10-K 1 d80027e10vk.htm FORM 10-K e10vk
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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, 2010
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
(State of incorporation)
  74-2966572
(I.R.S. Employer Identification No.)
     
7616 LBJ Freeway, Suite 300, Dallas, Texas
(Address of principal executive offices)
  75251
(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
$0.01 per share
  New York Stock Exchange
Securities registered pursuant to Section 12 (g) of the Act: Series A Preferred Stock, par value $0.01 per share
     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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer o   Accelerated filer þ   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a Smaller reporting company)    
     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, 2010, the last day of the registrant’s most recently completed second fiscal quarter was $74,254,704.
     As of March 1, 2011, 55,083,372 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 registrant’s 2011 annual meeting of stockholders, which is incorporated into Part III of this Form 10-K.
 
 

 


 

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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 a crude oil refinery in Big Spring, Texas, and related pipeline, terminal and marketing assets from Atofina Petrochemicals, Inc., or FINA. In 2006, we acquired 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. In 2008, we acquired a refinery in Krotz Springs, Louisiana through the acquisition of Valero Refining Company-Louisiana. In June 2010, we acquired a refinery in Bakersfield, California, through the purchase of substantially all of the assets of Big West of California, LLC. As of December 31, 2010, we operated 304 convenience stores in Central and West Texas and New Mexico, primarily under the 7-Eleven and FINA brand names. Our convenience stores typically offer merchandise, food products and motor fuels. 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”) holds more than 50% of the voting power for the election of our directors through its ownership of approximately 75% 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 Alon Holdings Blue Square-Israel Ltd. (“Blue Square”), a leading retailer in Israel, which is listed on the New York Stock Exchange and the Tel Aviv Stock Exchange, and Blue Square is a controlling shareholder of Dor-Alon Energy in Israel (1988) Ltd. (“Dor-Alon”), a leading Israeli marketer, developer and operator of gas stations and shopping centers, which is listed on the Tel Aviv Stock Exchange.
     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 at the SEC’s website at www.sec.gov. In addition, we make our SEC filings available free of charge through our website at www.alonusa.com as soon as reasonably practicable after we 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 website at www.alonusa.com:
    Compensation Committee Charter;
 
    Audit Committee Charter;
 
    Corporate Governance Guidelines; and
 
    Code of Business Conduct and Ethics.

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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 crude oil refineries are located in Texas, California, Oregon and Louisiana and have a combined throughput capacity of approximately 250,000 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 presentation of segment data reflects our following three operating segments: (i) refining and unbranded marketing, (ii) asphalt and (iii) retail and branded marketing. Additional information regarding our operating segments and properties is presented in Note 5 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
Refining and Unbranded Marketing
     Our refining and unbranded marketing segment includes sour and heavy crude oil refineries that are located in Big Spring, Texas; and Paramount, Bakersfield and Long Beach, California; and a light sweet crude oil refinery located in Krotz Springs, Louisiana. We refer to the Paramount, Bakersfield and Long Beach refineries together as our “California refineries.” These refineries have a combined throughput capacity of approximately 240,000 bpd. At our refineries we refine crude oil into petroleum products, including gasoline, diesel fuel, 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,” which generally refers to a refinery utilizing vacuum distillation and catalytic cracking processes in addition to basic distillation, naphtha reforming and hydrotreating processes, to produce higher light product yields through the conversion of heavier fuel oils into gasoline, light distillates and intermediate products.
     Major processing units at our Big Spring refinery include fluid catalytic cracking, naphtha reforming, vacuum distillation, hydrotreating and alkylation units.
     On February 18, 2008, a fire at the Big Spring refinery destroyed the propylene recovery unit and damaged equipment in the alkylation and gas concentration units. The re-start of the crude unit in a hydroskimming mode began on April 5, 2008 and the Fluid Catalytic Cracking Unit (“FCCU”) resumed operations on September 26, 2008. Substantially all of the repairs to the units damaged in the fire were completed by the end of January 2010.
     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 85.0% of the Big Spring refinery’s crude oil input.
     Our Big Spring refinery produces ultra-low sulfur gasoline, ultra-low sulfur diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum products. This refinery typically converts approximately 90.0% of its feedstock into finished products such as gasoline, diesel, jet fuel and petrochemicals, with the remaining 10.0% primarily converted to asphalt and liquefied petroleum gas.

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     The following table summarizes historical throughput and production data for our Big Spring refinery:
                                                 
    Year Ended December 31,  
    2010     2009     2008  
    bpd     %     bpd     %     bpd     %  
Refinery throughput:
                                               
Sour crude
    39,349       80.2       48,340       80.8       31,654       83.8  
Sweet crude
    7,288       14.9       9,238       15.4       4,270       11.3  
Blendstocks
    2,391       4.9       2,292       3.8       1,869       4.9  
 
                                   
Total refinery throughput (1)
    49,028       100.0       59,870       100.0       37,793       100.0  
 
                                   
 
                                               
Refinery production:
                                               
Gasoline
    24,625       50.7       26,826       45.0       14,266       38.4  
Diesel/jet
    15,869       32.7       19,136       32.2       10,439       28.2  
Asphalt
    2,827       5.8       5,289       8.9       4,850       13.1  
Petrochemicals
    2,939       6.0       2,928       4.9       1,221       3.3  
Other
    2,341       4.8       5,327       9.0       6,298       17.0  
 
                                   
Total refinery production (2)
    48,601       100.0       59,506       100.0       37,074       100.0  
 
                                   
 
                                               
Refinery utilization (3)
            68.2 %             82.3 %             52.3 %
 
(1)   Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.
 
(2)   Total refinery production represents the barrels per day of various products resulting from the refinery production process.
 
(3)   Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.
     Refinery throughput and production for 2010 reflects our efforts to implement new operating procedures which reduced throughput rates. Refinery throughput and production for 2009 reflects the effects of downtime associated with a scheduled reformer regeneration in May 2009, an unscheduled reformer regeneration in November 2009 and a scheduled shutdown of the ultra-low sulfur gas unit for completion of our ultra-low sulfur gas project. Refinery throughput and production for 2008 reflects the effects of the downtime associated with the February 18, 2008 fire.
     Big Spring Refinery Raw Material Supply
     Sour crude oil has typically accounted for more than 90% of our crude oil input at the Big Spring refinery, of which approximately 93% was West Texas Sour (“WTS”) crude oil prior to 2007. In late 2006, we began to use different crudes and feedstocks shipped from the Texas Gulf Coast on the Amdel pipeline to diversify our crude sources and to improve production yields. As a result, in 2008 WTS was approximately 63% of the Big Spring Refinery’s sour crude oil input. WTS was approximately 78% of the Big Spring Refinery’s sour crude oil input in 2009 and approximately 84% of the Big Spring Refinery’s sour crude oil input in 2010. Our Big Spring refinery is the closest refinery 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.
     More than half 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 pipelines 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 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% interest.

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     Crude Oil Pipelines
     We receive WTS crude oil and West Texas Intermediate (“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 through the Amdel and White Oil pipelines. This combination of access to Permian Basin crude oil and foreign and offshore domestic crude oil from the Gulf Coast allows 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 bi-directional Amdel pipeline and the 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 Mesa Interconnect pipeline which is connected to the Mesa pipeline system, a common carrier, and through our owned connection pipeline which is leased to Centurion Pipeline L.P. (“Centurion”) and connected to the Centurion pipeline system from Midland, Texas to Roberts Junction in Texas.
     On March 1, 2006, we sold our Amdel and White Oil crude pipelines to an affiliate of Sunoco, Inc. (“Sunoco”) and 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, Texas 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 ship a minimum of 21,500 bpd of crude oil from Midland, Texas to our Big Spring refinery using Centurion’s pipeline system from Midland to Roberts Junction and our owned 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. In 2010, gasoline accounted for approximately 50.7% 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. We completed our ultra-low sulfur gasoline project in 2009 and gasoline currently produced at the Big Spring refinery complies with the U.S. Environmental Protection Agency’s (“EPA”) ultra-low sulfur gasoline standard of 30 parts per million (“ppm”). 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. In 2010, diesel and jet fuel accounted for approximately 32.7% of our Big Spring refinery’s production. All of the on-road specification diesel fuel we produce meets the EPA’s ultra-low sulfur diesel standard of 15 ppm. Our jet fuel production conforms to the JP-8 grade military specifications.
     Asphalt. Asphalt accounted for approximately 5.8% of our Big Spring refinery’s production in 2010. Approximately 39.1% of our Big Spring refinery’s asphalt production is blended paving grades and 60.9% 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. Our asphalt facilities are capable of producing up to 30 different product formulations, 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 prices substantially determined by reference to the cost of crude oil, which is intended to approximate bulk wholesale market prices.

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     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 while continuing to process significant amounts of sour crude oil.
     Big Spring Refinery Transportation Fuel Marketing
     Our refining and unbranded marketing segment sells 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 portions of Texas, Oklahoma, New Mexico and Arizona through our physically integrated system. We refer to these areas as our ‘physically integrated system’ because our distributors in this region are supplied 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. During 2010, approximately 63% of the gasoline and 22% of the diesel motor fuels produced at our Big Spring Refinery were transferred to our retail and branded marketing segments at prices substantially determined by reference to commodity pricing information published by Platts.
     Unbranded Transportation Fuel Marketing. We presently sell a majority of the diesel fuel and approximately 20.94% of the gasoline produced at our Big Spring refinery on an unbranded basis. During 2010 we sold over 13,378 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 Abilene, Texas and Sheppard Air Force Base in Wichita Falls, Texas. Jet fuel production in excess of existing contracts is sold through unbranded rack sales.
     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   2012
Fin-Tex
  HEP throughput     137     Midland and Orla (Holly)   2020
Holly
  Lease     133     Orla and El Paso   2022
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 4-mile pipeline that we own connecting Big Spring and Coahoma, Texas.

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     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 4 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, or mid-continent, markets. The Trust and River pipeline system is a bi-directional pipeline system which we access through our Pipelines and Terminals Agreement with HEP.
     The Dyess JP-8 pipeline connects the Abilene terminal to Dyess Air Force Base. Our access to this pipeline is also provided through our Pipelines and Terminals Agreement with HEP.
     Our Carswell pipeline system runs from Abilene 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 two 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     189     Pipeline   Pipeline/truck
Duncan, Oklahoma
  Owned (3)     154     Pipeline   Pipeline
Orla, Texas
  HEP     116     Pipeline   Pipeline
Southlake, Texas
  Terminalling Agreement     212     Pipeline   Truck
 
                   
Total
        1,113          
 
                   
 
(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.
     All six terminals we access are physically integrated with our Big Spring refinery through the product pipelines we utilize. Four of these six terminals, Big Spring, Abilene, Southlake and Wichita Falls, are equipped with truck loading racks. The other two terminals, Duncan, Oklahoma and Orla, Texas, are used for delivering shipments into third-party pipeline systems. The Southlake terminal is supplied pursuant to a throughput agreement with Nustar Logistics, LP (“Nustar”) whereby we have agreed to ship 2,000 bpd of product from the HEP-owned Wichita Falls,

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Texas terminal to the Southlake terminal through Nustar’s pipeline. We also directly access three other terminals located in El Paso, Texas and Tucson and Phoenix, Arizona.
California Refineries and Terminals
     In August 2006 we acquired Paramount Petroleum Corporation. Paramount Petroleum Corporation’s assets included two 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. 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” which is a more complex refinery configuration than a “topping refinery” (described below), adding naphtha reforming, hydrotreating and other chemical treating processes to the distillation process. In addition to producing vacuum gas oil and asphalt, our Paramount refinery utilizes naphtha reforming and hydrotreating to produce gasoline and distillate products from the light oil streams resulting from the distillation process.
     In September 2006 we acquired Edgington Oil Company. Edgington Oil Company’s assets included a refinery located on 19 acres in Long Beach, California with a nameplate capacity of approximately 40,000 bpd. In industry terms, the Long Beach refinery is characterized as a “topping refinery” which generally refers to a low complexity refinery configuration consisting primarily of a distillation unit. Distillation is the first step in the refining process — separating crude oil into its constituent petroleum products. The Long Beach refinery primarily produces vacuum gas oil and asphalt.
     In June 2010 we acquired a refinery located in Bakersfield, California from Big West of California, LLC, a subsidiary of Flying J, Inc. The Bakersfield refinery is currently inactive as we work to integrate the operations of the Bakersfield refinery with our Paramount and Long Beach refineries. We plan to process vacuum gas oil produced by the other refineries in the hydrocracker unit located at the Bakersfield refinery. We refer to the Paramount, Bakersfield and Long Beach refineries together as our “California refineries.”
     Our California refineries are included in our refining and unbranded marketing segment, while our refinery in Willbridge is included in our asphalt segment.
     Our California refineries have the capability to process substantial volumes of less expensive sour crude oils. In 2010 at the California refineries, medium sour crude oil accounted for approximately 20.4% of crude oil input and heavy crude oil accounted for 79.6%. We own pipelines connecting the Paramount and Long Beach refineries.
     Our California refineries currently produce CARBOB gasoline, CARB diesel, jet fuel, asphalt and other petroleum products. In 2010, these refineries converted approximately 37.0% of crude oil into higher value products such as gasoline, diesel and jet fuel, and 34.6% converted to asphalt, fuel oil and sulfur. The remaining 28.4% of production was sold as unfinished feedstocks to other refineries and third parties.
     As reflected in our 2010 production results, the California refineries currently produce unfinished products, which typically provide lower margins than finished products. In order to realize higher margins for the sale of these products, we have completed a refinery upgrade project to bring online a naphtha hydrotreater located at the Paramount refinery. The naphtha hydrotreater allows us to increase our production of distillates and gasoline and to produce less unfinished products.
     In 2010, we averaged approximately 25.9% utilization of our California refineries’ crude oil throughput capacity. The following table summarizes 2010, 2009 and 2008 throughput and production data for our California refineries on a combined basis (excluding the Bakersfield refinery).

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    Year Ended December 31,  
    2010     2009     2008  
    bpd     %     bpd     %     bpd     %  
Refinery throughput:
                                               
Medium sour crude
    3,502       19.9       13,408       43.0       8,014       25.8  
Heavy crude
    13,688       77.8       17,420       55.9       22,590       72.6  
Blendstocks
    406       2.3       330       1.1       495       1.6  
 
                                   
Total refinery throughput (1)
    17,596       100.0       31,158       100.0       31,099       100.0  
 
                                   
 
                                               
Refinery production:
                                               
Gasoline
    2,629       15.4       4,920       16.2       4,141       13.7  
Diesel/jet
    3,704       21.6       7,123       23.5       7,481       24.8  
Asphalt
    5,919       34.6       8,976       29.5       9,214       30.5  
Light unfinished
                117       0.4              
Heavy unfinished
    4,483       26.2       8,813       29.0       9,182       30.4  
Other
    372       2.2       418       1.4       192       0.6  
 
                                   
Total refinery production (2)
    17,107       100.0       30,367       100.0       30,210       100.0  
 
                                   
Refinery utilization (3)
            25.9 %             46.2 %             46.3 %
 
(1)   Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.
 
(2)   Total refinery production represents the barrels per day of various products resulting from the refinery production process.
 
(3)   Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds, and including effects of downtime to optimize our refining and asphalt economics in 2010, 2009 and 2008.
     Our California refineries operated at low rates for 2010, 2009 and 2008 due to continued efforts to optimize asphalt production with demand. Additionally, in 2008 the California refineries were affected by planned turnarounds and the revamp of one of the crude units. The California refineries restarted in February 2009 after the completion of a refinery-wide turnaround and the completion of refinery upgrade projects. These projects included the upgrade of an idled naphtha hydrotreater, revamping a naphtha hydrotreater to hydrotreat jet fuel, upgrading crude units’ metallurgy, upgrading the refinery’s electrical system and the installation of a new flare gas recovery system. These upgrades resulted in the California refineries being operated in a hydroskimming mode. We continuously evaluate and optimize throughput at our California refineries based on the topping and hydroskimming margins environment.
     California Refineries Raw Material Supply
     For 2010, heavy crude oil accounted for approximately 79.6% of our crude oil input of which approximately 55.8% was California heavy crude oil. As a result of the proximity of the California 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. The majority of the California refineries’ crude oil input requirements are purchased on the spot market. The remainder 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. Other feedstocks, including butane and gasoline blendstocks, are delivered by truck and pipeline.

