,132  
 
                 
Earnings per share
  $ 3.37     $ 2.61     $ .72  
 
                 
Weighted average shares outstanding
    46,738       39,889       35,001  
 
                 
Cash dividends per share
  $ 3.03     $ 1.96     $  
 
                 
The accompanying notes are an integral part of these financial consolidated 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, 2004
  $ 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  
Stock compensation expense
          514                   514  
Dividends
                      (141,825 )     (141,825 )
Net income
                      157,368       157,368  
Other comprehensive loss:
                                       
Minimum pension liability, net of income tax
                (558 )           (558 )
 
                                     
Total comprehensive income
                                    156,810  
 
                                     
Adjustment to initially apply FASB Statement No. 158, net of tax
                (4,662 )           (4,662 )
                                     
Balance at December 31, 2006
  $ 468     $ 181,622     $ (7,816 )   $ 116,056     $ 290,330  
 
                             
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,  
    2006     2005     2004  
Cash flows from operating activities:
                       
Net income
  $ 157,368     $ 103,988     $ 25,132  
Adjustments to reconcile net income to cash provided by operating activities:
                       
Depreciation and amortization
    34,274       20,935       19,064  
Stock option compensation
    2,445       2,336       530  
Deferred income tax expense
    8,264       16,646       1,669  
Minority interest in income of subsidiaries
    8,241       5,792       2,565  
Equity earnings of investees (net of dividends)
    (739 )            
Accrued interest on subordinated notes to stockholders
                3,815  
Gain on disposition of assets
    (63,255 )     (38,591 )     (175 )
Changes in operating assets and liabilities, net of acquisition effects:
                       
Accounts and other receivables, net
    68,900       (20,201 )     (9,514 )
Inventories
    (20,490 )     148       (4,256 )
Prepaid expenses and other current assets
    9,639       (2,107 )     2,575  
Other assets
    26,217       1,279       1,871  
Accounts payable
    (88,664 )     52,895       17,245  
Accrued liabilities
    (13,787 )     (2,718 )     17,902  
Other non-current liabilities
    14,564       (2,507 )     (1,680 )
 
                 
Net cash provided by operating activities
    142,977       137,895       76,743  
 
                 
Cash flows from investing activities:
                       
Capital expenditures
    (39,832 )     (23,034 )     (27,301 )
Capital expenditures for turnarounds and catalysts
    (3,940 )     (12,041 )     (2,322 )
Proceeds from disposition of assets
    68,009       118,000       317  
Sale (purchase) of short-term investments, net
    185,320       (185,320 )      
Acquisition of minority interest in subsidiary
                (10,000 )
Acquisition of assets from Good Time stores
    (27,024 )            
Acquisition of Paramount Petroleum Corporation stock
    (504,655 )            
Acquisition of assets from Edgington Oil Company
    (98,762 )            
Acquisition of asphalt business
                (580 )
Dividends from investment in HEP (net of equity earnings in HEP)
          531        
Minority interest shares purchased
    (186 )     (5,098 )      
 
                 
Net cash used in investing activities
    (421,070 )     (106,962 )     (39,886 )
 
                 
Cash flows from financing activities:
                       
Proceeds from sale of common stock, net
          172,459       140  
Dividends paid to minority interest shareholders
    (7,968 )     (6,134 )      
Dividends paid to shareholders
    (141,825 )     (68,479 )      
Deferred debt issuance costs
    (11,047 )           (1,885 )
Revolving credit facilities, net
    19,798             (19,600 )
Additions to long-term debt
    500,000       2,936       100,671  
Payments on long-term debt
    (153,519 )     (58,252 )     (60,082 )
 
                 
Net cash provided by financing activities
    205,439       42,530       19,244  
 
                 
Net (decrease) increase in cash and cash equivalents
    (72,654 )     73,463       56,101  
Cash and cash equivalents, beginning of period
    136,820       63,357       7,256  
 
                 
Cash and cash equivalents, end of period
  $ 64,166     $ 136,820     $ 63,357  
 
                 
The accompanying notes are an integral part of these consolidated financial statements.

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    Year Ended December 31,  
    2006     2005     2004  
Supplemental cash flow information:
                       
Cash paid for interest, net of capitalized interest
  $ 20,301     $ 18,736     $ 20,536  
 
                 
Cash paid for income tax
  $ 83,291     $ 44,523     $ 15,701  
 
                 
Non-cash activities:
                       
Investing activity — receipt of Class B HEP subordinated units as proceeds from disposition of assets
  $     $ 30,000     $  
 
                 
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 South Central, Southwestern and Western regions of the United States. Alon’s business consists of three operating segments: (1) Refining and Marketing, (2) Asphalt and (3) Retail.
     Refining and Marketing Segment. Alon’s refining and marketing segment includes three sour and heavy crude oil refineries that are located in Big Spring, Texas, and Paramount and Long Beach, California. These three refineries have a combined throughput capacity of approximately 158,000 bpd. At these refineries Alon refines crude oil into petroleum products, including gasoline, diesel, jet fuel, petrochemicals, feedstocks, asphalts and other petroleum products, which are marketed primarily in the South Central, Southwestern and Western United States.
     Alon markets transportation fuels produced at its Big Spring refinery in West and Central Texas, Oklahoma, New Mexico and Arizona, which Alon refers to as its “physically integrated system” because it supplies its FINA-branded and unbranded distributors in this region with motor fuels produced at its Big Spring refinery and distributed through a network of pipelines and terminals which are either owned or accessed through leases or long-term throughput agreements. Alon’s physically integrated system includes more than 650 of the approximate 1,200 FINA-branded retail sites that Alon supplies, including its retail segment convenience stores. The refining and marketing segment also markets motor fuels in East Texas and Arkansas, which is referred to as the non-integrated system because Alon supplies branded and unbranded distributors in this region with motor fuels Alon obtained from third parties.
     Alon markets refined products produced at the Paramount refinery on an unbranded basis to wholesale distributors, other refiners and third parties primarily on the West Coast. Alon’s Long Beach refinery produces asphalt products. Unfinished fuel products and intermediates are transferred from our Long Beach refinery to the Paramount refinery via pipeline for further processing or sold to third parties.
     Asphalt Segment. Alon’s asphalt segment markets asphalt produced at its three refineries in the refining and marketing segment and is transferred to the asphalt segment at bulk wholesale market prices. The asphalt segment also conducts operations at and markets asphalt produced by Alon’s fourth refinery located in Willbridge, Oregon. The Willbridge refinery is an asphalt topping refinery and has a crude oil throughput capacity of 12,000 bpd. The Willbridge refinery processes primarily heavy crude oils with approximately 70% of its production sold as asphalt products.
     Alon’s asphalt segment markets asphalt through 12 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington (Richmond Beach), Nevada (Fernley) (50% interest) and Arizona (Phoenix, Flagstaff and Fredonia). Alon produces both paving and roofing grades of asphalt and, depending on the terminal, can manufacture performance-graded asphalts, emulsions and cutbacks.
     Retail Segment. Alon’s retail segment operates 206 owned and leased 7-Eleven branded convenience store sites located 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. Substantially all of the motor fuel sold through Alon’s retail segment is supplied by Alon’s Big Spring refinery.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     (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 17).
     (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
     In September 2005, the Emerging Issues Task Force, (“EITF”) reached a consensus concerning the accounting for linked purchase and sale arrangements in EITF Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. The EITF concluded that non-monetary exchanges of finished goods inventory within the same line of business be recognized at the carrying value of the inventory transferred. Alon began applying this consensus for new buy/sell arrangements beginning January 1, 2006.
     Alon occasionally enters into refined product buy/sell arrangements, which involve linked purchases and sales related to refined product sales contracts entered into to address location, quality or grade requirements. As of January 1, 2006, these buy/sell transactions are included on a net basis in sales in the consolidated statements of operations and profits are recognized when the exchanged product is sold. Prior to the adoption of EITF Issue No. 04-13, the results of these linked refined product buy/sell transactions were recorded separately in sales and cost of sales in the consolidated statements of operations.
     In the ordinary course of business, logistical and refinery production schedules necessitate the occasional sale of crude oil to third parties. The sale of crude oil increased as a result of the addition of the Paramount refinery in 2006. Crude oil sales are included as net sales in the consolidated statements of operations.
     Sulfur credits purchased to meet federal gasoline sulfur regulations are recorded in inventory at the lower of cost or market. Cost is computed on an average cost basis. Purchased sulfur credits are removed from inventory and charged to cost of sales in the consolidated statements of operations as they are utilized. Sales of excess sulfur credits are recognized in earnings and included in net sales in the consolidated statements of operations.
(d) Cost Classifications
     Refining and marketing cost of sales includes crude oil and other raw materials, inclusive of transportation costs. Asphalt cost of sales includes costs of purchased asphalt, blending materials and 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