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     Crude Oil Pipelines
     The crude oil pipelines we utilize 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
Plains Pipeline
  Third Party     14     Long Beach and West Hynes Terminal
     The Paramount refinery is supplied by the Chevron Crude pipeline (heavy sour) and Paramount Crude pipeline (medium/heavy sour). The Long Beach refinery is supplied by the No. 3/No. 4 pipelines (heavy sour) and the BP pipeline (medium sour). As a supplement to our on-site storage facilities, we lease storage tanks located at the BP-owned East Hynes, the Plains West Hynes, and the Kinder Morgan Carson crude oil terminals. Additionally, we acquire California medium sour crude oil from the West Hynes terminal and utilize the Plains Dominguez and Long Beach terminals pursuant to throughput arrangements. 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.
     In June 2007, we purchased a crude oil and unfinished products pipeline system from Kinder Morgan, Inc. known as the “Black Oil System.” The Black Oil System includes approximately 6 miles of active and 13 miles of inactive pipelines in the Long Beach, California area. The Black Oil System provides our Paramount refinery and other third-party shippers with access to refineries and waterborne terminals.
     California Refineries Production
     Gasoline. In 2010, CARBOB gasoline accounted for approximately 17.6% of our California refineries’ production. The California refineries utilize a computerized component blending system to optimize gasoline blending. In addition, our California refineries are capable of producing specially formulated fuels, such as those required in the California, Nevada and Arizona markets.
     Distillates. In 2010, CARB diesel, Ultra-low sulfur EPA diesel, Jet A and military fuels accounted for approximately 11.9% of our California refineries’ production. All of the diesel fuel we produce is ultra-low sulfur CARB/EPA diesel. We produce both commercial Jet A and JP-8 grade military jet fuel.
     Asphalt. In 2010, asphalt accounted for approximately 34.6% of our California refineries’ production. Approximately 70.3% of our California refineries’ asphalt production is paving grades and 29.4% is roofing asphalt. Asphalt produced at the California refineries is transferred to our asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices.
     Light and Heavy Unfinished Feedstocks. We produce LPG, naphtha, unfinished distillates, fuel oil and gas oils used as refinery feedstocks, along with other by-products such as sulfur and fuel oil, 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 unbranded marketing segment sells 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 CARBOB gasoline and CARB diesel produced at our California refineries through the 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 our jet fuel as Jet A that is sold through the spot market, while our JP-8 military jet fuel is contracted to the DESC. All JP-8 grade is sold to the DESC under one-year contracts awarded through a competitive bidding

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process. Our JP-8 contract was not renewed in 2010 and, consequently, we did not produce JP-8. However, in 2010, we were awarded the DESC F76 distillate contract and have also been awarded a JP-8 contract for 2011. All of our light products are delivered to our customers via our Line 145 pipeline or the Paramount rack system.
     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 terminal located in Carson, California.
     California Product Pipelines/Terminal
     The Paramount refinery utilizes the Line 145 product pipeline and our Line 166 pipelines 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 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 145
Line 166
  Leased     2     Connects Line 145 to City of Carson, California (Kinder Morgan)
     The Paramount refinery also utilizes its own terminal at the refinery to distribute CARB diesel, California Reformulated Gasoline (CaRFG), F76 distillate fuel, JP-8 and Jet-A into the local market. This terminal is equipped with a truck loading rack that has permitted volumes of approximately 12,000 bpd of distillate and 13,000 bpd of gasoline.
     California Feedstock Pipelines
     The Paramount refinery operates a feedstock pipeline and terminal system that is used to supply gas oil and other unfinished product to other Los Angeles Basin refineries and third party terminals. The Black Oil System acquired in June 2007 provides our Paramount refinery and other third-party shippers with access to refineries and waterborne terminals. In 2008 we acquired portions of BP’s E-12A pipeline and Plain’s L-52 pipeline. These lines are connected to our Line 35, increasing the integration between our Paramount and Long Beach refineries.

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     The following table describes the components of our feedstock pipeline and terminal system:
                             
Feedstock Pipelines   Terminal   Access   Tankage (1)   Miles   Connections
Chevron No.1
      Leased             4     Connects our Paramount and Long Beach refineries to our Lakewood Terminal
 
                           
 
  Lakewood   Owned     110             Connects the Chevron No. 1 pipeline to our Line 160 pipeline
 
                           
Line 160
      Owned             7.1     Connects the Lakewood Terminal to our leased tanks at Kinder Morgan, other refiners and third party customers
 
                           
 
  Kinder Morgan   Leased     180             Connects to our Black Oil Pipeline for deliveries to other refiners and third party customers
 
                           
Line 35, L-52, E-12A
      Owned             4     Connects our Long Beach and Paramount Refineries
 
                           
Black Oil Pipeline
      Owned             19     Connects the Kinder Morgan Terminal and Plains Pipeline System to LA Basin refiners and waterborne terminals
 
                           
North of the River pipeline
  Mojave Spur   Owned             10     Connects the Kern River Oil Field Mojave Spur to our Bakersfield refinery to provide natural gas to the refinery fuel system and hydrogen plant.
 
(1)   Measured in thousands of barrels.
Krotz Springs Refinery
     In July 2008 we acquired Valero Refining Company — Louisiana. Valero Refining Company — Louisiana’s assets included a refinery with a nameplate capacity of approximately 83,100 located in Krotz Springs, Louisiana.
     The Krotz Springs refinery is strategically located on approximately 381 acres on the Atchafalaya River in central Louisiana at the intersection of two crude oil pipeline systems and has direct access to the Colonial pipeline system (“Colonial Pipeline”), providing us with diversified access to both locally sourced and foreign crude oils, as well as distribution of our products to markets throughout the Southern and Eastern United States and along the Mississippi and Ohio Rivers. In industry terms, the Krotz Springs refinery is characterized as a “mild residual cracking refinery”, which generally refers to a refinery utilizing vacuum distillation and catalytic cracking processes in addition to basic distillation and naphtha reforming processes to minimize low quality black oil production and to produce higher light product yields such as gasoline, light distillates and intermediate products.
     The Krotz Springs refinery processing units are structured to yield approximately 101.5% of total feedstock input, meaning that for each 100 barrels of crude oil and feedstocks input into the refinery, it produces 101.5 barrels of refined products. Of the 101.5%, on average 99.0% is light finished products such as gasoline and distillates, including diesel and jet fuel, petrochemical feedstocks and liquefied petroleum gas, and the remaining 2.5% is primarily heavy oils.
     The Krotz Springs refinery’s main processing units include a crude unit and an associated vacuum unit, a fluid catalytic cracking unit, a catalytic reformer unit, a polymerization unit, and an isomerization unit.
     Our Krotz Springs refinery has the capability to process substantial volumes of low sulfur, or sweet, crude oils to produce a high percentage of light, high-value refined products. Typically, sweet crude oil has accounted for 100% of the Krotz Springs refinery’s crude oil input.

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     In 2010, we averaged approximately 46% utilization of our crude oil throughput capacity for the Krotz Springs refinery. The following table summarizes 2010, 2009 and 2008 throughput and production data for our Krotz Springs refinery:
                                                 
    Year Ended December 31,  
    2010     2009     2008 (1)  
    bpd     %     bpd     %     bpd     %  
Refinery throughput:
                                               
Light sweet crude
    23,810       60.7       22,942       47.5       43,361       74.5  
Heavy sweet crude
    14,535       37.0       22,258       46.0       11,979       20.6  
Blendstocks
    899       2.3       3,137       6.5       2,844       4.9  
 
                                   
Total refinery throughput (2)
    39,244       100.0       48,337       100.0       58,184       100.0  
 
                                   
 
                                               
Refinery production:
                                               
Gasoline
    15,812       40.1       22,264       45.4       25,195       42.8  
Diesel/jet
    18,986       48.2       21,318       43.4       26,982       45.9  
Heavy oils
    1,515       3.8       1,238       2.5       1,402       2.4  
Other
    3,107       7.9       4,258       8.7       5,258       8.9  
 
                                   
Total refinery production (3)
    39,420       100.0       49,078       100.0       58,837       100.0  
 
                                   
Refinery utilization (4)
            46.1 %             65.3 %             66.6 %
 
(1)   2008 data includes our Krotz Springs refinery for the period from July 1, 2008 through December 31, 2008.
 
(2)   Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.
 
(3)   Total refinery production represents the barrels per day of various products resulting from the refinery production process.
 
(4)   Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds. Refinery throughput and production for 2010 and 2009 reflects the effects of downtime associated with a shutdown that began in November 2009 and continued into the second quarter of 2010. Refinery throughput and production for 2008 reflects the effects of shutdowns during hurricanes Gustav and Ike and limited crude supply due to widespread electrical outages following the hurricanes.
     Krotz Springs Refinery Raw Material Supply
     In 2010, sweet crude oil accounted for approximately 100% of our crude oil input at the Krotz Springs refinery, of which approximately 62.1% was Light Louisiana Sweet (“LLS”) crude oil and 37.9% was Heavy Louisiana Sweet (“HLS”) crude oil. The Krotz Springs refinery has access to various types of domestic and foreign crude oils via a combination of two ExxonMobil pipeline (“EMPCo”) systems, barge delivery, or truck rack delivery. Approximately 80% of the crude oil is received by pipeline with the remainder received by barge or truck.
     We receive HLS, LLS and foreign crude oils from two EMPCo systems, the “Southbend/Sunset System,” and “Northline System”. The Southbend/Sunset System provides HLS crude oil from gathering systems at South Bend, Avery Island, Empire, Grand Isle and Fourchon, Louisiana. All of Southbend/Sunset’s current crude oil capacity is delivered to the Krotz Springs refinery. The Northline System delivers LLS and foreign crude oils from the St. James, Louisiana crude oil terminalling complex.
     The Krotz Springs refinery also has access to foreign crude oils from the St. James terminal. Various Louisiana crude oils can also be delivered by barge, via the Intracoastal Canal, the Atchafalaya River, or directly by truck.
     Historically, approximately three-quarters of our Krotz Springs refinery’s crude oil input requirements are purchased through term contracts with several suppliers. At present, J. Aron and Company (“J. Aron”), through arrangements with various oil

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companies, supplies the majority of Krotz Spring refinery’s crude oil input requirements. Other feedstocks, including butane and secondary feedstocks, are delivered by truck and marine transportation.
     Krotz Springs Refinery Production
     Gasoline. In 2010, gasoline accounted for approximately 40.1% of our Krotz Springs refinery’s production. We produce 87 octane regular unleaded gasoline and use a computerized component blending system to optimize gasoline blending. Our Krotz Springs refinery is capable of producing regular unleaded gasoline grades required in the southern and eastern U.S. markets.
     Distillates. In 2010, diesel, light cycle oil and jet fuel accounted for approximately 48.2% of our Krotz Springs refinery’s production. In connection with the acquisition of the Krotz Springs refinery in 2008, we entered into an offtake agreement with Valero Energy Corporation (“Valero”) that provides for Valero to purchase, at market prices, light cycle oil and high sulfur distillate blendstock for a period of five years.
     Heavy Oils and Other. In 2010, slurry oil, LPG and petrochemical feedstocks accounted for approximately 11.7% of the Krotz Spring refinery’s production.
     Krotz Springs Refinery Transportation Fuel Marketing
     Substantially all of the refined products produced by our Krotz Springs refinery are sold to J. Aron as they are produced. We market transportation fuel production through bulk sales and exchange channels. These bulk sales and exchange arrangements are entered into with various oil companies and traders and are transported to markets on the Mississippi River and the Atchafalaya River as well as to the Colonial Pipeline.
     Our refining and unbranded marketing segment sales include sales of refined products from our Krotz Springs refinery.
     Krotz Springs Refinery Product Pipelines
     The Krotz Springs refinery connects to and distributes refined products into the Colonial Pipeline for distribution by our customers to the southern and eastern United States. The 5,519 mile Colonial Pipeline transports products to 267 marketing terminals located near the major population centers. The connection to the Colonial Pipeline provides flexibility to optimize product flows into multiple regional markets. Products not shipped through the Colonial Pipeline are either transported via barge for sale or for further upgrading.
     Krotz Springs Refinery Barge, Railcar and Truck
     Products not shipped through the Colonial Pipeline, such as high sulfur diesel sold to Valero pursuant to our offtake agreement with Valero, are either transported via barge for sale or for further processing. Barges have access to both the Mississippi and Ohio Rivers.
     Propylene/propane mix is sold via railcar and truck, to consumers at Mont Belvieu, Texas or in adjacent Louisiana markets. Mixed LPGs are shipped on to an LPG fractionator at Napoleonsville, Louisiana. We pay a fractionation fee and sell the ethane and propane to a regional chemical company under contract, transport the normal butane back to the Krotz Springs refinery via truck for blending, and sell the isobutene and natural gasoline on a spot basis.
Asphalt
     In addition to gasoline and distillates, our California, Big Spring and Willbridge refineries produce significant quantities of vacuum tower bottoms (“VTB”), which we utilize to produce asphalt. We believe our asphalt production capabilities provides the opportunity to realize higher netbacks than those attainable by producing VTB into No. 6 Fuel Oil, which is an alternate product that can be produced at these refineries. In addition, our asphalt production capabilities permit us to realize value from VTB without the significant costs and expenses required to construct and operate coker units.
     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, the techniques used in the refining

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process and the type and quality of the asphalt produced. 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 GTR asphalt manufacturing process from Wright with respect to asphalt produced and sold in California.
     Asphalt produced by our California and Big Spring refineries is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices.
     We continue to believe that the asphalt business is a better alternative to producing No. 6 Fuel Oil or construction and operation of a coker unit. We believe that asphalt production in the markets in which we compete will be reduced due to coker unit projects that have been announced or recently completed by several asphalt producing refineries. We therefore expect the combination of decreased asphalt production in our markets and a stabilization of crude prices to improve our asphalt margins.
     Our Willbridge refinery is an asphalt topping refinery located on 42 acres in the industrial section of Portland, Oregon, with a crude oil throughput capacity of 12,000 bpd. Alternatively, the Willbridge facility can be operated as an asphalt terminal and supplied with asphalt produced at the California refineries or purchased from third parties. When operating the Willbridge facility as a refinery, it typically operates two to four months per year at times when cargos of heavy crude oil are available. Heavy crude oil is delivered to the Willbridge refinery through an adjacent dock leased by us from Chevron. The Willbridge refinery processes primarily heavy crude oil with approximately 70% of its production being asphalt products. The remaining products produced by the Willbridge refinery include approximately 5% naphtha and approximately 25% gas oils. Asphalt produced at the Willbridge facility is sold through our terminal at the Willbridge refinery or delivered by truck and railcar to terminals for further processing and resale. Gas oils and naphtha are sold to local refiners and other third parties and are primarily delivered by barge or rail cars.
     In addition to the Willbridge refinery, our asphalt segment includes 11 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Washington (Richmond Beach), Arizona (Phoenix, Flagstaff and Fredonia), Nevada (Fernley) (50% interest) and a 50% interest in Wright.
     In 2010, our asphalt segment sold asphalt produced at our refineries in Texas and California primarily as paving asphalt to road and materials manufacturers and highway construction/maintenance contractors, as GTR, polymer modified or emulsion asphalt to highway maintenance contractors, or as roofing asphalt to either roofing shingle manufacturers or to other industrial users.
Texas Asphalt Marketing
     Approximately 5.8% of our Big Spring refinery’s production in 2010 was asphalt. We can produce or manufacture approximately 30 different product formulations, 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 2008 data, the Texas Department of Transportation has advised us that we are one of the largest suppliers of asphalt to the State of Texas, which is the second largest asphalt consuming state in the United States according to the latest available industry data.
     Paving grade asphalts are predominantly sold from May through October through competitive bids to contractors involved in government projects. These asphalt sales are primarily made from 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 to our other asphalt terminals.
West Coast Asphalt Marketing
     In 2010, approximately 34.6% of our California refineries’ production was asphalt and asphalt blendstocks. Our California refineries/terminals produce over 100 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. These PG products meet the California PG specification

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included in the recently enacted conversion to Federal Highway SHRP asphalt performance grading system (PG). 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. The paving and roofing products produced at our refineries can be sold from the on-site asphalt terminal facilities or they can be distributed through and sold at one of our eight asphalt terminals in the western United States. Based upon the Asphalt Institute’s 2008 data, we are the largest supplier of liquid asphalt in the State of California, which is currently one of the top two largest asphalt consuming states in the United States.
     Sales of paving asphalt are made primarily to hot mix asphalt (HMA) materials manufacturers and paving contractors, either through negotiated 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 with approximately 68% of our West Coast paving asphalt products being sold between May and October 2010.
     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
    731     Refinery, Rail, Truck   Rail, Truck
Willbridge, OR refinery
    1,129 (2)   Refinery, Rail, Truck, Marine   Rail, Truck, Marine
Elk Grove, CA
    307     Rail, Truck   Truck
Bakersfield, CA
    183     Rail, Truck   Truck
Mojave, CA
    283     Rail, Truck   Truck
Richmond Beach, WA
    702 (2)   Rail, Truck, Marine   Truck, Marine
Fernley, NV (3)
    254     Rail, Truck   Truck
Phoenix, AZ
    165     Rail, Truck   Truck
Flagstaff, AZ
    25     Rail, Truck   Truck
Fredonia, AZ
    79     Truck   Truck
 
(1)   Measured in thousands of barrels.
 