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
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 consolidated statements of operations.
     Direct operating expenses, which relate to Alon’s refining and marketing and asphalt segments, include costs associated with the actual operations of the refineries, 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 consolidated statements 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 and asphalt segments 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 consisted 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.
     (h) Inventories
     Crude oil, refined products and blendstocks for the refining and marketing segment and asphalt for the asphalt 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 products, asphalt 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.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     (i) Hedging 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 Holly Energy Partners, LP (“HEP”) consists of 937,500 of subordinated class B limited partnership units in HEP and is accounted for under the equity method. These units may be 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, 2006 was $37,153 compared to the carrying value of $22,667.
     (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 and asphalt 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 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 cash flows and fair values are estimates based on management’s judgment and assumptions. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs of disposition.
     (m) Asset Retirement Obligations
     Effective January 1, 2003, Alon adopted Statement No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”), 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 12).

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     In March 2005, the FASB issued 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 sheets. 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 catalyst costs are presented in “depreciation and amortization” in Alon’s consolidated statements 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 uses the grant date fair-value based method for calculating and accounting for stock-based compensation as required in Statement of Financial Accounting Standards No. 123R, Share-Based Payment (“SFAS No. 123R”). As a private company, Alon used the minimum value method for calculating the fair value impact of SFAS No. 123, Accounting for Stock-Based Compensation (SFAS No. 123). Alon applied SFAS No. 123R prospectively to new awards and to awards modified, repurchased or forfeited after January 1, 2006. Alon applied the modified prospective transition method to any unvested stock-based awards issued after its initial public offering (“IPO”). The adoption of SFAS No. 123R did not have a significant effect on Alon’s financial position or results of operations.
     Alon previously accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations (“Opinion 25”). Accordingly, compensation cost for stock options was measured as the excess of the estimated fair value of the common stock over the exercise price and was recognized over the scheduled vesting period on an accelerated basis. All pre-IPO stock-based awards continue to be accounted for using the intrinsic value method under Opinion 25.
     Stock compensation expense is presented as selling, general and administrative expenses in the accompanying consolidated statements of operations (Note 19).
     (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 11). 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, 2006 and 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) Defined Benefit Pension and Other Postretirement Plans
     In September 2006, the FASB issued Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, which amends Statement No. 87, “Employers’ Accounting for Pensions,” Statement No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” Statement No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” and other related accounting literature.
     Statement No. 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or a liability in the statement of financial position and to recognize changes in that funded status through comprehensive income in the year the changes occur. This statement also requires an employer to measure the funded status of a plan as of the date of the employer’s year-end statement of financial position. Alon adopted the funded status recognition and related disclosure requirements of Statement No. 158 as of December 31, 2006, and measured the funded status of our defined benefit plans as of that date.
     The effect of applying Statement No. 158 on individual lines in the consolidated balance sheet as of December 31, 2006 was as follows:
                         
    Before           After
    Application of           Application of
    Statement 158   Adjustments   Statement 158
Liabilities for pension benefits
  $ 1,806     $     $ 1,806  
Long term liabilities for pension benefits
    4,926       7,318       12,244  
Deferred income taxes
    1,897       2,631       4,528  
Accumulated other comprehensive income
    3,154       4,662       7,816  
     (u) Commitments and Contingencies
     Liabilities for loss contingencies, including environmental remediation costs not within the scope of SFAS No. 143 arising from claims, assessments, litigation, fines, and penalties and other sources are recorded when it is

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
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.
     (v) Goodwill and Intangible Assets
     Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over 1 to 40 years. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. Alon uses December 31 of each year as the valuation date for annual impairment testing purposes.
     (w) 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 was 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 applies SFAS No. 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006. The adoption of SFAS No. 123R did not have a material effect on Alon’s financial position or results of operations.
     Alon previously accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations (“Opinion 25”). Accordingly, compensation cost for stock options was measured as the excess of the estimated fair value of the common stock over the exercise price and was recognized over the scheduled vesting period on an accelerated basis. Stock compensation expense is presented as selling, general and administrative expenses in the accompanying consolidated statements of operations. All pre-IPO stock-based awards continue to be accounted for under Opinion 25.
     In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (“FIN No. 48”). This interpretation prescribes a “more-likely-than-not” recognition threshold and measurement attribute (the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement with tax authorities) for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provided guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. Alon will adopt the provisions of FIN No. 48 on January 1, 2007 and does not expect these provisions to have a material effect on Alon’s results of operations, financial condition or liquidity.
     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 was adopted on January 1, 2006. The adoption of Statement No. 151 did not have a material effect on Alon’s financial position or results of operations.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     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 and was adopted on January 1, 2006. The adoption of Statement No. 153 did not have a material effect on Alon’s financial position or results of operations.
     In May 2005, the FASB issued Statement No. 154, Accounting Changes and Error Corrections. Statement No. 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 is effective for all accounting changes and any error corrections occurring after January 1, 2006. The adoption of Statement No. 154 did not have a material effect on Alon’s financial position or results of operations.
     In March 2005, the FASB issued 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 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 $2,049 and $1,111 effects of this special deduction in its calculation of the income tax expense for December 31, 2006 and 2005, respectively.
     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 consolidated statements of operations beginning January 1, 2006. The adoption of EITF Issue No. 04-13 consensus did not have a material effect on Alon’s financial position or results of operations.
     In September 2006, the FASB issued Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. Statement No. 158 requires recognition of the funded status of the plans, measured as of the fiscal year end. Alon adopted the recognition provision prospectively as of December 31, 2006. Alon previously used the required measurement date. The adoption of Statement No. 158 as of December 31, 2006, increased accumulated other comprehensive loss, net of income tax by approximately $4,600.
     SEC Staff Guidance — Quantifying Financial Statement Misstatements. During September 2006, the SEC Staff issued Staff Bulletin No. 108, which discusses the process of quantifying financial statement misstatements. During the fourth quarter of 2006, Alon adopted this guidance and it had no material impact on Alon’s consolidated financial statements.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     (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. 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 14 and 17).
     (4) Acquisitions
     Good Time Stores Acquisition
     On July 3, 2006, Alon completed the purchase of 40 retail stores from Good Time Stores, Inc. (“Good Time”) in El Paso, Texas. The purchase price for the 40 stores acquired was $27,024 in cash, including $2,349 for inventories, and assumption of certain lease obligations. This acquisition gives Alon a leading market share in El Paso and is consistent with Alon’s strategy of strengthening its integrated marketing sector.
     In conjunction with the Good Time Stores, Inc. (“Good Time”) acquisition, Alon, through a wholly-owned subsidiary, completed a draw down of $50,000 under a new credit agreement dated June 6, 2006. Of this $50,000, $19,800 was used to finance the acquisition and $30,200 was used to refinance existing retail segment debt.
     The purchase price has been allocated as set forth below based on estimated fair values of the assets acquired and the goodwill assumed at the date of acquisition.
         
Cash paid
  $ 26,043  
Transaction costs
    981  
 
     
Total Purchase Price
  $ 27,024  
 
     
     The purchase price was allocated as follows:
         
Inventories and other current assets
  $ 2,693  
Property, plant and equipment
    5,014  
Intangible assets
    4,000  
Goodwill
    15,317  
 
     
Total Purchase Price
  $ 27,024  
 
     
     Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired. Alon’s expected discounted future value of cash flows and additional scale were the primary factors contributing to the recognition of goodwill.
     Paramount Acquisition
     On August 4, 2006, Alon completed the purchase of the stock of Paramount Petroleum Corporation, an independent refiner of petroleum products. Paramount Petroleum Corporation’s assets include refineries, located in Paramount, California, and Willbridge, Oregon with a combined refining capacity of 66,000 barrels of heavy crude oil per day and seven asphalt terminals located in Richmond Beach, Washington, Elk Grove and Mojave, California, Phoenix, Fredonia, and Flagstaff, Arizona and Fernley, Nevada (50% interest) and a 50% interest in Wright Asphalt Products

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
Company (“Wright”), which specializes in patented tire rubber modified asphalt products that are provided in six terminals.
     The final purchase price for Paramount Petroleum Corporation is pending settlement of certain post closing adjustments. The purchase price has been preliminarily allocated based on estimated fair values of the assets acquired and the liabilities assumed at the July 31, 2006 effective date of the acquisition and is pending the completion and analysis of an independent appraisal and other evaluations and settlement of certain post closing adjustments.
         
Cash paid, less unrestricted cash acquired
  $ 501,056  
Transaction costs
    3,599  
 
     
Total Purchase Price
  $ 504,655  
 
     
     The purchase price was allocated as follows:
         
Current assets, net of unrestricted cash acquired
  $ 308,135  
Property, plant and equipment
    499,179  
Deferred charges and other assets
    23,503  
Equity method investments
    15,836  
Intangibles
    16,098  
Current liabilities, excluding debt
    (165,824 )
Deferred income tax liability
    (166,535 )
Other liabilities
    (25,737 )
 
     
Total Purchase Price
  $ 504,655  
 
     
     Alon retired all of the Paramount Petroleum Corporation debt at the closing of the acquisition.
     Unaudited Pro Forma Financial Information
     The consolidated statements of operations include the results of the Paramount Petroleum Corporation acquisition commencing on August 1, 2006. The following unaudited pro forma financial information assumes:
    The acquisition of Paramount Petroleum Corporation occurred on January 1, 2005;
 
    $400,000 of term debt was incurred to fund the Paramount Petroleum Corporation acquisition on January 1, 2005 and existing Paramount Petroleum Corporation debt was repaid on this date; and
 
    Depreciation expense was higher beginning January 1, 2005 for the higher estimated asset values as of that date.
     The unaudited pro forma financial information is not necessarily indicative of the results of future operations (in thousands, except per share amounts):
                 
    For the Year Ended  
    December 31,  
    2006     2005  
Net sales
  $ 4,058,334     $ 3,532,215  
Operating income
    288,886       181,966  
Net income
    152,795       82,557  
Earnings per share
  $ 3.27     $ 2.07  

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     Edgington Acquisition
     On September 28, 2006, Alon completed the acquisition of Edgington Oil Company, a heavy crude oil refining company located in Long Beach, California. The acquisition included Edgington Oil Company’s topping refinery with a nameplate capacity of approximately 40,000 bpd of crude oil. Total consideration for the acquisition consisted of $98,762 in cash and assumed liabilities, including $34,405 for the value of certain inventories at closing.
     The purchase price has been preliminarily allocated as set forth below based on estimated fair values of the assets at the date of acquisition, pending the completion of an independent appraisal and other evaluations.
         
Cash paid
  $ 97,599  
Transaction costs
    1,163  
 
     
Total Purchase Price
  $ 98,762  
 
     
 
       
The purchase price was allocated as follows:
       
 
       
Current assets, net of unrestricted cash acquired
  $ 1,000  
Inventories
    34,405  
Property, plant and equipment
    63,357  
 
     
Total Purchase Price
  $ 98,762  
 
     
     The Paramount Petroleum Corporation and Edgington Oil Company acquisitions are consistent with Alon’s general business strategy of increasing cash flows and earnings through the acquisition of assets or businesses that are logical extensions of its existing assets or businesses. The addition of Paramount Petroleum Corporation’s and Edgington Oil Company’s assets has also increased the geographic diversity of Alon’s Refining and Marketing, and Asphalt segment networks by allowing Alon to expand throughout the Southwest region and up the West Coast of the United States. With the addition of the Paramount, Willbridge and Long Beach refineries, Alon believes it has diversified the risks associated with being a single asset refiner. Alon intends to apply its experience of increasing reliability, capacity and yields at its Big Spring refinery to the newly-acquired assets in order to maximize the return on investments. These acquisitions have more than doubled the crude oil processing capacity of Alon from 70,000 barrels per day to approximately 170,000 barrels per day and will allow Alon to process heavy crude oils. The acquisitions provide Alon exposure to West Coast refining margins.
     (5) 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 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.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     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 $826 is recorded in other non-current liabilities in the December 31, 2006 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 $10,400 as a current liability and $42,299 as a long-term liability in the December 31, 2006 consolidated balance sheet.
     On March 1, 2006, Alon sold its Amdel and White Oil crude oil pipelines, which had been inactive since December 2002, to an affiliate of Sunoco, Inc., or Sunoco, for a total consideration of approximately $68.0 million. In conjunction with the sale of the Amdel and White Oil pipelines, Alon 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 allows Alon to maintain crude oil transportation rights on the pipelines from the Gulf Coast and from Midland to the Big Spring refinery. Pursuant to the Throughput and Deficiency Agreement, Alon has agreed to ship a minimum of 15,000 bpd on the pipelines during the term of the agreement. Alon commenced shipments of crude oil through the Amdel and White Oil pipelines under this agreement in October 2006.
     (6) Segment Data
     Alon’s revenues are derived from three operating segments: (i) refining and marketing, (ii) asphalt and (iii) 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
     Alon’s refining and marketing segment includes three sour and heavy crude oil refineries that are located in Big Spring, Texas, and Paramount and Long Beach, California. At these refineries Alon refines crude oil into petroleum products, including gasoline, diesel, jet fuel, petrochemicals, feedstocks, asphalts and other petroleum products, which are marketed primarily in the South Central, Southwestern and Western regions of the United States. 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 1,200 locations.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
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) Asphalt
     Alon’s asphalt segment includes the Willbridge, Oregon refinery and 12 refinery/terminal locations located in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington (Richmond Beach), Nevada (Fernley) (50% interest) and Arizona (Phoenix, Flagstaff and Fredonia) and a 50% interest in Wright which specializes in marketing patented tire rubber modified asphalt products. Alon produces both paving and roofing grades of asphalt and, depending on the terminal, can manufacture performance-graded asphalts, emulsions and cutbacks.
     (c) Retail Segment
     Alon’s retail segment operates 206 owned and leased 7-Eleven branded convenience store sites located 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.
     (d) Corporate
     Operations that are not included in any of the three 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, 2006, 2005 and 2004 is presented below.
                                         