(2)   Storage figures for Willbridge and Richmond Beach include tanks in service for storage of crude oil, fuel oil or other products.
 
(3)   50% interest.
     Deliveries of asphalt products to our non-refinery terminals are made primarily through common carrier trucks and leased railcars that are loaded at the California and Big Spring refineries. Asphalt produced at our Willbridge refinery is sold primarily through our terminal located at that facility but may also be delivered by rail or marine vessel to other terminals.
     We also own 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. In California we maintain the 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. During 2010, Wright obtained approximately 28.2% of its asphalt requirements from our refineries and terminals. Wright sells GTR and its other asphalt products on either a negotiated contract or competitive bidding basis.
Retail and Branded Marketing
     We are the largest 7-Eleven licensee in the United States and we are the sole licensee of the FINA brand for motor fuels in the South Central and Southwestern United States. Through our 7-Eleven licensing agreement, we have the exclusive right to operate 7-Eleven convenience stores in substantially all of our existing retail markets and many surrounding areas. We market gasoline and diesel fuel under the FINA brand name and provide brand support and payment services to distributors supplying over 630 locations, including all of our owned stores that sell motor

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fuel. In markets where we choose not to supply fuel products we also sub-license the FINA brand and provide the same brand support and payment services to distributors supplying approximately 260 additional locations. In 2010, approximately 91% of Alon’s branded marketing operations, including retail operations, were supplied by our Big Spring refinery.
Retail
     As of December 31, 2010, we operated 304 owned and leased convenience store sites primarily in Central and 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, primarily under the 7-Eleven and FINA brand names.
     We are one of the top three independent convenience store chains, measured by store count, in each of the cities of Abilene, El Paso, Midland, Odessa, Big Spring and Lubbock, Texas. We also have a significant presence in Waco and Wichita Falls, Texas and Albuquerque, New Mexico.
     The following table shows our owned and leased convenience stores by location:
                         
Location   Owned     Leased     Total  
Big Spring, Texas
    6       1       7  
Wichita Falls, Texas
    8       4       12  
Waco, Texas
    11       3       14  
Midland, Texas
    8       9       17  
Lubbock, Texas
    17       5       22  
Albuquerque, New Mexico
    12       11       23  
Odessa, Texas
    11       25       36  
Abilene, Texas
    32       9       41  
El Paso, Texas
    13       71       84  
Other locations in Central and West Texas
    29       19       48  
 
                 
Total stores
    147       157       304  
 
                 
     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 58 employees. We also maintain an office in Abilene, Texas, where we have 34 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 mark-up. Our current supply contract with McLane expires in December 2011. For the year ended December 31, 2010, approximately 50% of our retail merchandise sales were purchased 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 have implemented a point-of-sale checkout system at substantially all of our convenience stores and are in the process of implementing the system at our remaining stores. This system includes merchandise scanning, pump control, peripheral device integration, shortage control tools and daily operations reporting. This system enhances our ability to offer a greater variety of promotions with a high degree of flexibility regarding definition (by store, group of stores, region, or other subset of stores) and duration. We also are able to receive enhanced management reports that will assist our decision-making processes. We believe this system

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will allow our convenience store managers to spend less time preparing reports and more time analyzing these reports to improve convenience store operations. We plan to use this system as a platform to support other marketing technology projects, including interactive video at the pump and bar-code coupons at the pump.
Branded Marketing
     Approximately 81% of our branded fuel sales are in West Texas and Central Texas. We sell motor fuel under the FINA brand through various terminals to supply approximately 630 locations, including the majority of our retail locations and other FINA-branded independent locations. 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 1956. For the year ended December 31, 2010, we sold 318.9 million gallons of branded motor fuel for distribution to our retail convenience stores and other retail distribution outlets.
     We have an exclusive license through 2012 to use the FINA trademark in the wholesale distribution of motor fuel 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.
     Distribution Network and Distributor Arrangements. We sell motor fuel to our retail locations and to approximately 25 third-party distributors, who then supply and sell to retail outlets. The supply agreements we maintain with our distributors are generally for three-year terms and usually include 10-day payment terms. All supplied distributors comply with our ratability program, which involves incentives and penalties based on the consistency of their purchases.
     FINA Brand Sub-Licensing. We offer FINA brand sub-licensing to distributors supplying geographic areas other than our integrated supply system. In addition to a license to use the FINA brand, we also provide payment card processing services, advertising programs and loyalty and other marketing programs to 47 distributors supplying approximately 260 additional stores. This sub-licensing program allows us to expand the geographic footprint of the FINA brand, thereby increasing its recognition. Each sub-licensee pays royalties on a per gallon basis, is required to comply with the FINA minimum standards program and utilize our payment card processing services.
     FINA Minimum Standards Program. We have an established image consistency program where each FINA-branded facility in our network is inspected by an independent third-party organization. Each facility is evaluated using specific criteria and scores based upon these criteria are communicated to the controlling distributor. Any non-complying facilities are enrolled in a specific improvement program to bring the facility up to our FINA standards.
     Payment Card Processing. We offer payment card processing services to our distributors and FINA-branded sublicensees through a third-party provider, which acts as a clearinghouse with MasterCard, VISA, American Express, Discover and debit card issuers. Payment card transactions are communicated directly to a third-party provider, which then transmits those transactions to the appropriate card issuers. Our fees payable to MasterCard, VISA, American Express, Discover and debit card issuers are contracted through the third-party provider. Although our fees may vary by card type, we charge our customers, including our retail convenience stores, a percentage-based fee plus a transaction fee for each card type to simplify the fee structure. Our rates are designed to provide a margin on the difference between the fees paid by our distributors and fees charged by the various card associations. The fees are not designed to be a major profit center, but rather to cover overhead and ancillary expenses of maintaining the payment card network system. For MasterCard, VISA, American Express, Discover and debit cards, the third-party provider provides us with daily settlement of transactions. We generally provide our customers with payment or credit for transactions within five days. We also generally retain the settlement funds for such payment and transactions that we process as a credit against any payments due to us from our distributors or sub-licensees. As a result, offering these payment services reduces our credit risk.
     Technology. We rely on technology to enhance our operations and provide meaningful data and tools for management to evaluate and manage the profitability of our motor fuel distribution business. We have a licensing arrangement with a third-party provider for payment card processing and clearinghouse services for payment card purchases at many of our retail convenience stores, as well as all of the third-party retail locations supplied by our wholesale distributors or the sub-licensed FINA stores for which we provided branded services. Under our arrangement with the third-party provider, the proprietary software is provided to each of these retail locations to provide secure data transfer of payment card transactions directly to the third party provider for daily processing of

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each payment card transaction at these retail locations. We also license JD Edwards enterprise software tailored for our wholesale business that collects and analyzes the data from each of these payment card transactions that we process, providing our management with valuable information on consumer purchasing tendencies and trends. We use a proprietary software program to further break-down and analyze the payment card transactions that we process. We also license pricing optimization software that assists management in modeling and making timely pricing decisions in order to maximize our gross margin in motor fuel sales. In addition, we utilize licensed software to manage our customers’ motor fuel purchases and delivery arrangements.
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 support and diversity with a potential better ability to bear the economic risks, operating risks and volatile market conditions associated with the petroleum industry.
     Financial returns in the refining and marketing industry depend on the difference between refined product prices and the prices for crude oil and other feedstock, also referred to as refining margins. Refining margins are impacted by, among other things, levels of crude 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 vertically-integrated competitors have their own sources of crude oil that they may use to supply their refineries. However, our Big Spring refinery is in close proximity to Midland, Texas, which is the largest origination terminal for Permian Basin crude oil, which we believe provides us with transportation cost advantages over many of our competitors in this region.
     The market for our refined products are generally supplied by a number of refiners, including large integrated oil companies or independent refiners. 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 of refined products. This pipeline provides Gulf Coast refiners, which include some of the world’s largest and most complex refineries, and other shippers with improved access to the refined products markets in West Texas and New Mexico which results in greater competition to our Big Spring refinery. In August 2006, Longhorn Pipeline Holdings LLC, the owner of the Longhorn pipeline, was acquired by Flying J, Inc., (“Flying J”). Since Flying J’s acquisition, we have reduced shipments to El Paso via the Fin-Tex pipeline system, while increasing 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 contracted FINA-branded locations or are being used for exchange paybacks for sales in the Albuquerque and Bloomfield, New Mexico markets. In December 2008, Flying J and certain of its affiliates, including its subsidiary that operates the Longhorn pipeline, filed for bankruptcy. In July 2009, Magellan Midstream Partners, L.P. acquired the Longhorn pipeline from Flying J.
     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 that have little or no associated refining operations such as NuStar Energy LP. 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, Susser, Stripes, Circle K, Western Refining and various other independent operators. The principal competitive factors affecting our retail and branded marketing 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

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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.
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, water, and land, the handling and disposal of solid and hazardous waste and the remediation of contamination. We believe our operations are generally in substantial compliance with these 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
     Fuels
     The Clean Air Act and its implementing regulations require significant reductions in the sulfur content in gasoline and diesel fuel. These regulations required most refineries to reduce the sulfur content in gasoline to 30 ppm.
     Gasoline and diesel produced at our Big Spring and California refineries currently meet the low sulfur gasoline and diesel fuel standards. Gasoline produced at our Krotz Springs refinery currently meets the low sulfur gasoline standard. Our Krotz Springs refinery does not manufacture low sulfur diesel fuel.
     Our gasoline sulfur control schedule at our Big Spring refinery was impacted by the fire that occurred in February 2008. On September 25, 2009, we entered into an Administrative Settlement Agreement with EPA, which gave us an additional 90 days to meet the gasoline sulfur standards at the Big Spring refinery in consideration for our agreement to offset any excess gasoline sulfur during that time. We achieved compliance within the 90-day extension and purchased sulfur credits to offset the excess sulfur in early 2011.
     Compliance with the gasoline sulfur standards for the Big Spring refinery required capital expenditures of approximately $35.5 million through 2009, of which approximately $29.3, $5.2, and $1.0 million were spent in 2009, 2008, and 2007 respectively.
     In February 2007, the EPA adopted final rules 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 annual average gasoline benzene content standard of 0.62%, which may be achieved through the purchase of benzene credits, and that beginning on July 1, 2012, refiners meet a maximum average gasoline benzene concentration of 1.30%, by volume on all gasoline produced, both reformulated and conventional and without benzene credits. Gasoline produced at our California refineries already meets the standards established by the EPA. We have determined that capital expenditures of approximately $8.9 million in 2011 and an additional $27 million (through 2014) will be necessary in order for the Big Spring refinery to install controls to comply with the standards. We have determined that capital expenditures of approximately $10.5 million will be necessary in order for the Krotz Springs refinery to install controls to meet the standards. Under the regulations, the EPA may grant extensions of time to comply with the annual average benzene standard if a refinery demonstrates that unusual circumstances exist that impose extreme hardship and significantly affect the ability of the refinery to comply. We have requested an extension of time to comply with the annual average standard at our Krotz Springs refinery and are awaiting a response from the EPA.
     In May 2007, the EPA adopted a final rule that subjects refiners and importers of gasoline to a yearly renewable volume obligation that is based on the national renewable fuel standard. Due to our size, we were exempted from the

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requirements of this rule through December 31, 2010. In February 2010, the EPA finalized new regulations that replace and update the current rules and extend the renewable fuel standard to other finished products (e.g., diesel). Under the rule, we are required to blend renewable fuels (e.g., ethanol) into our finished products or purchase credits in lieu of blending. We are blending ethanol into some of the gasoline and diesel fuels that we manufacture at the Big Spring refinery and the California refineries. We will purchase credits (RINs) to satisfy the balance of our renewable fuel volume obligation for the product that we do not blend with ethanol. At this time, we do not know how many credits we will need or how much they will cost when we will be required to purchase them for compliance.
          Regulations
     Conditions may develop that require additional 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. The EPA recently promulgated regulations applicable to emissions of hazardous air pollutants from industrial heaters and boilers and reciprocating internal combustion engines, which may necessitate the installation of controls or additional monitoring at our refineries. In addition, the EPA recently passed greenhouse gas emission regulations, which may necessitate the installation of controls to reduce emissions of greenhouse gases if we construct new equipment or modify existing equipment in such a way that there is a significant increase in greenhouse gas emissions. Finally, the EPA will be finalizing rules applicable to refinery heaters, boilers, and flares that may necessitate the installation of controls or additional monitoring. We cannot currently determine the amounts of such future expenditures.
          Compliance
     On August 7, 2008 the South Coast Air Quality Management District (“SCAQMD”) issued a notice of violation to us for failing to continuously monitor emissions from four reformer heaters at the Paramount refinery. We subsequently settled the notice of violation for $30,000. We reached an agreement with the SCAQMD and have accepted permit conditions that required the installation of an automatic fuel shut-off system on each heater. The systems were installed in September 2010 at a cost of $150,000.
     Our Bakersfield refinery must comply with a local flare rule, Rule 4311 to limit the emissions of volatile organic compounds (VOC), oxides of nitrogen (NOx), and oxides of sulfur (SOx) from the operation of flares. This refinery has four flares, but we currently only plan to operate three of its flares. Initially, the rule requires monitoring of flare flow and concentrations of sulfur compounds during flaring events. Projects are currently underway to install the required monitoring equipment on the three flares that the refinery will operate at an estimated cost of $785,000. Based on monitoring data that is obtained, additional emission controls could be required.
     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 in a preliminary stage and it is possible that legal challenges could delay implementation of any regulations, 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.
     Although the U.S. House of Representatives passed the American Clean Energy and Security Act on June 26, 2009, which would have established a market-based “cap-and-trade” system to achieve yearly reductions in greenhouse gas (“GHG”) emissions, the 111th United States Congress did not pass comprehensive legislation addressing GHG emissions. While it is possible that Congress will adopt some form of federal mandatory GHG emission reductions legislation in the future, the timing and specific requirements of any such legislation are uncertain at this time, especially in light of several efforts by Republican members of Congress to stall the EPA’s efforts to regulate GHGs and repeal the authority of the EPA to regulate GHGs.
     In October 2006, we were contacted by Region 6 of the EPA and invited to enter into discussions under the EPA’s National 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. To date, 28 refining