    Refining and                
Year ended December 31, 2006   Marketing   Asphalt   Retail   Corporate   Total
     
Net sales to external customers
  $ 2,456,957     $ 389,634     $ 351,493     $     $ 3,198,084  
Intersegment sales/purchases
    392,180       (245,434 )     (146,746 )            
Depreciation and amortization
    24,961       2,247       5,453       1,613       34,274  
Operating income (loss)
    268,105       11,171       2,182       (2,124 )     279,334  
Total assets
    1,154,958       144,871       98,649       10,307       1,408,785  
Turnaround, chemical catalyst and capital expenditures
    31,680       3,156       8,748       188       43,772  
 
                                       
 
  Refining and                                
Year ended December 31, 2005
  Marketing   Asphalt   Retail   Corporate   Total
     
Net sales to external customers
  $ 1,887,060     $ 114,910     $ 326,537     $     $ 2,328,507  
Intersegment sales/purchases
    249,747       (104,327 )     (145,420 )            
Depreciation and amortization
    14,330       134       4,557       1,914       20,935  
Operating income (loss)
    204,816       (16,573 )     2,925       (2,405 )     188,763  
Total assets
    657,991       18,759       69,794       12,236       758,780  
Turnaround, chemical catalyst and capital expenditures
    30,951       170       3,484       470       35,075  
 
                                       
 
  Refining and                                
Year ended December 31, 2004
  Marketing   Asphalt   Retail   Corporate   Total
     
Net sales to external customers
  $ 1,325,852     $ 80,221     $ 301,491     $     $ 1,707,564  
Intersegment sales/purchases
    193,659       (75,882 )     (117,777 )            
Depreciation and amortization
    13,194       198       4,192       1,480       19,064  
Operating income (loss)
    68,759       (148 )     2,897       (2,069 )     69,439  
Total assets
    373,350       16,480       69,949       12,737       472,516  
Turnaround, chemical catalyst and capital expenditures
    25,619       258       3,134       612       29,623  

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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.
     (7) 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, 2006, Alon held net forward contracts for sales of 10 thousand barrels of refined products at an average price of $67.44 per barrel with a fair value of $670. 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. These contracts were not designated as hedges for accounting purposes. Accordingly, a net unrealized loss of ($4) and unrealized gains of $206 were recorded as an adjustment to net sales in the consolidated statements of operations for the years ended December 31, 2006 and 2005, respectively.
     At December 31, 2006, Alon also held net futures contracts for purchases and sales of 150 thousand barrels of crude oil, 175 thousand barrels of refined products and 90 thousand barrels of heating oil at an average price of $68.16 per barrel with a fair value of $26,973. These futures contracts were not designated as hedges for accounting purposes. Accordingly, the contracts are recorded at their fair values and an unrealized loss of ($252) has been recorded as a cost offset in the consolidated statements of operations for the year ended December 31, 2006.
     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.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     (8) 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 sheets. The balance in the allowance account was $2,006 and $1,145 at December 31, 2006 and 2005, respectively. For the three-year period ended December 31, 2006, no sales to a single customer accounted for more than 10% of Alon’s net sales.
     (9) 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, asphalt 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,  
    2006     2005  
Crude oil, refined products, asphalt and blendstocks
  $ 286,092     $ 57,822  
Materials and supplies
    6,281       5,880  
Store merchandise
    15,905       12,977  
Store fuel
    3,186       2,502  
 
           
Total inventories
  $ 311,464     $ 79,181  
 
           
     Crude oil, refined products, asphalt and blendstock inventories totaled 5,269 barrels and 1,819 barrels as of December 31, 2006 and 2005, respectively.
     Market values of crude oil, refined products, asphalt and blendstock inventories exceeded LIFO costs by $26,924 and $52,198 at December 31, 2006 and 2005, respectively.
     (10) Property, Plant, and Equipment, Net
     Property, plant, and equipment consisted of the following:
                 
    December 31,  
    2006     2005  
Refining facilities
  $ 730,036     $ 171,346  
Pipelines and terminals
    40,108       27,237  
Retail
    78,722       63,486  
Other
    10,700       10,691  
 
           
Property, plant and equipment, gross
    859,566       272,760  
Less accumulated depreciation
    (83,730 )     (61,350 )
 
           
Property, plant and equipment, net
  $ 775,836     $ 211,410  
 
           
     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

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     Alon capitalized interest of $927 and $301 for the years ended December 31, 2005 and 2004, respectively. No interest was capitalized for the year ended December 31, 2006.
     (11) Other Assets
     Other assets consisted of the following:
                 
    December 31,  
    2006     2005  
Deferred turnaround, chemical catalyst cost
  $ 12,797     $ 9,865  
Environmental receivables
    11,853       3,257  
Deferred debt issuance costs
    10,769       6,529  
Goodwill
    15,317        
Intangible assets
    20,696       3,429  
Other
    8,046       4,422  
 
           
Total other assets
  $ 79,478     $ 27,502  
 
           
     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, 2006 and 2005, Alon has recorded a current receivable of $1,750 and $1,750 and a non-current receivable of $2,031 and $3,257 from FINA, respectively, and corresponding accrued environmental liabilities. Alon’s Paramount subsidiary also has indemnification agreements with a prior owner for part of the remediation expenses at its refineries and offsite tank farm, and as a result, has recorded $9,822 as a non-current receivable at December 31, 2006. (See note 20).
     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 $990, $1,883 and $1,329 for the years ended December 31, 2006, 2005 and 2004, respectively.
     (12) Accrued Liabilities
     Alon’s current accrued liabilities and other non-current liabilities at December 31, 2006 and 2005 consisted of the following:
                 
    December 31,  
    2006     2005  
Accrued Liabilities — Current:
               
Taxes other than income taxes, primarily excise taxes
  $ 19,666     $ 21,206  
Income taxes payable
    8,878       7,239  
Employee costs
    4,373       4,977  
Other
    33,891       14,706  
 
           
Total accrued liabilities
  $ 66,808     $ 48,128  
 
           
 
               

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
                 
    December 31,  
    2006     2005  
Accrued Liabilities — Non-Current:
               
Pension and other postemployment benefit liabilities, net (Note 13)
  $ 18,678     $ 10,611  
Environmental accrual (Note 20)
    38,349       2,986  
Asset retirement obligation
    6,216       2,211  
Other
    2,642       2,537  
 
           
Total other non-current liabilities
  $ 65,885     $ 18,345  
 
           
     Alon adopted the Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143), on January 1, 2003. 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 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, 2006 and 2005:
                 
    December 31,  
    2006     2005  
Balance at beginning of year
  $ 2,211     $ 2,524  
Accretion expense
    145       53  
Additional accretion due to change in risk free interest rate
    394        
Retirements
    (124 )     (366 )
Additions
    3,590        
 
           
Balance at end of year
  $ 6,216     $ 2,211  
 
           
Approximately $3,524 relates to the acquisitions in 2006 (see Note 4).
     (13) Employee and Postretirement Benefits
     Alon has three defined benefit pension plans covering substantially all of its refining and marketing segment employees excluding West Coast 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.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     The measurement dates used to determine pension and other postretirement benefit measures for the pension plan and the postretirement benefit plan is December 31, 2006 and 2005. Financial information related to Alon’s pension plans and other postretirement benefits is presented below.
                                 
    Pension Benefits     Postretirement Benefits  
    2006     2005     2006     2005  
Change in projected benefit obligation:
                               
Benefit obligation at beginning of year
  $ 39,100     $ 31,772     $ 1,755     $ 1,852  
Service cost
    1,867       1,694       74       75  
Interest cost
    2,325       2,068       107       112  
Plan participants contributions
                       
Plan amendments
    (1,033 )     127       (217 )      
Actuarial loss (gain)
    3,713       4,113       114       (110 )
Benefits paid
    (800 )     (674 )     (199 )     (174 )
 
                       
Projected benefit obligations at end of year
  $ 45,172     $ 39,100     $ 1,634     $ 1,755  
 
                       
Change in plan assets:
                               
Fair value of plan assets at beginning of period
    24,677       20,114              
Actual gain on plan assets
    4,410       1,883              
Employer contribution
    2,835       3,354       199       174  
Plan participants contributions
                       
Benefits paid
    (800 )     (674 )     (199 )     (174 )
 
                       
Fair value of plan assets at end of period
  $ 31,122     $ 24,677     $     $  
 
                       
Reconciliation of funded status:
                               
Fair value of plan assets at end of year
  $ 31,122     $ 24,677     $     $  
Less benefit obligation at end of year
    45,172       39,100       1,634       1,755  
 
                       
Funded status at end of year
  $ (14,050 )     (14,423 )   $ (1,634 )     (1,755 )
 
                       
Unrecognized prior service costs
    n/a       100       n/a       (3,804 )
Unrecognized net actuarial loss
    n/a       11,983       n/a       1,005  
 
                       
Accrued benefit costs
    n/a     $ (2,340 )     n/a     $ (4,554 )
 
                       
     The pre-tax amounts related to our Pension Plans and other postretirement benefit plans recognized in our consolidated balance sheets as of December 31, 2006 and 2005 were as follows:
                                 
    Pension Benefits     Postretirement Benefits  
    2006     2005     2006     2005  
Amounts recognized in the consolidated balance sheets:
                               
Accrued benefit liability
  $ (6,732 )   $ (6,656 )   $ (2,649 )   $ (4,554 )
Intangible asset
          94              
Accumulated other comprehensive loss
    4,926       4,222       (1,635 )      
 
                       
Accrued pension cost
  $ (1,806 )   $ (2,340 )   $ (4,284 )   $ (4,554 )
 
     The pre-tax amounts in accumulated other comprehensive income (loss) as of December 31, 2006 that have not yet been recognized as components of net periodic benefit cost were as follows:
 
    Pension Benefits     Postretirement Benefits  
    2006             2006          
Net actuarial loss
  $ (12,769 )           $ (1,058 )        
Prior service (costs)/credit
    525               3,708          
 
                           
Accrued benefit costs
  $ (12,244 )           $ 2,650          
 
                           

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     As of December 31, 2006 and 2005, 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,
    2006   2005
Projected benefit obligation
  $ 45,172     $ 39,100  
Accumulated benefit obligation
    37,854       31,333  
Fair value of plan assets
    31,122       24,677  
     The weighted-average assumptions used to determine benefit obligations at December 31, 2006, 2005 and 2004 were as follows:
                                                 
    Pension Benefits   Postretirement Benefits
    2006   2005   2004   2006   2005   2004
Discount rate
    5.75 %     6.00 %     6.00 %     5.75 %     6.00 %     6.00 %
Rate of compensation increase
    3.50 %     3.50 %     3.00 %                  
     The weighted-average assumptions used to determine net periodic Benefit costs for the years ended December 31, 2006, 2005 and 2004 were as follows:
                                                 
    Pension Benefits   Postretirement Benefits
    2006   2005   2004   2006   2005   2004
Discount rate
    6.00 %     6.00 %     6.25 %     5.75 %     6.00 %     6.25 %
Expected return on plan assets
    9.00 %     9.00 %     9.00 %                  
Rate of compensation increase
    3.50 %     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 2006. 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  
    2006     2005     2004     2006     2005     2004  
Components of net periodic Benefit cost:
                                               
Service cost
  $ 1,867     $ 1,694     $ 1,326     $ 74     $ 75     $ 160  
Interest cost
    2,325       2,068       1,826       107       112       222  
Amortization of prior service costs
    63       27             (314 )     (314 )     (157 )
Expected return on plan assets
    (2,371 )     (1,996 )     (1,388 )                  
Recognized net actuarial loss
    573       544       563       61       67       29  
 
                                   
Net periodic benefit cost
  $ 2,457     $ 2,337     $ 2,327     $ (72 )   $ (60 )   $ 254  
 
                                   
     Plan Assets
     The weighted-average asset allocation of Alon’s pension benefits at December 31, 2006 and 2005 was as follows:
                 
    Pension Benefits
    Plan Assets
    2006   2005
Asset Category:
               
Equity securities
    76.0 %     82.0 %
Debt securities
    13.0 %     8.0 %
Real estate investment trust
    11.0 %     10.0 %
 
               
Total
    100.0 %     100.0 %
 
               

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     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.
     Cash Flows
     Alon contributed $2,835 and $3,354 to the pension plan for the years ended December 31, 2006 and 2005, respectively, and expects to contribute $4,430 to the pension plan in 2007. There were no employee contributions to the plans.
     The benefits expected to be paid in each year 2007 — 2011 are $1,011; $1,343; $1,213; $1,369, and $1,566, respectively. The aggregate benefits expected to be paid in the five years from 2012 — 2016 are $12,495. The expected benefits are based on the same assumptions used to measure Alon’s benefit obligation at December 31, 2006 and include estimated future employee service.
     In September 2006, the FASB issued Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, which amends Statement No. 87, Employers’ Accounting for Pensions, Statement No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, Statement No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, Statement No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, and other related accounting literature.
     Statement No. 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or a liability in the statement of financial position and to recognize changes in that funded status through comprehensive income in the year the changes occur. This statement also requires an employer to measure the funded status of a plan as of the date of the employer’s year-end statement of financial position. We adopted the funded status recognition and related disclosure requirements of Statement No. 158 as of December 31, 2006, and measured the funded status of our defined benefit plans as of that date.
     The effect of applying Statement No. 158 on individual lines in the consolidated balance sheet as of December 31, 2006 was as follows:
                         