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companies (representing over 90% of the U.S. refining capacity) have entered into “global settlements” under the initiative. On February 2, 2007, we committed in writing to enter into discussions with the EPA under the initiative. To date, there have been no specific findings entered against us or any of our refineries by the EPA, and we have not determined whether we will ultimately enter into a “global settlement” with the EPA. If we enter into a global settlement, it would apply to our Big Spring refinery, our Paramount and Long Beach refineries and our Willbridge, Oregon terminal. Based on prior settlements that the EPA has reached with other petroleum refineries under the initiative, we anticipate that the EPA will seek relief in the form of the payment of a civil penalty, the installation of air pollution controls, enhanced operations and maintenance programs, and the implementation of environmentally beneficial projects in consideration for a broad release from liability for violations that may have occurred historically. At this time, we cannot estimate the cost of any required controls or environmentally beneficial projects, but the civil penalty is expected to be comparable to other settling refiners.
     The Krotz Springs and Bakersfield refineries became subject to “global settlements” with the EPA under the National Petroleum Refining Initiative, before they were acquired by us. In return for agreeing to the consent decree and implementing the reductions in emissions that it specifies, the refineries secured broad releases of liability that provide immunity from enforcement actions for alleged past non-compliance under each of the Clean Air Act programs covered by the Consent Decree. The major project for consent decree compliance for the Krotz Springs refinery is installing NOx controls and monitors on heaters and boilers which is scheduled to be completed in 2011. Other projects include SO2 and NOx reduction measures from the FCCU. The current estimated capital cost is $13.0 million. If we are unable to meet the agreed upon reductions without add-on controls, our capital costs could increase. The Krotz Springs refinery has completed many portions of the consent decree including compliance with particulate emissions from the FCCU, H2S in the fuel gas, flare operating requirements, Leak Detection and Repair and Benzene Waste Operations NESHAPs program enhancements. Because the Krotz Springs refinery remains subject to the Valero consent decree, we entered into an agreement with Valero at the time of the acquisition allocating responsibilities under the consent decree. We are responsible for implementing only those portions of the consent decree that are specifically and uniquely applicable to the Krotz Springs refinery. In addition, with respect to certain system-wide emission limitations that apply across all of the Valero refineries, the Krotz Springs refinery was generally allocated emission limitations that did not necessitate substantial capital expenditures for add-on controls.
     The Bakersfield refinery became subject to a global settlement with the EPA in 2001. Currently, the only continuing requirements are periodic audits of its Leak Detection and Repair program and enhanced sampling and reporting under the Benzene Waste Operations NESHAP. As part of the global settlement, the Bakersfield refinery was required to perform an evaluation of and has accepted subpart J applicability for two of its pre-1973 flares. System modifications may be needed to comply with emission limits. The costs of any such modifications are unknown at this time. The compliance date has been proposed as January 1, 2017, coincident with the compliance date in local flare Rule 4311.
     On May 13, 2010, we received a Clean Air Act, Section 114 request for information from the EPA related to sources at the Big Spring refinery that operate under a “flexible permit” issued by the Texas Commission on Environmental Quality (“TCEQ”). On July 15, 2010, the EPA disapproved Texas’ “flexible permit” program and contends that sources operating under a flexible permit are not properly permitted and are subject to enforcement. We responded to the EPA’s request for information on June 18, 2010 and July 21, 2010. On September 20, 2010 and December 2, 2010, the EPA sent “opportunity to confer” letters to us requesting that we explain our plans to transition to a non-flexible permit and asking us to commit to obtaining a non-flexible permit under an EPA approved permitting program within a specified timeframe and through a transparent process, which provides opportunities for the EPA and third parties to comment. On December 22, 2010 and January 12, 2011, we agreed to make a federally enforceable commitment by March 31, 2011, to apply for a non-flexible permit. The Big Spring refinery is one of over one hundred regulated facilities in Texas that will be required to obtain a new, non-flexible permit.
     In May 2009, the EPA conducted an inspection of Big Spring refinery’s Risk Management Program (RMP) under Section 112r of the Clean Air Act. In March 2010, we received an inspection report describing findings and alleged violations of the RMP program at the refinery. On June 17, 2010, we responded by requesting additional information concerning other statements in the inspection report. On July 13, 2010, the EPA responded to our request. We have not received any further communication from the EPA concerning the RMP inspection.

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     Remediation Efforts. We are currently remediating historical soil and groundwater contamination at our Big Spring refinery pursuant to a compliance plan issued by the TCEQ and a RCRA Part B permit. The compliance plan and permit require us to investigate and, if necessary, remediate potentially contaminated areas on refinery property and also requires us to monitor and treat contaminated groundwater at the refinery and some of our terminals. To date, we have substantially completed the remediation of the potentially contaminated areas and continues to monitor and treat groundwater at the site. The costs incurred to comply with the compliance plan were covered, with certain limitations, by an environmental indemnity provided by FINA that covered remediation costs incurred for ten years after the July 2000 closing date and subject to a cap, which is discussed below. We are also remediating historical soil and groundwater contamination at the Hawley, South Lake, and Wichita Falls terminals that we acquired from FINA at the time of the refinery acquisition, which were also covered by the FINA indemnity.
     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 (“LARWQCB”). 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. Another project focuses on efforts at the Long Beach refinery, with the costs being shared with Apex Oil Co., the former owner of the Long Beach refinery. As part of our acquisition of Pipeline 145, we assumed an active remediation project designed to clean up a leak that occurred on this pipeline prior to our ownership. A fifth project was added in 2010 when two areas of release were found during a hydrotest of Pipeline 160, which transported gas oil and diesel. Both release areas are in the process of being remediated. The release in one area did not impact groundwater and will be remediated with excavation. The second release point did impact groundwater and will be remediated with LARWQCB oversight. Approximately $1.7 million was spent in 2010 for all of these remediation projects of which our portion was $1.1 million. We estimate that an additional $3.1 million will be spent in 2011 with our portion being approximately $2.2 million.
     With respect to the ongoing remediation program at our Long Beach refinery described in the preceding paragraph, in conjunction with our acquisition of the refinery, 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 refinery 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 $15.0 million and has a per occurrence deductible of $0.5 million.
     On March 1, 2005, our Paramount Petroleum Corporation subsidiary 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. Approximately $0.5 million was spent in 2010 for these remediation costs, of which our portion was $0.15 million, and we estimate that an additional $0.5 million will be spent during 2011, of which our portion will be $0.16 million.
     In addition, a majority of our owned and leased convenience stores have underground gasoline and diesel fuel storage tanks. Compliance with federal and state regulations that govern these storage tanks can be costly. The operation of underground storage tanks also poses various risks, including soil and groundwater contamination. We are currently investigating and remediating leaks from underground storage tanks at some of our convenience stores, and it is possible that we may identify more leaks or contamination in the future that could result in fines or civil liability for us. We have established reserves in our financial statements in respect of these matters to the extent that the associated costs are both probable and reasonably estimable. We cannot assure you, however, that these reserves will prove to be adequate.
     Environmental Indemnity from FINA. In connection with the acquisition of our Big Spring refinery and other operating assets from FINA in August 2000, FINA agreed, within prescribed limitations, to indemnify us against costs incurred in connection with any remediation that is required as a result of environmental conditions that existed on the acquired properties prior to the closing date of our acquisition. FINA’s indemnification obligations for these remediation costs ran through August 2010, had 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

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of December 31, 2010, the remediation of the properties was on schedule, and we had expended approximately $17.0 million in connection with that remediation and approximately $3.0 million in environmental insurance premiums, all of which were covered by the FINA indemnity.
     Environmental Insurance. We purchased two environmental insurance policies to cover expenditures not covered by the FINA indemnification agreement, the premiums for which have been paid 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 the Big Spring refinery. This policy has an initial retention of $20.0 million during the first ten years after the acquisition (coinciding with the FINA indemnity), which retention 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 insured 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 $100,000 per claim / $1.0 million aggregate sublimit on liability for civil fines and penalties and a retention of $150,000 per claim in the case of civil fines or penalties. Both the cost cap policy and ERCLIP have a term of twenty years and share a maximum aggregate limit 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 and is currently in run-off. However, we have no reason to believe at this time that Kemper will be unable to comply with its obligations under these policies. 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 equal to or in excess of the premiums paid for our policies with Kemper.
     Environmental Indemnity to HEP. In connection with our sale of pipelines and terminals to HEP, we entered into an Environmental Agreement 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 the sales or from violations of environmental laws with respect to the pipelines and terminals occurring prior to the sale. Our environmental indemnification obligations under the Environmental Agreement expire after February 2015. In addition, our indemnity obligations are subject to HEP first incurring $100,000 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 the date of sale, we have the option under the Environmental Agreement to perform such remediation ourselves in lieu of indemnifying HEP for their costs of performing such remediation. Pursuant to this option, we are continuing to perform the ongoing remediation at the Wichita Falls terminal. Any remediation required under the terms of the Environmental Agreement is limited to the standards under the applicable environmental laws as in effect at the date of sale.
     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 such date. 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. To date, Sunoco has not made any claims against us under the Purchase and Sale Agreement.
     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.

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     The California State Fire Marshall’s Office enforces federal pipeline regulations for pipelines in the State of California. We are 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 the regulations. We are also required to have a Pipeline Spill Response Plan for all California pipelines in our system which 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, and the Office of Spill Prevention and Response based on a worst case discharge. We have a Pipeline Spill Response Plan under which our California pipelines operate and believe that we are generally in substantial compliance with the California pipeline requirements.
     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 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 oil 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. Under the PMPA, 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 accordance with certain requirements of the PMPA, those distributors may file lawsuits against us to compel continuation of their contracts or to recover damages from us. We have not terminated or failed to renew distribution contracts with our branded distributors.
Employees
     As of December 31, 2010, we had approximately 2,821 employees. Approximately 723 employees worked in our refining and unbranded marketing segment, of which 628 were employed at our refineries and approximately 95 were employed at our corporate offices in Dallas, Texas. Approximately 122 employees worked in our asphalt segment and approximately 1,976 employees worked in our retail and branded marketing segment.
     Approximately 120 of the 170 employees at our Big Spring refinery are covered by collective bargaining agreements that expire on April 1, 2012. None of the employees in our asphalt, retail and branded marketing 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 Unbranded Marketing,” “Asphalt” and “Retail and Branded Marketing” in Item 1. We believe that our facilities are generally adequate for our operations and are maintained in a good state of repair in the ordinary course of business. As of December 31, 2010, we were the lessee under a number of cancelable and non-cancelable leases for certain properties. Our leases are discussed more fully in Note 21 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

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Executive Officers of the Registrant
     Our current executive officers and key employees (identified by an asterisk), their ages as of March 1, 2011, and their business experience during at least the past five years are set forth below.
             
Name   Age   Position
David Wiessman
    56     Executive Chairman of the Board of Directors
Jeff D. Morris
    59     Director and Chief Executive Officer
Paul Eisman
    55     President
Shai Even
    42     Senior Vice President and Chief Financial Officer
Joseph Israel
    39     Chief Operating Officer
Claire A. Hart
    55     Senior Vice President
Alan Moret
    56     Senior Vice President of Supply
Michael Oster
    39     Senior Vice President of Mergers and Acquisitions
Jimmy C. Crosby*
    51     Vice President of Refining — Big Spring
Ed Juno*
    58     Vice President of Refining — Paramount
William Wuensche*
    50     Vice President of Refining — Krotz Springs
William L. Thorpe*
    64     Vice President of Asphalt Operations
Kyle McKeen*
    47     President and Chief Executive Officer of Alon Brands
Joseph Lipman*
    65     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.
     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 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 Oil Company, Ltd., or Alon Israel, Alon’s parent company. 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 Executive Chairman of the Board of Directors of Alon Holdings Blue Square-Israel, Ltd., which is listed on the New York Stock Exchange, or NYSE, and the Tel Aviv Stock Exchange, or TASE; Executive Chairman of Blue Square Real Estate Ltd., which is listed on the TASE; and Executive Chairman of the Board and President of Dor-Alon Energy in Israel (1988) Ltd., which is listed on the TASE, and all of which are subsidiaries of Alon Israel.
     Jeff D. Morris has served as a director and as our Chief Executive Officer since May 2005 and has served as Chief Executive Officer of our other operating subsidiaries since July 2000. Mr. Morris also served as our President from May 2005 until March 2010 and President of our other operating subsidiaries from July 2000 until March 2010. Prior to joining Alon, he held various positions at FINA, Inc., where he began his career in 1974. Mr. Morris served as Vice President of FINA’s SouthEastern Business Unit from 1998 to 2000 and as Vice President of its SouthWestern Business Unit from 1995 to 1998. In these capacities, he was responsible for both the Big Spring refinery and FINA’s Port Arthur refinery and the crude oil gathering assets and marketing activities for both business units. Mr. Morris has also been a director of our subsidiary Alon Refining Krotz Springs, Inc. since 2008.
     Paul Eisman was appointed to serve as our President in March 2010. Prior to joining Alon, Mr. Eisman was Executive Vice President, Refining & Marketing Operations at Frontier Oil Corporation from 2006 to 2009 and held various positions at KBC Advanced Technologies from 2003 to 2006, including Vice President of North American Operations. During 2002, Mr. Eisman was Senior Vice President of Planning for Valero Energy Corporation following Valero’s acquisition of Ultramar Diamond Shamrock. Prior to the acquisition, Mr. Eisman had a 24-year career with Ultramar Diamond Shamrock, serving in many technical and operational roles including Executive Vice President of Corporate Development and Refinery Manager at the McKee refinery.
     Shai Even has served as a Senior Vice President since August 2008 and as our Chief Financial Officer since December 2004. Mr. Even served as a Vice President from May 2005 to August 2008 and Treasurer from August 2003 until March 2007. Shai Even is the brother of Shlomo Even, one of our directors.