    Before           After
    Application of           Application of
    Statement 158   Adjustments   Statement 158
Liabilities for pension benefits
  $ 1,806     $     $ 1,806  
Long term liabilities for pension benefits
    4,926       7,318       12,244  
Deferred income taxes
    1,897       2,631       4,528  
Accumulated other comprehensive income
    3,154       4,662       7,816  
     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, 2006 and 2005 was $125 and $165, respectively.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     For West Coast employees, Alon has a 401(k) savings plan available to all employees who are at least 19 years of age and have been employed at least one year. Participants may contribute a minimum of 2% up to a maximum of 18% of base pay subject to limits established by the Internal Revenue Service. Alon matches 100% of individual participant contributions based on the first 6% of compensation. Alon’s contribution to the plan for the period August 1, 2006 through December 31, 2006 was $546.
(14) Long-Term Debt
     A summary of Alon’s long-term debt follows:
                 
    December 31,  
    2006     2005  
Term loan credit facility
  $ 447,750     $  
Secured term loan
          100,000  
Revolving credit facilities
           
Retail credit facilities
    50,919        
Retail mortgages and equipment loans
          32,390  
 
           
Total debt
    498,669       132,390  
Less current portion
    (6,739 )     (4,487 )
 
           
Total long-term debt
  $ 491,930     $ 127,903  
 
           
     (a) Term Loan Credit Facility
     On June 22, 2006, Alon entered into a Credit Agreement with Credit Suisse (the “Credit Suisse Credit Facility”) with an aggregate available commitment of $450,000. On August 4, 2006, Alon borrowed $400,000 as a term loan upon consummation of the acquisition of Paramount Petroleum Corporation. On September 28, 2006, Alon borrowed an additional $50,000 as a term loan to finance the acquisition of Edgington Oil Company. The loans under the Credit Suisse Credit Facility will mature on August 2, 2013. At December 31, 2006, the loan rate was Eurodollar plus 2.25%. Principal payments of 1% per annum are to be paid in quarterly installments beginning September 30, 2006. At December 31, 2006, the outstanding balance was $447,750.
     The borrowings under the Credit Suisse Credit Facility bear interest at the range of Eurodollar rate plus 2.50% to the Eurodollar rate plus 1.75% per annum based upon the ratings of the loans by Standard & Poor’s Rating Service and Moody’s Investors Service, Inc. The Credit Suisse Credit Facility is jointly and severally guaranteed by all of Alon’s subsidiaries except for Alon’s retail subsidiaries. The Credit Suisse Credit Facility is secured by a second lien on Alon’s cash, accounts receivable and inventory and a first lien on most of the remaining assets of Alon.
     Alon may, from time to time, request an additional $100,000 of term loans under the Credit Suisse Credit Facility provided that the sum of the incremental loans and the then outstanding loans under the Credit Suisse Credit Facility does not exceed $550,000.
     Alon may prepay at any time a portion or all of the outstanding loan balance under the Credit Suisse Credit Facility with no prepayment premium.
     The Credit Suisse Credit Facility contains restrictive covenants, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, different businesses, certain lease obligations, and certain restricted payments. This facility does not contain any financial maintenance covenants.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     (b) 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 accrued interest at LIBOR (4.37% at December 31, 2005) plus 6.5% per year, but not less than 10% per annum, and was subject to a minimum annual payment of $2,500 per year which could be increased under certain circumstances or declined by lenders as defined in the agreement. This facility included 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, Alon made a payment of approximately $103,900 in satisfaction of its outstanding borrowings under its secured term loan agreement, including applicable accrued interest and prepayment premiums, with available cash on hand. $100,000 represented a voluntary prepayment of the outstanding principal under the term loan agreement, approximately $3,000 represented a prepayment premium and $900 represented accrued and unpaid interest on the principal balance. The $3,000 prepayment premium and $3,894 of unamortized debt issuance costs are included as interest expense in Alon’s consolidated statements of operations.
     (c) Revolving Credit Facilities
     Israel Discount Bank Credit Facility. Alon entered into a revolving credit facility (the “IDB Credit Facility”) on January 14, 2004, which was amended and restated on February 15, 2006 and further amended and restated on June 22, 2006, as amended on August 4, 2006 and February 28, 2007. The Israel Discount Bank of New York, or Israel Discount Bank, acts as administrative agent, co-arranger, collateral agent and lender, and Bank Leumi USA acts as co-arranger and lender under the revolving credit facility. The initial size of the IDB Credit Facility is $160,000 with options to increase the size of the facility to $240,000 if crude oil prices increase above certain levels or Alon increases its throughput capacity. Prior to the February 15, 2006 amendment, the amount available under the previous revolving credit facility was $141,600.
     Borrowing availability under the IDB Credit Facility is limited at any time to the lower of the total current size of the credit facility at that time, which is initially $160,000, or the amount of the borrowing base under the revolving credit agreement. As of December 31, 2006, the borrowing base under the IDB Credit Facility was $228,000. The entire IDB Credit Facility is available in the form of letters of credit and revolving loans. The borrowings under the IDB Credit Facility bear interest at the Eurodollar rate plus 1.50% per annum. The IDB Credit Facility is jointly and severally guaranteed by all of Alon’s subsidiaries except for its retail subsidiaries and the subsidiaries of Alon Paramount Holdings, Inc. (“Alon Holdings”) (excluding Alon Pipeline Logistics, LLC (“Alon Logistics”)). The IDB Credit Facility is secured by a first lien on cash, accounts receivables, inventories and related assets and a second lien on our fixed assets, excluding assets of the retail subsidiaries and the subsidiaries of Alon Holdings (excluding Alon Logistics). The IDB Credit Facility includes certain restrictions and covenants, including among other things, limitations on capital expenditures, dividend restrictions and minimum net worth and coverage ratios.
     There were no borrowings outstanding under the IDB Credit Facility at December 31, 2006 and 2005. As of December 31, 2006 and 2005, Alon had $102,119 and $131,727, respectively, of outstanding letters of credit under the IDB Credit Facility.
     Bank of America Credit Facility. In conjunction with Alon’s acquisition of Paramount Petroleum Corporation, Alon Holdings assumed a Revolving Credit Agreement (the “Paramount Initial Credit Facility”) between Paramount Petroleum Corporation and Bank of America N.A. as Agent and a group of financial institutions, secured by the assets of Paramount Petroleum Corporation. Borrowings under the Paramount Initial Credit Facility were limited to up to $215,000, consisting of revolving loans and letters of credit. There were no borrowings outstanding under the Paramount Initial Credit Facility at December 31, 2006 and outstanding letters of credit were approximately $75,472.
     On March 1, 2007, Alon's Paramount subsidiary entered into an amended and restated credit agreement (“Paramount Credit Facility”) with Bank of America N.A. as agent, sole lead arranger and book manager primarily secured by the assets

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
of Alon Holdings (excluding Alon Logistics). Borrowings under the Paramount Credit Facility are limited to up to $300,000, consisting of revolving loans and letters of credit. Amounts borrowed under the Paramount Credit Facility accrue interest at the Eurodollar plus a margin based on an excess availability grid. Based on the availability as of December 31, 2006, such interest rate would be 1.25% over the Eurodollar. The Paramount Credit Facility expires on February 28, 2012. Alon’s Paramount subsidiary is required to comply with certain restrictive covenants related to working capital and operations under the Paramount Credit Facility.
     (d) Retail Credit Facility
     On June 6, 2006, Southwest Convenience Stores, LLC, a wholly-owned subsidiary of the Company (“SCS”) entered into a Credit Agreement (the “Wachovia Credit Facility”) by and among SCS, as borrower, and Wachovia Bank. Borrowings under the Wachovia Credit Facility are available in the form of (i) a term loan commitment in an aggregate principal amount of $30,000 maturing on June 30, 2016, and (ii) a revolving credit commitment (available in the form of revolving loans and letters of credit) in an aggregate principal amount of $20,000 maturing on June 30, 2009. Revolving loans may be converted by SCS at any time to a term loan maturing on the tenth anniversary of conversion. At the request of SCS, the revolving credit commitment may be increased by an amount not to exceed $10,000. The aggregate amount of the lenders’ commitments under the entire Wachovia Credit Facility may not exceed $60,000. On July 3, 2006, SCS borrowed $50,000 of which $30,200 was used to refinance existing debt and approximately $19,800 was used to finance the acquisition of Good Time stores. At December 31, 2006, the outstanding balances were $29,833 in the form of a term loan and $20,000 in the form of a revolving loan.
     Borrowings under the Wachovia Credit Facility bear interest at a Eurodollar rate plus 1.5% per annum. Principal payments of term loan borrowings under this credit facility are being paid in monthly installments based on a 15 year amortization term.
     Obligations under the Wachovia Credit Facility are jointly and severally guaranteed by Alon, Alon’s wholly-owned subsidiaries Alon USA Interests, LLC and all of the subsidiaries of SCS. The obligations under the Wachovia Credit Facility are secured by a pledge of substantially all of the assets of SCS and its subsidiaries, including cash, accounts receivable and inventory.
     The Wachovia Credit Facility includes a financial covenant that requires SCS to maintain a ratio of total consolidated EBITDA less income tax expense in cash to total consolidated scheduled principal payments of indebtedness plus interest expense, as of the end of each fiscal year, of not less than 1.25 to 1.0. Compliance with this covenant is determined in the manner specified in the documentation governing the credit facility. Consolidated EBITDA under the Wachovia Credit Facility represents net income plus depreciation, amortization, taxes, interest expense and minority interest less gain on disposition of assets.
     The Wachovia Credit Facility contains customary restrictive covenants on the activities of SCS and its subsidiaries, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, different businesses, certain lease obligations, and certain restricted payments.
     (e) Retail Mortgages and Equipment Loans
     In 2003, Alon obtained $1,545 in mortgage loans to finance the acquisition of new retail locations. The interest rates on these loans ranged between 5.5% and 9.7%, with 5 to 15 year payment terms.
     On July 3, 2006, Alon made a payment of approximately $30,200 in satisfaction of its outstanding borrowings under retail mortgages and equipment loans, including approximately $600 in prepayment premiums. The $600 prepayment premium and $2,197 of unamortized debt issuance costs are included as interest expense in Alon’s consolidated statements of operations.

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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, 2006 are as follows: 2007 — $6,739; 2008 — $6,792; 2009 — $26,530; 2010 — $6,533; 2011 — $6,536 and thereafter — $445,539.
     (g) Interest and Financing Expense
     Interest and finance expense included in the consolidated statements of operations consisted of the following:
                         
    December 31,  
    2006     2005     2004  
Interest expense
  $ 17,685     $ 15,422     $ 19,261  
Letters of credit and finance costs
    6,333       3,385       3,415  
Amortization of debt issuance costs (includes write off of debt costs of $6,091 in 2006)
    6,640       1,446       1,329  
Capitalized interest
          (927 )     (301 )
 
                 
Total interest expense
  $ 30,658     $ 19,326     $ 23,704  
 
                 
     (15) Income Taxes
     Income tax expense included the following:
                         
    December 31,  
    2006     2005     2004  
Current:
                       
Federal
  $ 77,372     $ 41,886     $ 15,554  
State
    8,332       6,986       1,092  
 
                 
Total current
    85,704       48,872       16,646  
 
                 
Deferred:
                       
Federal
    5,035       16,009       1,487  
State
    3,229       637       182  
 
                 
Total deferred
    8,264       16,646       1,669  
 
                 
Income tax expense
  $ 93,968     $ 65,518     $ 18,315  
 
                 
     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,  
    2006     2005     2004  
Computed expected tax expense
  $ 90,852     $ 61,481     $ 16,104  
State and local income taxes, net of federal benefit
    7,516       4,895       828  
Deduction for qualified production income
    (2,049 )     (1,111 )      
Low-sulfur diesel tax credit
    (2,918 )            
Other, net
    567       253       1,383  
 
                 
Income tax expense
  $ 93,968     $ 65,518     $ 18,315  
 
                 

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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,  
    2006     2005  
Deferred income tax assets:
               
Accounts receivable, allowance
  $ 855     $ 327  
Deferred gain
    3,640       2,009  
Accrued liabilities and other
    1,918       205  
Post retirement benefits
    3,840       1,742  
Noncurrent accrued liabilities and other
    8,018       841  
Net operating loss carryover
    11,569        
Tax credits
    1,280        
Other
    338        
 
           
Deferred income tax assets
    31,458       5,124  
 
           
Deferred income tax liabilities:
               
Deferred charges
    (2,931 )      
Intangibles
    (6,081 )      
Property, plant, and equipment
    (198,104 )     (35,370 )
Other noncurrent
    (32,550 )     (19,635 )
Inventories
    (16,904 )     (826 )
 
           
Deferred income tax liabilities
  $ (256,570 )   $ (55,831 )
 
           
     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.
     (16) 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 January, 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.
     (17) 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 46,806,443 and 46,809,857 shares of common stock as of December 31, 2006 and 2005, respectively. There were no issued and outstanding shares of preferred stock as of December 31, 2006 and 2005.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     For the years ended December 31, 2006, 2005 and 2004, activity in the number of common stock was as follows:
         
    Common
    Stock
    (in thousands)
Balance as of January 1, 2004
    35,001  
Balance as of December 31, 2004
    35,001  
Sale of Common Stock
    11,730  
Shares issued in connection with stock plans (Note 19)
    79  
 
       
Balance as of December 31, 2005
    46,810  
Shares forfeited
    (6 )
Shares issued in connection with stock plans (Note 19)
    2  
 