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     Joseph Israel has served as our Chief Operating Officer since August 2008. Mr. Israel served as our Vice President of Mergers & Acquisitions from March 2005 to August 2008 and 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 1995, including the Israeli Land Administration, the Israeli Fuel Administration and most recently as Economics and Commerce Vice President of Israel’s Petroleum Energy Infrastructure entity.
     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.
     Alan Moret has served as our Senior Vice President of Supply since August 2008. Mr. Moret served as our Senior Vice President of Asphalt Operations from August 2006 to August 2008, 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.
     Michael Oster has served as our Senior Vice President of Mergers and Acquisitions of Alon Energy since August 2008 and General Manager of Commercial Transactions of Alon Energy from January 2003 to August 2008. Prior to joining Alon Energy, Mr. Oster was a partner in the Israeli law firm, Yehuda Raveh and Co.
     Jimmy C. Crosby has served as our Vice President of Refining — Big Spring since January 2010, as Vice President of Refining — California Refineries from March 2009 until January 2010, and as Vice President of Refining and Supply since May 2007, with responsibility for refinery and supply operations at our California refineries. Mr. Crosby served as our Vice President of Supply and Planning from May 2005 to May 2007, 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 May 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.
     Ed Juno has served as our Vice President of Refining — Paramount since January 2010. Prior to joining Alon, Mr. Juno has been employed in the refining industry for over 35 years, most recently with Sinclair Oil Corporation as Manager of Sinclair’s Wyoming refinery from 2008 to 2009 and as Operations Manager of the Wyoming refinery from 2003 to 2008.
     William Wuensche has served as our Vice President of Refining — Krotz Springs since March 2009, with responsibility for refinery operations at the Krotz Springs refinery. Mr. Wuensche joined Alon in July 2008 and from August 2008 to March 2009, Mr. Wuensche served as Vice President of Refining of Alon Refining Krotz Springs, Inc., our subsidiary conducting our refining operations at Krotz Springs. Prior to joining Alon, Mr. Wuensche was with Valero Refining Company-Louisiana from June 2006 to July 2008, as Vice President and General Manager of Valero’s Krotz Springs refinery and Valero Refining Company from February 2004 to June 2006, as Vice President and General Manager of Valero’s McKee Refinery. Earlier in his career, Mr. Wuensche held various positions of increasing responsibilities in the engineering, economics and planning and refinery operations areas.
     William L. Thorpe has served as Vice President of Asphalt Operations since August 2008, with responsibility over asphalt marketing and operations, quality control and quality assurance at our refineries and asphalt terminals and safety, security and training at our asphalt terminals. Mr. Thorpe served as the Vice President of Asphalt Marketing of our subsidiary, Paramount Petroleum Corporation, from August 2006 to August 2008. Prior to joining Alon, Mr. Thorpe was with Paramount Petroleum Corporation from 1996 to August 2006 having responsibility for marketing and operations, serving as Senior Vice President. Prior to joining Paramount Petroleum Corporation, Mr. Thorpe held management positions with various companies, including Vice President of Pacific Resources, Inc., Vice President — Sales and Marketing of Marlex Petroleum Corporation, Vice President — Marketing of Charter

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Oil Company and Manager — Transportation Planning and Development of ConocoPhillips. Mr. Thorpe has served as Vice-Chairman of the Board for the Asphalt Institute and the Asphalt Pavement Association of California and became Chairman of the Board of the Asphalt Institute beginning in 2010.
     Kyle McKeen has served as President and Chief Executive Officer of Alon Brands, Inc., our subsidiary that manages our retail and branded marketing operations, since May 2008. From 2005 to 2008, Mr. McKeen served as President and Chief Operating Officer of Carter Energy, an independent energy marketer supporting over 600 retailers by providing fuel supply, merchandising and marketing support, and consulting services. Prior to joining Carter Energy in 2005, Mr. McKeen was a member of the Board of Managers of Alon USA Interests, LLC from September 2002 to 2005 and held numerous positions of increasing responsibilities with Alon Energy, including Vice President of Marketing.
     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.
     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 an investment in any of our securities, you should consider carefully, among other things, the factors and the specific risks set forth below. This Annual Report on Form 10-K 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 primarily 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. When the margin between refined product prices and crude oil and other feedstock prices contracts or inverts, as has been the case in recent periods and may continue to be the case in the future, our results of operations and cash flows are negatively affected. 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. For example, in the last half of 2008, the price for West Texas Intermediate (“WTI”) crude oil fluctuated between $31.27 and $145.31 per barrel, while the price for Gulf Coast unleaded gasoline fluctuated between 76.8 cents per gallon, or cpg, and 474.6 cpg. The direction and timing of changes in prices for crude oil and refined products do not necessarily correlate with one another and it is the relationship between such prices, rather than the nominal amounts of such prices, that has the greatest impact on our results of operations and cash flows. Prices of crude oil, other feedstocks and refined products, and the relationships between such prices and prices for refined products, depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline, diesel, asphalt and other refined products and the relative magnitude and timing of such changes. 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, North and 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;
 
    commodities speculation;
 
    accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our refineries;
 
    federal and state government regulations; and
 
    local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our markets.
     Although we continually analyze refinery operating margins at our individual refineries and seek to adjust throughput volumes to optimize our operating results based on market conditions, there are inherent limitations on

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our ability to offset the effects of adverse market conditions. For example, reductions in throughput volumes in a negative operating margin environment may reduce operating losses, but it would not eliminate them because we would still be incurring fixed costs and other variable costs.
     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 last-in, first-out (“LIFO”) inventory valuation methodology. As a result, 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. Our investment in inventory is affected by the general level of crude oil prices, and significant increases in crude oil prices could result in substantial working capital requirements to maintain inventory volumes.
     In addition, the volatility in costs of natural gas, electricity and other utility services used by our refineries and other operations affect our operating costs. Utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for utility services in both local and regional markets. Future increases in utility prices may have a negative effect on our earnings, profitability and cash flows.
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 Big Spring and California 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, the sweet/sour spread has significantly narrowed and any further 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 2009, the light/heavy spread was less than in 2008 and the light/heavy spread fluctuated in 2010. Any further tightening of the light/heavy spread could negatively affect profitability.
Our indebtedness could adversely affect our financial condition or make us more vulnerable to adverse economic conditions.
     As of December 31, 2010, our consolidated outstanding indebtedness was $916.3 million. Our level of indebtedness could have significant effects on our business, financial condition and results of operations and cash flows and, consequently, important consequences to your investment in our securities, such as:
    we may be limited in our ability to obtain additional financing to fund our working capital needs, capital expenditures and debt service requirements or our other operational needs;
 
    we may be limited in our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our debt;
 
    we may be at a competitive disadvantage compared to competitors with less leverage since we may be less capable of responding to adverse economic and industry conditions; and
 
    we may not have sufficient flexibility to react to adverse changes in the economy, our business or the industries in which we operate.
     In addition, our ability to make payments on our indebtedness will depend on our ability to generate cash in the future. Our ability to generate cash is subject to general economic and market conditions and financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will

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generate sufficient cash to fund our working capital, capital expenditure, debt service and other liquidity needs, which could result in our inability to comply with financial and other covenants contained in our debt agreements, our being unable to repay or pay interest on our indebtedness, and our inability to fund our other liquidity needs. If we are unable to service our debt obligations, fund our other liquidity needs and maintain compliance with our financial and other covenants, we could be forced to curtail our operations, our creditors could accelerate our indebtedness and exercise other remedies and we could be required to pursue one or more alternative strategies, such as selling assets or refinancing or restructuring our indebtedness. However, we cannot assure you that any such alternatives would be feasible or prove adequate.
The recent recession and credit crisis and related turmoil in the global financial system has had and may continue to have an adverse impact on our business, results of operations and cash flows.
     Our business and profitability are affected by the overall level of demand for our products, which in turn is affected by factors such as overall levels of economic activity and business and consumer confidence and spending. Recent declines in global economic activity and consumer and business confidence and spending have significantly reduced the level of demand for our products. In addition, severe reductions in the availability and increases in the cost of credit have adversely affected our ability to fund our operations and operate our refineries at full capacity, and have adversely affected our operating margins. Together, these factors have had and may continue to have an adverse impact on our business, financial condition, results of operations and cash flows.
     Our business is indirectly exposed to risks faced by our suppliers, customers and other business partners. The impact on these constituencies of the risks posed by the recent recession and credit crisis and related turmoil in the global financial system have included or could include interruptions or delays in the performance by counterparties to our contracts, reductions and delays in customer purchases, delays in or the inability of customers to obtain financing to purchase our products and the inability of customers to pay for our products. Any of these events may have an adverse impact on our business, financial condition, results of operations and cash flows.
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. We experienced such an event on February 18, 2008 when a fire at the Big Spring refinery destroyed the propylene recovery unit and damaged equipment in the alkylation and gas concentration units. As a result the Big Spring refinery’s crude unit did not operate until April 5, 2008 and the FCCU did not resume operations until September 26, 2008.
     The occurrence of such events at any of our 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, hurricanes, 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.

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If the price of crude oil increases significantly, it could reduce our margin 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 margins from these sales could be adversely affected. For example, in the first half of 2008, WTI crude prices increased from $87.15 per barrel to $140.22 per barrel over a period of six months. Primarily as a result of these increases in the cost of crude, we experienced reduced margins from our asphalt sales in the first half of 2008.
Our operating results are seasonal and generally lower in the first and fourth quarters of the year.
     Demand for gasoline and asphalt products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. Seasonal fluctuations in highway traffic also affect motor fuels and merchandise sales in our retail stores. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. This seasonality is most pronounced in our asphalt business.
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 for our purchases or require us to post security prior to payment. 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 disruptions in operations and volatile market conditions, to offer more competitive pricing and to obtain crude oil in times of shortage.
     We are not engaged in the exploration and production business and therefore do not produce any of our crude oil feedstocks. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production. Competitors that have their own crude production are at times able to offset losses from refining operations with profits from producing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries, such as wind, solar and hydropower, that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual customers. If we are unable to compete effectively with these competitors, both within and outside our industry, there could be a material adverse effect on our business, financial condition, results of operations and cash flows.

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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 processes 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 addition, these retailers may use promotional pricing or discounts, both at the pump and in the store, to encourage in-store merchandise sales. These activities by our competitors could adversely affect our profit margins. Additionally, our convenience stores could lose market share, relating to both gasoline and merchandise, to these and other retailers, which could adversely affect our 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. 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 United States Environmental Protection Agency, or EPA, under the National Petroleum Refinery Initiative. To date, the EPA has not made any specific findings against us or any of our refineries, 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 costs of any required controls or environmentally beneficial projects.
     Our Big Spring refinery is one of more than 100 facilities in Texas to receive a Clean Air Act request for information from the EPA relating to the EPA’s disapproval of Texas’ “flexible permit rule.” According to the EPA, the Texas “flexible permit rule” was never approved by the EPA for inclusion in the Texas state clean-air implementation plan and, therefore, emission limitations in Texas flexible permits are not federally enforceable. The EPA indicated that it would consider enforcement against holders of flexible permits that failed to comply with applicable federal requirements on a case-by-case basis. At this time, we have agreed to make a federally enforceable commitment by March 31, 2011 to apply for a non-flexible permit. It is unclear whether we will have any obligation to install new controls.

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     The U.S. House of Representatives and the U.S. Senate are in various stages of considering legislation intended to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States. GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes.
     Although it is not possible at this time to predict when the House and Senate may enact climate change legislation, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased costs. If we are unable to sell our refined products at a price that reflects such increased costs, there could be a material adverse effect on our business, financial condition and results of operations. In addition, any increase in prices of refined products resulting from such increased costs could have an adverse effect on our financial condition, results of operations and cash flows.
     In addition to the climate change legislation under consideration by Congress, on December 7, 2009, the EPA issued an endangerment finding that GHGs endanger both public health and welfare, and that GHG emissions from motor vehicles contribute to the threat of climate change. Although the finding itself does not impose requirements on regulated entities, it allowed the EPA and the Department of Transportation to finalize a jointly proposed rule regulating greenhouse gas emissions from vehicles and establishing Corporate Average Fuel Economy standards for light-duty vehicles. National GHG tailpipe standards for passenger cars and light trucks were finalized on April 1, 2010.
     Once GHGs became regulated by the EPA for vehicles, they also became regulated pollutants under the Clean Air Act potentially triggering other Clean Air Act requirements. On May 13, 2010, EPA announced a final rule to raise the threshold amount of GHG emissions that a source would have to emit to trigger certain Clean Air Act permitting requirements and the need to install controls to reduce emissions of greenhouse gases. Beginning in January 2011, facilities already subject to the Prevention of Significant Deterioration and Title V operating permit programs that increase their emissions of GHGs by 75,000 tons per year will be required to install control technology, known as “Best Available Control Technology,” to address the GHG emissions. Both the endangerment finding and stationary source rule are being challenged, however. If the EPA’s actions withstand legal challenge, the new obligations finalized in the stationary source rule could require us to incur increased costs. If we are unable to sell our refined products at a price that captures such increased costs, there could be a material adverse effect on our business, financial condition and results of operations. In addition, any increase in prices of refined products resulting from such increased costs could have an adverse effect on our financial condition, results of operations and cash flows.
     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 refineries, terminals and convenience stores. Since August 2000, we have spent approximately $20.0 million with respect to the investigation and remediation of our Big Spring refinery and related terminals. We anticipate spending approximately $7.5 million in investigation and remediation expenses in connection with our Big Spring refinery and terminals over the next 15 years. Since their acquisition, we have spent approximately $9.1 million with respect to the investigation and remediation of our California refineries and related terminals. We anticipate spending an additional $40.5 million in investigation and remediation expenses in connection with our California refineries and terminals over the next 15 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

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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 to HEP and two of our pipelines pursuant to a transaction with an affiliate of Sunoco, Inc. (“Sunoco”), we have agreed, subject to certain limitations, to indemnify HEP and Sunoco for costs and liabilities that may be incurred by them as a result of environmental conditions existing at the time of the sale. See Items 1 and 2 “Business and Properties—Government Regulation and Legislation—Environmental Indemnity to HEP” and “Business and Properties—Government Regulation and Legislation—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, cash flows or prospects.
We could encounter significant opposition to operations at our California refineries.
     Our Paramount refinery is located in a residential area. The refinery is located near schools, apartment complexes, private homes and shopping establishments. In addition, our Long Beach refinery is also located in close proximity to other commercial facilities. Any loss of community support for our California 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 California refineries could have a material adverse effect on our business, results of operations and cash flows.
The occurrence of a release of hazardous materials or a catastrophic event affecting our California refineries could endanger persons living nearby.
     Because our California refineries are located in residential areas, any release of hazardous material or catastrophic event could cause injuries to persons outside the confines of these refineries. In the event that persons were injured as a result of such an event, we would likely incur substantial legal costs as well as any costs resulting from settlements or adjudication of claims from such injured persons. The extent of these 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.
Certain of our facilities are located in areas that have a history of earthquakes or hurricanes, 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. Our Krotz Springs refinery is located less than 100 miles from the Gulf Coast. In August 2008, the Krotz Springs refinery sustained minor physical damage from Hurricane Gustav; however, the regional utilities were affected and, as a result, the Krotz Springs refinery was without electric power for one week. Offshore crude oil production and gathering facilities were impacted by Gustav and a subsequent storm, which temporarily limited the availability of crude oil to the Krotz Springs refinery. In the event of an earthquake or hurricane that causes damage to our refining, pipeline or asphalt terminal assets, or the infrastructure necessary for the operation of these assets,

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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 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.
Covenants in our credit agreements 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 prohibited or limited by our credit agreements, we will need to obtain the consent of our lenders or refinance our credit facilities. Such consents or 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 a period of 45 to 75 days, depending upon the specific policy. 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 the insurer of our environmental policies.
     The insurer under two of our environmental policies is The Kemper Insurance Companies, which has experienced significant downgrades of its credit ratings in recent years and is currently in run-off. These two policies are 20-year policies that were purchased to protect us against expenditures not covered by our indemnification agreement with FINA. Our insurance brokers have advised us that environmental insurance policies with terms in excess of ten years are not currently available and that policies with shorter terms are available only at premiums equal to or 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, at premiums equal to or in excess of our current premiums with Kemper. However, we have no reason at this time to believe that Kemper will not be able to comply with its obligations under these policies.

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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 Big Spring refinery’s workforce is unionized, and we may face labor disruptions that would interfere with our operations.
     As of December 31, 2010, 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 April 1, 2012. Our current labor agreement may not prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse effect 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 and branded marketing segment.
     Our convenience store operations are primarily conducted under the 7-Eleven name pursuant to a license agreement between 7-Eleven, Inc. and Alon. 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 and products used exclusively by 7-Eleven. Termination of the license agreement could have a material adverse effect on our retail 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.

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     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, cash flows, the terms of their indebtedness, tax considerations and legal restrictions. Three of our executive officers, Messrs. Morris, Hart and Concienne, own shares of nonvoting stock of two of our subsidiaries, Alon Assets, Inc., or Alon Assets, and Alon USA Operating, Inc., or Alon Operating. As of December 31, 2010, the shares owned by these executive officers represent 6.32% 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 6.54% 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 “Security Ownership of Certain Beneficial Owners and Management.” 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 Holders and Management.”
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 in Israel. 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.   RESERVED.

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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES 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 within the two most recently completed fiscal years:
                 
Quarterly Period   High     Low  
2010
               
Fourth Quarter
  $ 6.13     $ 5.16  
Third Quarter
    6.99       4.77  
Second Quarter
    7.92       6.04  
First Quarter
    8.08       6.52  
2009
               
Fourth Quarter
  $ 10.18     $ 6.60  
Third Quarter
    11.20       8.20  
Second Quarter
    15.90       9.92  
First Quarter
    15.46       8.76  
Holders
     As of March 1, 2011, there were approximately 26 common stockholders of record.
Dividends
     On April 2, 2009, 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 non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.144 million.
     On June 15, 2009, 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 non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.144 million.
     On September 15, 2009, 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 non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.144 million.
     On December 15, 2009, 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 non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.144 million.
     On March 31, 2010, we paid a regular quarterly cash dividend of $0.04 per share. In connection with our cash dividend payment to stockholders, the non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.144 million.
     On June 15, 2010, 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 non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.285 million.

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     On September 15, 2010, 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 non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.164 million.
     On December 15, 2010, we paid a regular quarterly cash dividend of $0.04 per share of our common stock.
     We intend to continue to pay quarterly cash dividends on our common stock at an annual rate of $0.16 per share. However, 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, the terms of our preferred stock and other factors our board of directors deems relevant.
Recent Sales of Unregistered Securities
     Alon has entered into unregistered sales of equity securities as described in Item 9B of this Form 10-K.
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 cumulative five year period from January 3, 2006 to December 31, 2010, assuming an initial investment of $100 dollars and the reinvestment of all dividends, if any. The “Peer Group” includes Frontier Oil Corporation, Tesoro Petroleum Corp. and Valero Energy Corporation.
(LINE GRAPH)

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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 consolidated statement of cash flows data for the years ended December 31, 2007 and 2006, and the selected consolidated balance sheet data as of December 31, 2008, 2007 and 2006 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 consolidated statement of cash flows data for the years ended December 31, 2010, 2009 and 2008, and the selected consolidated balance sheet data as of December 31, 2010 and 2009, are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
     Our financial statements include the results of the Krotz Springs refining business from July 1, 2008. As a result of this transaction, the financial and operating data for periods prior to the effective date of this transaction may not be comparable to the data for the years ended December 31, 2010, 2009 and 2008.
     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,  
    2010     2009     2008     2007     2006  
            (dollars in thousands, except per share data)          
STATEMENT OF OPERATIONS DATA:
                                       
Net sales (1)
  $ 4,030,743     $ 3,915,732     $ 5,156,706     $ 4,542,151     $ 3,093,890  
Operating costs and expenses (1)
    4,192,469       3,994,977       5,258,153       4,363,238       2,877,811  
 
                             
Gain on involuntary conversion of assets (2)
                279,680              
Gain (loss) on disposition of assets (3)
    945       (1,591 )     45,244       7,206       63,255  
 
                             
Operating income (loss)
    (160,781 )     (80,836 )     223,477       186,119       279,334  
Net income (loss) available to common stockholders
    (122,932 )     (115,156 )     82,883       103,936       157,368  
 
                                       
Earnings (loss) per share, basic
  $ (2.27 )   $ (2.46 )   $ 1.77     $ 2.22     $ 3.37  
Weighted average shares outstanding, basic
    54,186       46,829       46,788       46,763       46,738  
Earnings (loss) per share, diluted
  $ (2.27 )   $ (2.46 )   $ 1.72     $ 2.16     $ 3.36  
Weighted average shares outstanding, diluted
    54,186       46,829       49,583       46,804       46,779  
Cash dividends per common share
    0.16       0.16       0.16       0.16       3.03  
 
                                       
CASH FLOW DATA:
                                       
Net cash provided by (used in):
                                       
Operating activities
  $ 21,330     $ 283,145     $ (812 )   $ 123,950     $ 142,977  
Investing activities
    (40,925 )     (138,691 )     (610,322 )     (147,254 )     (421,070 )
Financing activities
    50,845       (122,471 )     560,973       27,753       205,439  
 
                                       
BALANCE SHEET DATA:
                                       
Cash and cash equivalents and short-term investments
  $ 71,687     $ 40,437     $ 18,454     $ 95,911     $ 64,166  
Working capital
    990       84,257       250,384       279,580       228,779  
Total assets
    2,088,521       2,132,789       2,413,433       1,581,386       1,408,785  
Total debt
    916,305       937,024       1,103,569       536,615       498,669  
Total equity
    341,767       431,918       536,867       403,922       299,862  

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(1)   Our buy/sell arrangements involve linked purchases and sales related to refined product contracts entered into to address location, quality or grade requirements. These buy/sell transactions are included on a net basis in net sales in the consolidated statements of operations and profits are recognized when the exchanged product is sold. See Note 2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
 
(2)   Gain on involuntary conversion of assets reported in 2008 of $279.7 million represents the insurance proceeds received as a result of the Big Spring refinery fire in excess of the book value of the assets impaired of $25.3 million and demolition and repair expenses of $25.0 million incurred through December 31, 2008.
 
(3)   Gain on disposition of assets reported in 2008 primarily reflects the recognition of all the remaining deferred gain associated with the HEP transaction due to the termination of an indemnification agreement with HEP. Gain on disposition of assets reported in 2007 reflects the recognition of $7.2 million deferred gain recorded primarily in connection with the HEP transaction. Gain on disposition of assets reported in 2006 reflects the $52.5 million 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.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
     The following discussion of our financial condition and results of operations is provided as a supplement to, and should be read in conjunction with, our consolidated financial statements and the notes thereto included elsewhere in this Annual Report on Form 10-K and the other sections of this Annual Report on Form 10-K, including Items 1 and 2 “Business and Properties,” and Item 6 “Selected Financial Data.”
Forward-Looking Statements
     Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.
     Forward-looking statements reflect our current expectations regarding future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows. See Item 1A “Risk Factors.”
     Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:
    changes in general economic conditions and capital markets;
 
    changes in the underlying demand for our products;
 
    the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;
 
    changes in the sweet/sour spread;
 
    changes in the light/heavy spread;
 
    changes in the spread between West Texas Intermediate crude oil and Light Louisiana and Heavy Louisiana Sweet crude oils;
 
    the effects of transactions involving forward contracts and derivative instruments;
 
    actions of customers and competitors;
 
    changes in fuel and utility costs incurred by our facilities;
 
    disruptions due to equipment interruption, pipeline disruptions or failure at our or third-party facilities;
 
    the execution of planned capital projects;
 
    adverse changes in the credit ratings assigned to our trade credit and debt instruments;
 
    the effects of and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;

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    operating hazards, natural disasters, casualty losses and other matters beyond our control;
 
    realization of synergies and accretion to reported earnings from our acquisition of the Bakersfield refinery;
 
    integration of the operations and employees of the Bakersfield refinery and the timing of such integration;
 
    the global financial crisis’ impact on our business and financial condition; and
 
    the other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2010 under the caption “Risk Factors.”
     Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.
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 crude oil refineries are located in Texas, California, Oregon and Louisiana and have a combined throughput capacity of approximately 250,000 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.
     Refining and Unbranded Marketing Segment. Our refining and unbranded marketing segment includes sour and heavy crude oil refineries that are located in Big Spring, Texas; and Paramount, Bakersfield and Long Beach, California; and a light sweet crude oil refinery located in Krotz Springs, Louisiana. We refer to the Paramount, Bakersfield and Long Beach refineries together as our “California refineries.” The refineries in our refining and unbranded marketing segment have a combined throughput capacity of approximately 240,000 bpd. At our refineries we refine crude oil into petroleum products, including gasoline, diesel fuel, jet fuel, petrochemicals, feedstocks and asphalts, which are marketed primarily in the South Central, Southwestern, and Western United States.
     We market transportation fuels 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 retail and branded marketing segment convenience stores 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.
     We market refined products produced from our California refineries to wholesale distributors, other refiners and third parties primarily on the West Coast. We plan to integrate the Bakersfield hydrocracker unit by processing vacuum gas oil produced at our other California refineries.
     The Krotz Springs refinery processing units are structured to yield approximately 101.5% of total feedstock input, meaning that for each 100 barrels of crude oil and feedstocks input into the refinery, it produces 101.5 barrels of refined products. Of the 101.5%, on average 99.0% is light finished products such as gasoline and distillates, including diesel and jet fuel, petrochemical feedstocks and liquefied petroleum gas, and the remaining 2.5% is primarily heavy oils. We market refined products from Krotz Springs to wholesale distributors, other refiners, and third parties. The refinery’s location provides access to upriver markets on the Mississippi and Ohio Rivers and its docking facilities along the Atchafalaya River allow barge access. The refinery also uses its direct access to the Colonial Pipeline to transport products to markets in the Southern and Eastern United States.
     Asphalt Segment. Our asphalt segment markets asphalt produced at our Big Spring and California refineries included in the refining and marketing segment and at our Willbridge, Oregon refinery. Asphalt produced by the refineries in our refining and marketing segment is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. Our

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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), Arizona (Phoenix, Flagstaff and Fredonia) and Nevada (Fernley) (50% interest) as well as a 50% interest in Wright Asphalt Products Company, LLC (“Wright”). We produce both paving and roofing grades of asphalt, including performance-graded asphalts, emulsions and cutbacks.
     Retail and Branded Marketing Segment. Our retail and branded marketing segment operates 304 convenience stores primarily in Central and 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, primarily under the 7-Eleven and FINA brand names. Substantially all of the motor fuel sold through our retail operations and the majority of the motor fuel marketed in our branded business is supplied by our Big Spring refinery. In 2010, approximately 91% of the motor fuel requirements of our branded marketing operations, including retail operations, were supplied by our Big Spring refinery. Branded distributors that are not part of our integrated supply system, primarily in Central Texas, are supplied with motor fuels we obtain from third-party suppliers.
     We market gasoline and diesel under the FINA brand name through a network of approximately 630 locations, including our convenience stores. Approximately 63% of the gasoline and 22% of the diesel motor fuel produced at our Big Spring refinery was transferred to our retail and branded marketing segment at prices substantially determined by reference to commodity pricing information published by Platts. Additionally, our retail and branded marketing segment licenses the use of the FINA brand name and provides credit card processing services to approximately 260 licensed locations that are not under fuel supply agreements with us.
Summary of 2010 Developments
     In March 2010, Alon Refining Krotz Springs (“ARKS”) entered into a $65.0 million short-term credit facility with Bank Hapoalim B.M. The short-term credit facility as amended and restated matured on November 15, 2010 and was prepaid in full in October 2010. The proceeds of the short-term credit facility were used in part to prepay the ARKS revolving credit facility.
     In March 2010, ARKS terminated its revolving credit facility agreement and repaid all outstanding amounts thereunder. As a result of the prepayment of the ARKS revolving credit facility, a write-off of unamortized debt issuance costs of $6.7 million was recorded as interest expense in the first quarter of 2010.
     In April 2010, ARKS entered into a Supply and Offtake Agreement, which was amended on May 26, 2010 (the “Supply and Offtake Agreement”) with J. Aron & Company (“J. Aron”), the proceeds of which allowed ARKS to retire part of its obligations under its short-term credit facility and support the operation of the Krotz Springs refinery at a minimum of 72,000 barrels per day. Pursuant to the Supply and Offtake Agreement, (i) J. Aron agreed to sell to ARKS, and ARKS agreed to buy from J. Aron, at market price, crude oil for processing at the Krotz Springs refinery and (ii) ARKS agreed to sell, and J. Aron agreed to buy, at market price, certain refined products produced at the Krotz Springs refinery.
     In June 2010, we purchased a refinery in Bakersfield, California from Big West of California, LLC, a subsidiary of Flying J, Inc. The refinery is non-operational at this time and will require turnaround work and additional capital expenditures before it can be returned to operations and integrated with the other California refineries. In connection with the Bakersfield refinery acquisition, the acquisition date fair value of the identifiable net assets acquired exceeded the fair value of the consideration transferred, resulting in a $17.5 million bargain purchase gain.
     In October 2010, we completed a registered direct offering of our 8.5% Series A Convertible Preferred Stock for an aggregate offering price of $40.0 million before deducting offering expenses. We used $30.0 million of the proceeds from the offering to prepay in full the ARKS short-term credit facility in October 2010. Also in October 2010, we obtained $23.0 million of letters of credit outside our existing credit facilities.
     In December 2010, Southwest Convenience Stores, LLC (“SCS”) entered into an amended and restated retail credit facility agreement with Wells Fargo Bank. The facility amended and restated the original credit agreement, dated June 29, 2007, between SCS and Wachovia Bank, the predecessor to Wells Fargo Bank. The amendment to the original credit agreement reinstated the original facility size from $73.4 million to $93.4 million. The facility

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consists of the $73.4 million existing term loan, a $10.0 million additional term loan and $10.0 million of revolving credit capacity. At December 31, 2010, $93.4 million was outstanding under this facility.
2010 Operations Highlights
     Highlights for 2010 include:
    Combined refinery throughput in 2010 averaged 105,868 bpd, consisting of 49,028 bpd at the Big Spring refinery, 17,596 bpd at the California refineries, and 39,244 bpd at the Krotz Springs refinery compared to a combined average of 139,365 bpd for the same period last year, consisting of 59,870 bpd at the Big Spring refinery, 31,158 bpd at the California refineries, and 48,337 bpd at the Krotz Springs refinery.
 
    Operating margin at the Big Spring refinery was $6.03 per barrel in 2010, compared to $4.35 per barrel for the same period in 2009. Light product yields increased in 2010 due to the operation of substantially all refinery units that were damaged in the 2008 fire. Light product yields were approximately 89% in 2010, compared to 82% for the same period in 2009.
 
    Operating margin at the California refineries was $1.08 per barrel in 2010, compared to $1.83 per barrel for the same period in 2009. The operating margin decreased in 2010 due to decreased light product yields and a decrease in the West Coast 3/2/1 crack spread.
 
    Operating margin at the Krotz Springs refinery was $2.24 per barrel in 2010 compared to $5.66 per barrel for 2009. The lower Krotz Springs refinery operating margin is due primarily to operational effects of the extended turnaround and restart in June 2010 and a higher LLS to WTI spread.
 
    Gulf Coast 3/2/1 average crack spreads were $8.22 per barrel in 2010, compared to $7.24 per barrel for the same period in 2009. Gulf Coast 2/1/1 high sulfur diesel average crack spreads for the year ended December 31, 2010, was $7.75 per barrel compared to $6.50 per barrel for the same period in 2009. West Coast 3/2/1 average crack spreads for the year ended December 31, 2010, was $13.56 per barrel compared to $13.92 per barrel for the same period in 2009.
 
    The average sweet/sour spread for 2010 was $2.15 per barrel compared to $1.52 per barrel for the same period in 2009. The average light/heavy spread for 2010 was $9.14 per barrel compared to $5.46 per barrel for the same period in 2009. The average LLS to WTI spread for 2010 was $3.35 per barrel compared to $2.57 per barrel for the same period in 2009.
 
    Asphalt margins in 2010 averaged $51.06 per ton compared to an average of $46.07 per ton in 2009. The average blended asphalt sales price increased 16.4% from $409.88 per ton in 2009, to $477.26 per ton in 2010, and the average non-blended asphalt sales price increased 91.8% from $170.05 per ton in 2009 to $326.16 per ton in 2010. The blended asphalt sales accounted for 93% of total asphalt sales in 2010 compared to 92% for 2009.
 
    In our retail and branded marketing segment, retail fuel sales gallons increased by 17.8% from 120.7 million gallons for the year ended December 31, 2009, to 142.2 million gallons for the year ended December 31, 2010. Our branded fuel sales increased by 16.4% from 274.1 million gallons in 2009, to 318.9 million gallons for 2010.