       
Balance as of December 31, 2006
    46,806  
 
       
     (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.
     (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. (“Alon Operating”) approved the payment of special dividends to pre-offering stockholders of record. The applicable stockholders 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.
     Common Stock Dividends
     On March 21, 2006, Alon paid a regular quarterly cash dividend of $0.04 per share and a special cash dividend of $0.37 per share on Alon’s common stock to stockholders of record at the close of business on March 1, 2006. In connection with Alon’s cash dividend payment to stockholders on March 21, 2006, the minority interest owners of Alon Assets, Inc. (“Alon Assets”) and Alon Operating received an aggregate cash dividend of approximately $1,078. On June 14, 2006, Alon paid a regular quarterly cash dividend of $0.04 per share on Alon’s common stock to stockholders of record at the close of business on June 1, 2006. In connection with Alon’s cash dividend payment to stockholders on June 14, 2006, the minority interest owners of Alon Assets and Alon Operating received an aggregate cash dividend of approximately $105. On September 14, 2006, Alon paid a regular quarterly cash dividend of $0.04 per share and a special cash dividend of $2.50 per share on Alon’s common stock to stockholders of record at the close of business on September 1, 2006. In connection with Alon’s cash dividend payment to stockholders on September 14, 2006, the minority interest owners of Alon Assets and Alon Operating received an aggregate cash dividend of approximately $6,680. On December 14, 2006, Alon paid a regular quarterly cash dividend of $0.04 per share on Alon’s common stock to stockholders of record at the close of business on December 1, 2006. In connection with Alon’s cash dividend payment to stockholders on December 14, 2006, the minority interest owners of Alon Assets and Alon Operating received an aggregate cash dividend of approximately $105.
     On February 8, 2007, Alon announced a quarterly cash dividend of $0.04 per share payable March 14, 2007 for stockholders of record at the close of business on March 1, 2007 (Note 22).

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     (18) 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  
    2006     2005     2004  
Net income
  $ 157,368     $ 103,988     $ 25,132  
Average number of shares of common stock outstanding
    46,738       39,889       35,001  
Effect of dilutive restricted shares
    41       19        
 
                 
Average number of shares of common stock outstanding assuming dilution
    46,779       39,908       35,001  
 
                 
Earnings per share — basic
  $ 3.37     $ 2.61     $ .72  
 
                 
Earnings per share — diluted
  $ 3.36     $ 2.61     $ .72  
 
                 
     (19) Stock Based Compensation
     Alon has two employee incentive compensation plans, (i) the 2005 Incentive Compensation Plan and (ii) the 2000 Incentive Stock Compensation Plan.
     (a) 2005 Incentive Compensation Plan (share value in dollars)
     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 awards of 10,791 shares of restricted stock and in November 2005 Alon granted an award of 12,500 shares of restricted stock, in each case to certain directors, officers and key employees in connection with Alon’s IPO in July 2005. The participants were allowed to acquire shares at a discounted price of $12.00 per share with a grant date fair value of $16.00 per share for the August 2005 awards and $20.42 per share for the November 2005 award. In November 2005, Alon granted awards of 52,672 shares of restricted stock to certain 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. In August 2005, 2,774 shares of restricted stock were awarded to Alon’s non-employee directors with a grant date fair value of $18.03 per share. In May 2006, 2,253 shares of restricted stock were awarded to non-employee directors with a grant date fair value of $33.29 per share. Additionally, restricted shares of 5,667 were forfeited and 2,833 shares were accelerated to vest from the November 2005 issuance. By December 31, 2006, an additional 23,411 shares vested from the 2005 issuances. All restricted shares granted under the Incentive Compensation Plan vest over a period of three years, assuming continued service at vesting.
     Compensation expense for the restricted stock grants amounted to $514 for the year ended December 31, 2006. There is no material difference between intrinsic value under Opinion 25 and fair value under SFAS No. 123R for pro forma disclosure purposes.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
                 
            Weighted Average  
Nonvested Shares   Shares     Grant Date Fair Values  
Nonvested at January 1, 2006
    78,737     $ 19.73  
Granted
    2,253       33.29  
Vested
    (26,244 )     19.73  
Forfeited
    (5,667 )     20.42  
 
           
Nonvested at December 31, 2006
    49,079     $ 20.27  
 
           
     As of December 31, 2006, there was $331 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the 2005 Incentive Compensation Plan. That cost is expected to be recognized over a weighted-average period of 1.9 years. Total fair value of shares vested in 2006 was $762.
     (b) 2000 Incentive Stock Compensation Plan
     At August 1, 2000 (inception), Alon Operating and Alon Assets majority owned, fully consolidated subsidiaries of Alon, adopted a stock option plan (collectively, the “Option Plans”) pursuant to which Alon’s board of directors may grant stock options to certain officers and executive management. The Option Plans 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). The Option Plans were closed to new participants subsequent to August 1, 2000, the initial grant date. Total compensation expense recognized under the Option Plans using the intrinsic value method was $1,931, $1,949 and $530 at December 31, 2006, 2005, and 2004, respectively.
     The following table summarized the stock option activity for Alon Assets and Alon Operating for the years ended December 31, 2006 and 2005:
                                 
    Alon Assets     Alon Operating  
            Weighted             Weighted  
    Number of     Average     Number of     Average  
    Options     Exercise     Options     Exercise  
    Outstanding     Price     Outstanding     Price  
Outstanding at January 1, 2005
    9,272     $ 100       3,482     $ 100  
Granted
                       
Exercised
    (1,212 )     100       (455 )     100  
Forfeited and expired
                       
 
                       
Outstanding at December 31, 2005
    8,060     $ 100       3,027     $ 100  
 
                       
Granted
                       
Exercised
    (1,212 )     100       (455 )     100  
Forfeited and expired
                       
 
                       
Outstanding at December 31, 2006
  $ 6,848     $ 100     $ 2,572     $ 100  
 
                       
     The intrinsic value of total options exercised in 2006 was $5,046.
     (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.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     (20) 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, 2006, minimum lease payments on operating leases were as follows:
         
Year ending December 31:        
2007
  $ 24,105  
2008
    20,122  
2009
    18,407  
2010
    17,131  
2011
    13,114  
2012 and thereafter
    63,760  
 
     
Total
  $ 156,639  
 
     
     Total rental expense was $15,523, $11,235 and $12,042 for the years ended December 31, 2006, 2005 and 2004, 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.
     On March 1, 2006, Alon sold its Amdel and White Oil crude oil pipelines, which had been inactive since December 2002, to an affiliate of Sunoco, Inc., or Sunoco, for a total consideration of approximately $68.0 million. In conjunction with the sale of the Amdel and White Oil pipelines, Alon 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 allows Alon to maintain crude oil transportation rights on the pipelines from the Gulf Coast and from Midland to the Big Spring refinery. Pursuant to the Throughput and Deficiency Agreement, Alon has agreed to ship a minimum of 15,000 bpd on the pipelines during the term of the agreement. Alon commenced shipments of crude oil through the Amdel and White Oil pipelines under this agreement in October 2006.
     To further diversify crude oil delivery sources to the Big Spring refinery, Alon entered into a 15-year arrangement with Centurion in June 2006. Pursuant to this arrangement, Centurion will provide us with crude oil transportation pipeline capacity and we will ship a minimum of 21,500 bpd of crude oil from Midland to our Big Spring refinery using Centurion’s approximately forty-mile long pipeline system from Midland to Roberts Junction and our three mile pipeline from Roberts Junction to the Big Spring refinery which we lease to Centurion. Alon commenced shipments of crude oil through these pipelines in November 2006.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     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.
     (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 $100 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 $20,000, 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 $40,099 ($1,750 current payable and $38,349 non-current liability) at December 31, 2006 and $4,736 ($1,750 current payable and $2,986 non-current liability) at December 31, 2005.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
     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 consumption by 2009. Alon spent approximately $12,935 in 2006 and expects to spend approximately $15,400 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 ended in December 2006. As of December 31