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Major Influences on Results of Operations
     Refining and Unbranded Marketing. Our earnings and cash flow from our refining and unbranded marketing segment are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire crude oil and other feedstocks and the price of the refined products we ultimately sell depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, and not necessarily fluctuations in those prices that affect 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 ultra-low sulfur diesel and the market value of West Texas Intermediate, or WTI, a light, sweet crude oil. We calculate the Group III 3/2/1 crack spread using the market values of Group III conventional gasoline and ultra-low sulfur diesel and the market value of WTI crude oil. We calculate the per barrel operating margin for our Big Spring refinery by dividing the Big Spring refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales (exclusive of substantial unrealized hedge positions and inventory adjustments related to acquisitions).
     We compare our California refineries’ per barrel operating margin to the West Coast 3/2/1 crack spread. A 3/2/1 crack spread is calculated assuming that three barrels of a benchmark crude oil are converted into two barrels of gasoline and one barrel of diesel. This is calculated using the market values of West Coast LA CARBOB pipeline gasoline, LA ultra-low sulfur pipeline diesel and the market value of WTI crude oil.
     We compare our Krotz Springs refinery’s per barrel margin to the Gulf Coast 2/1/1 crack spread. The 2/1/1 crack spread is calculated assuming that two barrels of a benchmark crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate the Gulf Coast 2/1/1 crack spread using the market values of Gulf Coast conventional gasoline and Gulf Coast high sulfur diesel and the market value of WTI crude oil.
     Our Big Spring refinery and California refineries are 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 at our refineries by calculating the difference between the value of WTI crude oil less the value of West Texas Sour, or WTS, a medium, sour crude oil. We refer to this differential as the sweet/sour spread. A widening of the sweet/sour spread can favorably influence the operating margin for our Big Spring and California refineries. 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 WTI crude oil less the value of MAYA crude, which we refer to as the light/heavy spread. A widening of the light/heavy spread can favorably influence the refinery operating margins for our California refineries.
     The Krotz Springs refinery has the capability to process substantial volumes of low-sulfur, or sweet, crude oils to produce a high percentage of light, high-value refined products. Sweet crude oil typically comprises 100% of the Krotz Springs refinery’s crude oil input. This input is comprised of equal amounts of Heavy Louisiana Sweet, or HLS crude oil, and Light Louisiana Sweet, or LLS crude oil. We measure the cost of refining these lighter sweet crude oils by calculating the difference between the average value of LLS crude oil (which also approximates the value of HLS crude oil) to the average value of WTI crude oil. A narrowing of this spread can favorably influence the refinery operating margins of our Krotz Springs refinery.
     The results of operations from our refining and unbranded 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. Typically, electricity prices fluctuate with natural gas prices.

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     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 unbranded 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 refineries 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. Crude oil and refined products are essentially commodities, and 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 transfer prices for asphalt produced at our refineries in the refining and unbranded marketing segment. Asphalt is transferred to our asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. The asphalt segment also conducts operations at and markets asphalt produced by our refinery located in Willbridge, Oregon. In addition to producing asphalt at our refineries, at times when refining margins are unfavorable we opportunistically purchase asphalt from other producers for resale. A portion of our asphalt sales are made using fixed price contracts for delivery of asphalt products at future dates. Because these contracts are priced at the market prices for asphalt at the time of the contract, a change 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 revenues 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 and Branded Marketing. Our earnings and cash flows from our retail and branded marketing segment are primarily affected by merchandise and motor fuel sales and margins at our convenience stores and the motor fuel sales volumes and margins from sales to our FINA-branded distributors, together with licensing and credit card related fees generated from our FINA-branded distributors and licensees. Retail merchandise gross margin is equal to retail merchandise sales less the delivered cost of the retail merchandise, net of vendor discounts and rebates, measured as a percentage of total retail merchandise sales. Retail merchandise sales are driven by convenience, branding and competitive pricing. Motor fuel margin is equal to motor fuel sales less the delivered cost of fuel and motor fuel taxes, measured on a cents per gallon (“cpg”) basis. Our motor fuel margins are driven by local supply, demand and competitor pricing. Our convenience store 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, 2010 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.

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Big Spring Refinery Fire
     On February 18, 2008, a fire at the Big Spring refinery destroyed the propylene recovery unit and damaged equipment in the alkylation and gas concentration units. On April 5, 2008, the refinery was able to begin partial operation in a 35,000 bpd hydroskimming mode. The major units brought back on line in April included the crude unit, reformer unit, distillate hydrotreater and jet fuel hydrotreater. The Fluid Catalytic Cracking Unit (“FCCU”) returned to normal operating capabilities with the restart on September 26, 2008. Substantially all of the repairs to the units damaged in the fire were completed in 2009 other than the alkylation unit which returned to operations in January 2010.
     For the year ended December 31, 2008, we recorded $56.9 million of non-reimbursable costs associated with the fire. The components of net costs associated with fire as of December 31, 2008 included: $51.1 million for expenses incurred from pipeline commitment deficiencies, crude sale losses and other incremental costs; $5.0 million for our third party liability insurance deductible under the insurance policy; and depreciation for the temporarily idled facilities of $0.8 million.
     An involuntary pre-tax gain on conversion of assets of $279.7 million was recorded for the insurance proceeds of $330.0 million received in excess of the book value of the assets impaired of $25.3 million and demolition and repair expenses of $25.0 million incurred through December 31, 2008. An additional $55.0 million of insurance proceeds were received in 2008 and January 2009 and this was recorded as business interruption recovery for the year ended December 31, 2008.
Refinery Acquisitions
     In June 2010, we purchased the Bakersfield, California refinery from Big West of California, LLC, a subsidiary of Flying J, Inc. The refinery is non-operational at this time and will require turnaround work and additional capital expenditures before it can be returned to operations and integrated with other California refineries. In connection with the Bakersfield refinery acquisition, the acquisition date fair value of the identifiable net assets acquired exceeded the fair value of the consideration transferred, resulting in a $17.5 million bargain purchase gain.
     In July 2008, we acquired the refining business located in Krotz Springs, Louisiana from Valero. The purchase price was $333.0 million in cash plus $141.5 million for working capital, including inventories. The Krotz Springs refinery, with a nameplate crude capacity of approximately 83,100 bpd, supplies multiple demand centers in the Southern and Eastern United States markets through a pipeline operated by the Colonial Pipeline. The purchase of the Krotz Springs refinery increased property, plant and equipment by $376.7 million, inventories by $145.0 million and debt by $141.5 million. The results of operations for the Krotz Springs refinery have been included in our consolidated statements of operations for the second half of the year ended December 31, 2008.
Unscheduled Turnaround and Reduced Crude Oil Throughput
     In an effort to match our safety, reliability and the environmental performance initiatives with the current operating margin environment, we accelerated a planned turnaround at our Krotz Springs refinery from the first quarter of 2010 to the fourth quarter of 2009. The refinery resumed operations in June 2010. Throughput at the Big Spring refinery was lower during 2010, as we implemented new operating procedures. The California refineries’ throughput was lower during 2010, due to continued efforts to optimize asphalt production with demand and as a result of the shutdown in December 2010 to redeploy resources for the integration of the Bakersfield refinery acquired in June 2010.
Hurricane Activity
     The aftermath of Hurricanes Gustav and Ike in the third quarter of 2008 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. Hurricane Gustav directly affected our refinery in Krotz Springs, Louisiana causing power outages and crude oil supply disruption.

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HEP Transaction
     A gain on disposition of assets of $42.9 million in the second quarter of 2008 represented the recognition of all the remaining deferred gain associated with the contribution of certain pipelines and terminals to Holly Energy Partners, LP (“HEP”), in March 2005 and was due to the termination of an indemnification agreement with HEP.
Results of Operations
     Net Sales. Net sales consist primarily of sales of refined petroleum products through our refining and unbranded marketing segment and asphalt segment and sales of merchandise, including food products, and motor fuels, through our retail and branded marketing segment.
     For the refining and unbranded marketing segment, net sales consist of gross sales, net of customer rebates, discounts and excise taxes. Net sales for our refining and unbranded marketing segment include intersegment sales to our asphalt and retail and branded marketing segments, which are eliminated through consolidation of our financial statements. Asphalt sales consist of gross sales, net of any discounts and applicable taxes. 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 mainly affected by crude oil and refined product prices and volume changes caused by operations. Our retail merchandise sales are affected primarily by competition and seasonal influences.
     Cost of Sales. Refining and unbranded 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 unbranded 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, 2010, 2009 and 2008. 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,  
    2010     2009     2008  
    (dollars in thousands, except per share data)  
STATEMENT OF OPERATIONS DATA:
                       
Net sales (1)
  $ 4,030,743     $ 3,915,732     $ 5,156,706  
Operating costs and expenses:
                       
Cost of sales
    3,703,416       3,502,782       4,853,195  
Direct operating expenses
    249,933       265,502       216,498  
Selling, general and administrative expenses (2)
    128,082       129,446       119,852  
Unrealized loss associated with consignment inventory (3)
    8,942              
Net costs associated with fire (4)
                56,854  
Business interruption recovery (5)
                (55,000 )
Depreciation and amortization (6)
    102,096       97,247       66,754  
 
                 
Total operating costs and expenses
    4,192,469       3,994,977       5,258,153  
 
                 
Gain on involuntary conversion of assets (7)
                279,680  
Gain (loss) on disposition of assets (8)
    945       (1,591 )     45,244  
 
                 
Operating income (loss)
    (160,781 )     (80,836 )     223,477  
Interest expense (9)
    (94,939 )     (111,137 )     (67,550 )
Equity earnings (losses) of investees
    5,439       24,558       (1,522 )
Gain on bargain purchase (10)
    17,480              
Other income, net
    9,716       331       1,500  
 
                 
Income (loss) before income tax expense (benefit), non-controlling interest in income (loss) of subsidiaries and accumulated dividends on preferred stock of subsidiary
    (223,085 )     (167,084 )     155,905  
Income tax expense (benefit)
    (90,512 )     (64,877 )     62,781  
 
                 
Income (loss) before non-controlling interest in income (loss) of subsidiaries and accumulated dividends on preferred stock of subsidiary
    (132,573 )     (102,207 )     93,124  
Non-controlling interest in income (loss) of subsidiaries
    (9,641 )     (8,551 )     5,941  
Accumulated dividends on preferred stock of subsidiary (11)
          21,500       4,300  
 
                 
Net income (loss) available to common stockholders
  $ (122,932 )   $ (115,156 )   $ 82,883  
 
                 
 
                       
Earnings (loss) per share, basic
  $ (2.27 )   $ (2.46 )   $ 1.77  
Weighted average shares outstanding, basic (in thousands)
    54,186       46,829       46,788  
Earnings (loss) per share, diluted
  $ (2.27 )   $ (2.46 )   $ 1.72  
Weighted average shares outstanding, diluted (in thousands)
    54,186       46,829       49,583  
Cash dividends per share
  $ 0.16     $ 0.16     $ 0.16  
 
                       
CASH FLOW DATA:
                       
Net cash provided by (used in):
                       
Operating activities
  $ 21,330     $ 283,145     $ (812 )
Investing activities
    (40,925 )     (138,691 )     (610,322 )
Financing activities
    50,845       (122,471 )     560,973  
 
                       
BALANCE SHEET DATA (end of period):
                       
Cash and cash equivalents
  $ 71,687     $ 40,437     $ 18,454  
Working capital
    990       84,257       250,384  
Total assets
    2,088,521       2,132,789       2,413,433  
Total debt
    916,305       937,024       1,103,569  
Total equity
    341,767       431,918       536,867  
 
                       
OTHER DATA:
                       
Adjusted EBITDA (12)
  $ (44,475 )   $ 42,891     $ 244,965  
Capital expenditures (13)
    46,707       81,660       62,356  
Capital expenditures to rebuild the Big Spring refinery
          46,769       362,178  
Capital expenditures for turnaround and chemical catalyst
    13,131       24,699       9,958  

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(1)   Includes excise taxes on sales by the retail and branded marketing segment of $54.9 million, $47.1 million and $37.5 million for the years ended December 31, 2010, 2009 and 2008, respectively.
 
(2)   Includes corporate headquarters selling, general and administrative expenses of $0.8 million, $0.8 million and $0.6 million for the years ended December 31, 2010, 2009 and 2008, respectively, which are not allocated to our three operating segments.
 
(3)   Unrealized loss associated with consignment inventory for the year ended December 31, 2010, is a mark-to-market adjustment for the associated consigned inventory liabilities. Crude oil consignment inventory represents inventory located at storage facilities that was sold to third parties with an obligation by us to repurchase the inventory at then prevailing market prices when the respective agreements end. At December 31, 2010, we had 0.7 million barrels of crude oil inventory consigned to others with a market value of $59.5 million.
 
(4)   Includes $51.1 million of expenses incurred from pipeline commitment deficiencies, crude sale losses and other incremental costs; $5.0 million for our third party liability insurance deductible under the insurance policy; and depreciation for the temporarily idled facilities of $0.8 million for the year ended December 31, 2008.
 
(5)   Business interruption recovery of $55.0 million was recorded for the year ended December 31, 2008 as a result of the Big Spring refinery fire with all insurance proceeds received in 2008 and January 2009.
 
(6)   Includes corporate depreciation and amortization of $1.4 million, $0.7 million and $0.9 million for the years ended December 31, 2010, 2009 and 2008, respectively, which are not allocated to our three operating segments.
 
(7)   A gain on involuntary conversion of assets of $279.7 million has been recorded for the insurance proceeds received in excess of the book value of the assets impaired of $25.3 million and demolition and repair expenses of $25.0 million incurred through December 31, 2008 as a result of the Big Spring refinery fire.
 
(8)   Gain on disposition of assets reported in 2008 primarily includes the recognition of deferred gain recorded in connection with the contribution of certain product pipelines and terminals to Holly Energy Partners, LP, (“HEP”), in March 2005 (“HEP transaction”). A recognized gain of $42.9 million represented all the remaining deferred gain associated with the HEP transaction and was due to the termination of an indemnification agreement with HEP.
 
(9)   Interest expense for the year ended December 31, 2010 includes a charge of $6.7 million for the write-off of debt issuance costs associated with our prepayment of the ARKS revolving credit facility. Interest expense for the year ended December 31, 2009, includes $20.5 million of unamortized debt issuance costs written off as a result of prepayments of $163.8 million of term debt in October 2009. Interest expense for 2009 also includes $5.7 million related to the liquidation of the heating oil hedge in the second quarter of 2009.
 
(10)   In connection with the Bakersfield refinery acquisition, the acquisition date fair value of the identifiable net assets acquired exceeded the fair value of the consideration transferred, resulting in a $17.5 million bargain purchase gain.
 
(11)   Accumulated dividends on preferred stock of subsidiary for year ended December 31, 2009, represent dividends of $12.9 million for the conversion of the preferred stock into Alon common stock. Also included for the year ended December 31, 2009, is $8.6 million of accumulated dividends through December 31, 2009.
 
(12)   See “— Reconciliation of Amounts Reported Under Generally Accepted Accounting Principles” for information regarding our definition of Adjusted EBITDA, its limitations as an analytical tool and a reconciliation of net income (loss) available to common stockholders to Adjusted EBITDA for the periods presented.
 
(13)   Includes corporate capital expenditures of $2.3 million, $3.7 million and $1.2 million for the years ended December 31, 2010, 2009 and 2008, respectively, which are not allocated to our three operating segments.

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REFINING AND UNBRANDED MARKETING SEGMENT
                         
    Year Ended December 31,  
    2010     2009     2008  
    (dollars in thousands, except per barrel data and  
            pricing statistics)          
STATEMENT OF OPERATIONS DATA:
                       
Net sales (1)
  $ 3,454,115     $ 3,359,043     $ 4,551,769  
Operating costs and expenses:
                       
Cost of sales
    3,302,829       3,117,528       4,505,094  
Direct operating expenses
    205,838       221,378       173,142  
Selling, general and administrative expenses
    22,764       29,376       17,784  
Unrealized loss associated with consignment inventory (2)
    8,942              
Net costs associated with fire (3)
                56,854  
Business interruption recovery (4)
                (55,000 )
Depreciation and amortization
    80,401       76,252       50,047  
 
                 
Total operating costs and expenses
    3,620,774       3,444,534       4,747,921  
 
                 
Gain on involuntary conversion of assets (5)
                279,680  
Gain (loss) on disposition of assets (6)
    659       (1,042 )     45,244  
 
                 
Operating income (loss)
  $ (166,000 )   $ (86,533 )   $ 128,772  
 
                 
 
                       
KEY OPERATING STATISTICS AND OTHER DATA:
                       
Per barrel of throughput:
                       
Refinery operating margin — Big Spring (7)
  $ 6.03     $ 4.35     $ (3.18 )
Refinery operating margin — CA Refineries (7)
    1.08       1.83       1.65  
Refinery operating margin — Krotz Springs (7)
    2.24       5.66       7.25  
Refinery direct operating expense — Big Spring (8)
    5.06       4.21       4.40  
Refinery direct operating expense — CA Refineries (8)
    7.73       4.82       5.81  
Refinery direct operating expense — Krotz Springs (8)
    4.36       4.22       4.30  
Capital expenditures
    38,136       71,555       57,576  
Capital expenditures to rebuild the Big Spring refinery
          46,769       362,178  
Capital expenditures for turnaround and chemical catalyst
    13,131       24,699       9,958  
 
                       
PRICING STATISTICS:
                       
WTI crude oil (per barrel)
  $ 79.41     $ 61.82     $ 99.56  
WTS crude oil (per barrel)
    77.26       60.30       95.78  
MAYA crude oil (per barrel)
    70.27       56.36       83.93  
LLS crude oil (per barrel)
    82.76       64.39       102.24  
Crack spreads (3/2/1) (per barrel):
                       
Gulf Coast
  $ 8.22     $ 7.24     $ 10.47  
Group III
    9.49       8.10       11.15  
West Coast
    13.56       13.92       15.80  
Crack spreads (2/1/1) (per barrel):
                       
Gulf Coast high sulfur diesel
  $ 7.75     $ 6.50     $ 11.28  
Crude oil differentials (per barrel):
                       
WTI less WTS
  $ 2.15     $ 1.52     $ 3.78  
WTI less MAYA
    9.14       5.46       15.63  
LLS less WTI
    3.35       2.57       2.68  
Product price (dollars per gallon):
                       
Gulf Coast unleaded gasoline
    2.052       1.635       2.471  
Gulf Coast ultra-low sulfur diesel
    2.156       1.664       2.918  
Gulf Coast high sulfur diesel
    2.099       1.619       2.808  
Group III unleaded gasoline
    2.087       1.662       2.481  
Group III ultra-low sulfur diesel
    2.176       1.670       2.945  
West Coast LA CARBOB (unleaded gasoline)
    2.214       1.852       2.679  
West Coast LA ultra-low sulfur diesel
    2.212       1.706       2.883  
Natural gas (per MMBTU)
  $ 4.38     $ 4.16     $ 8.90  

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    Year Ended December 31,  
THROUGHPUT AND PRODUCTION DATA:   2010     2009     2008  
Big Spring refinery   bpd     %     bpd     %     bpd     %  
Refinery throughput:
                                               
Sour crude
    39,349       80.2       48,340       80.8       31,654       83.8  
Sweet crude
    7,288       14.9       9,238       15.4       4,270       11.3  
Blendstocks
    2,391       4.9       2,292       3.8       1,869       4.9  
 
                                   
Total refinery throughput (9)
    49,028       100.0       59,870       100.0       37,793       100.0  
 
                                   
 
                                               
Refinery production:
                                               
Gasoline
    24,625       50.7       26,826       45.0       14,266       38.4  
Diesel/jet
    15,869       32.7       19,136       32.2       10,439       28.2  
Asphalt
    2,827       5.8       5,289       8.9       4,850       13.1  
Petrochemicals
    2,939       6.0       2,928       4.9       1,221       3.3  
Other
    2,341       4.8       5,327       9.0       6,298       17.0  
 
                                   
Total refinery production (10)
    48,601       100.0       59,506       100.0       37,074       100.0  
 
                                   
 
                                               
Refinery utilization (11)
            68.2 %             82.3 %             52.3 %
                                                 
    Year Ended December 31,  
THROUGHPUT AND PRODUCTION DATA:   2010     2009     2008  
California refineries (A)   bpd     %     bpd     %     bpd     %  
Refinery throughput:
                                               
Medium sour crude
    3,502       19.9       13,408       43.0       8,014       25.8  
Heavy crude
    13,688       77.8       17,420       55.9       22,590       72.6  
Blendstocks
    406       2.3       330       1.1       495       1.6  
 
                                   
Total refinery throughput (9)
    17,596       100.0       31,158       100.0       31,099       100.0  
 
                                   
 
                                               
Refinery production:
                                               
Gasoline
    2,629       15.4       4,920       16.2       4,141       13.7  
Diesel/jet
    3,704       21.6       7,123       23.5       7,481       24.8  
Asphalt
    5,919       34.6       8,976       29.5       9,214       30.5  
Light unfinished
                117       0.4              
Heavy unfinished
    4,483       26.2       8,813       29.0       9,182       30.4  
Other
    372       2.2       418       1.4       192       0.6  
 
                                   
Total refinery production (10)
    17,107       100.0       30,367       100.0       30,210       100.0  
 
                                   
 
                                               
Refinery utilization (11)
            25.9 %             46.2 %             46.3 %
                                                 
    Year Ended December 31,  
THROUGHPUT AND PRODUCTION DATA:   2010     2009     2008  
Krotz Springs refinery (B)   bpd     %     bpd     %     bpd     %  
Refinery throughput:
                                               
Light sweet crude
    23,810       60.7       22,942       47.5       43,361       74.5  
Heavy sweet crude
    14,535       37.0       22,258       46.0       11,979       20.6  
Blendstocks
    899       2.3       3,137       6.5       2,844       4.9  
 
                                   
Total refinery throughput (9)
    39,244       100.0       48,337       100.0       58,184       100.0  
 
                                   
 
                                               
Refinery production:
                                               
Gasoline
    15,812       40.1       22,264       45.4       25,195       42.8  
Diesel/jet
    18,986       48.2       21,318       43.4       26,982       45.9  
Heavy oils
    1,515       3.8       1,238       2.5       1,402       2.4  
Other
    3,107       7.9       4,258       8.7       5,258       8.9  
 
                                   
Total refinery production (10)
    39,420       100.0       49,078       100.0       58,837       100.0  
 
                                   
 
                                               
Refinery utilization (11)
            46.1 %             65.3 %             66.6 %
 
(A)   The throughput data for the year ended December 31, 2010, reflects eleven months of throughput as the California refineries were shutdown in December to redeploy resources for the integration of the Bakersfield refinery acquired in June 2010.
 
(B)   The throughput data for the year ended December 31, 2010, reflects substantially seven months of operations beginning in June 2010 due to the restart of the Krotz Springs refinery after major turnaround activity. Throughput data for the year ended December 31, 2008 includes our Krotz Springs refinery for the period from July 1, 2008 through December 31, 2008.

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(1)   Net sales include intersegment sales to our asphalt and retail and branded marketing segments at prices which are intended to approximate wholesale market prices. These intersegment sales are eliminated through consolidation of our financial statements.
 
(2)   Unrealized loss associated with consignment inventory for the year ended December 31, 2010, is a mark-to-market adjustment for the associated consigned inventory liabilities. Crude oil consignment inventory represents inventory located at storage facilities that was sold to third parties with an obligation by us to repurchase the inventory at then prevailing market prices when the respective agreements end. At December 31, 2010, we had 0.7 million barrels of crude oil consigned to others with a market value of 59.5 million.
 
(3)   Includes $51.1 million of expenses incurred from pipeline commitment deficiencies, crude sale losses and other incremental costs; $5.0 million for our third party liability insurance deductible under the insurance policy; and depreciation for the temporarily idled facilities of $0.8 million for the year ended December 31, 2008.
 
(4)   Business interruption recovery of $55.0 million was recorded for the year ended December 31, 2008 as a result of the Big Spring refinery fire with all insurance proceeds being received in 2008 and January 2009.
 
(5)   A gain on involuntary conversion of assets of $279.7 million has been recorded for the insurance proceeds received in excess of the book value of the assets impaired of $25.3 million and demolition and repair expenses of $25.0 million incurred through December 31, 2008 as a result of the Big Spring refinery fire.
 
(6)   Gain on disposition of assets reported in 2008 primarily includes the recognition of deferred gain recorded in connection with the HEP transaction. A recognized gain of $42.9 million represented all the remaining deferred gain associated with the HEP transaction and was due to the termination of an indemnification agreement with HEP.
 
(7)   Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales (exclusive of substantial unrealized hedge positions and inventory adjustments related to acquisitions) attributable to each refinery by the 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 the year ended December 31, 2010, excludes a benefit of $4.5 million to cost of sales for inventory adjustments related to the Bakersfield refinery acquisition. There were unrealized hedging gains of $4.2 million for the year ended December 31, 2008, for the California refineries. For the Krotz Springs refinery, there were unrealized hedging gains of $25.6 million for the year ended December 31, 2009, and unrealized hedging gains of $117.5 million for the for the six months ended December 31, 2008. The 2008 refinery operating margin for the Krotz Springs refinery also excludes a charge of $127.4 million to cost of sales for inventory adjustments related to the acquisition. Additionally, the Krotz Springs refinery margin for 2009 excludes realized gains related to the unwind of the heating oil crack spread hedge of $139.3 million.
 
(8)   Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses at our Big Spring, California, and Krotz Springs refineries, exclusive of depreciation and amortization, by the applicable refinery’s total throughput volumes. Direct operating expenses related to the Bakersfield refinery of $3.4 million for the year ended December 31, 2010, has been excluded from the per barrel measurement.
 
(9)   Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.
 
(10)   Total refinery production represents the barrels per day of various products produced from processing crude and other refinery feedstocks through the crude units and other conversion units at the refineries.
 
(11)   Refinery utilization represents average daily crude oil throughput divided by crude oil throughput capacity, excluding planned periods of downtime for maintenance and turnarounds.

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ASPHALT SEGMENT
                         
    Year Ended December 31,  
    2010     2009     2008  
    (dollars in thousands, except per ton data)  
STATEMENT OF OPERATIONS DATA:
                       
Net sales
  $ 399,334     $ 440,915     $ 647,221  
Operating costs and expenses:
                       
Cost of sales (1)
    355,272       386,050       499,992  
Direct operating expenses
    44,095       44,124       43,356  
Selling, general and administrative expenses
    5,542       4,588       4,292  
Depreciation and amortization
    6,875       6,807       2,139  
 
                 
Total operating costs and expenses
    411,784       441,569       549,779  
 
                 
Operating income (loss)
  $ (12,450 )   $ (654 )   $ 97,442  
 
                 
 
                       
KEY OPERATING STATISTICS AND OTHER DATA:
                       
Number of terminals (end of period)
    12       12       12  
Blended asphalt sales volume (tons in thousands) (2)
    780       994       1,210  
Non-blended asphalt sales volume (tons in thousands) (3)
    83       197       88  
Blended asphalt sales price per ton (2)
  $ 477.26     $ 409.88     $ 511.95  
Non-blended asphalt sales price per ton (3)
    326.16       170.05       315.48  
Asphalt margin per ton (4)
    51.06       46.07       113.43  
Capital expenditures
  $ 1,557     $ 2,579     $ 644  
 
(1)   Cost of sales includes intersegment purchases of asphalt blends from our refining and unbranded marketing segment at prices which approximate wholesale market prices. These intersegment purchases are eliminated through consolidation of our financial statements.
 
(2)   Blended asphalt represents base asphalt that has been blended with other materials necessary to sell the asphalt as a finished product.
 
(3)   Non-blended asphalt represents base material asphalt and other components that require additional blending before being sold as a finished product.
 
(4)   Asphalt margin is a per ton measurement calculated by dividing the margin between net sales and cost of sales by the total sales volume. Asphalt margins are used in the asphalt industry to measure operating results related to asphalt sales.

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RETAIL AND BRANDED MARKETING SEGMENT
                         
    Year Ended December 31,  
    2010     2009     2008  
    (dollars in thousands, except per gallon data)  
STATEMENT OF OPERATIONS DATA:
                       
Net sales (1)
  $ 1,044,851     $ 808,221     $ 1,227,319  
Operating costs and expenses:
                       
Cost of sales (2)
    912,872       691,651       1,117,712  
Selling, general and administrative expenses
    99,024       94,725       97,172  
Depreciation and amortization
    13,440       13,464       13,674  
 
                 
Total operating costs and expenses
    1,025,336       799,840       1,228,558  
 
                 
Gain (loss) on disposition of assets
    286       (549 )      
 
                 
Operating income (loss)
  $ 19,801     $ 7,832     $ (1,239 )
 
                 
 
                       
KEY OPERATING STATISTICS AND OTHER DATA:
                       
Branded fuel sales (thousands of gallons) (3)
    318,935       274,101       339,100  
Branded fuel margin (cents per gallon) (3)
    6.2       5.8       2.8  
 
                       
Number of stores (end of period)
    304       308       306  
Retail fuel sales (thousands of gallons)
    142,155       120,697       96,974  
Retail fuel sales (thousands of gallons per site per month) (4)
    39       33       27  
Retail fuel margin (cents per gallon) (5)
    12.9       13.9       19.7  
Retail fuel sales price (dollar per gallon) (6)
  $ 2.70     $ 2.29     $ 3.26  
Merchandise sales
  $ 281,674     $ 268,785     $ 261,144  
Merchandise sales (per site per month) (4)
    77       73       72  
Merchandise margin (7)
    31.9 %     30.7 %     30.9 %
Capital expenditures
  $ 4,679     $ 3,822     $ 2,928  
 
(1)   Includes excise taxes on sales by the retail and branded marketing segment of $54.9 million, $47.1 million and $37.5 million for the years ended December 31, 2010, 2009 and 2008, respectively. Net sales also includes royalty and related net credit card fees of $4.2 million, $1.4 million and $0.3 million for the years ended December 31, 2010, 2009 and 2008, respectively.
 
(2)   Cost of sales includes intersegment purchases of motor fuels from our refining and unbranded marketing segment at prices which approximate wholesale market prices. These intersegment purchases are eliminated through consolidation of our financial statements.
 
(3)   Branded fuel sales represent branded fuel sales to our wholesale marketing customers that are primarily supplied by the Big Spring refinery. The branded fuels that are not supplied by the Big Spring refinery are obtained from third-party suppliers. Due to the fire on February 18, 2008 at the Big Spring refinery, more fuel was purchased from third-party suppliers in 2008. The branded fuel sales margin represents the margin between the net sales and cost of sales attributable to our branded fuel sales volume, expressed on a cents-per-gallon basis.
 
(4)   Retail fuel and merchandise sales per site for 2009 were calculated using 306 stores for eleven months and 308 stores for one month.
 
(5)   Retail fuel margin represents the difference between motor fuel sales revenue and the net cost of purchased motor fuel, including transportation costs and associated motor fuel taxes, expressed on a cents-per-gallon basis. Motor fuel margins are frequently used in the retail industry to measure operating results related to motor fuel sales.
 
(6)   Retail fuel sales price per gallon represents the average sales price for motor fuels sold through our retail convenience stores.
 
(7)   Merchandise margin represents the difference between merchandise sales revenues and the delivered cost of merchandise purchases, net of rebates and commissions, expressed as a percentage of merchandise sales revenues. Merchandise margins, also referred to as in-store margins, are commonly used in the retail industry to measure in-store, or non-fuel, operating results.

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Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Net Sales
     Consolidated. Net sales for 2010 were $4,030.7 million compared to $3,915.7 million for 2009, an increase of $115.0 million or 2.9%. This increase was primarily due to higher refined product prices and higher motor fuel volume and merchandise sales, partially offset by lower refinery throughput and lower asphalt sales volumes.
     Refining and Unbranded Marketing Segment. Net sales for our refining and unbranded marketing segment were $3,454.1 million for 2010, compared to $3,359.0 million for 2009, an increase of $95.1 million or 2.8%. The increase in net sales was primarily due to higher refined product prices partially offset by lower refinery throughput.
     Combined refinery throughput for the year ended December 31, 2010 averaged 105,868 bpd, consisting of 49,028 bpd at the Big Spring refinery, 17,596 bpd at the California refineries, and 39,244 bpd at the Krotz Springs refinery compared to average total refinery throughput for 2009 of 139,365 bpd, consisting of 59,870 bpd at the Big Spring refinery, 31,158 bpd at the California refineries and 48,337 at the Krotz Springs refinery. The Big Spring refinery throughput was lower as a result of efforts to implement new operating procedures and the California refineries’ throughput was lower due to our continued efforts to optimize asphalt production with demand and the redeployment of resources to integrate the Bakersfield refinery. The Krotz Springs refinery throughput was lower due to its shutdown for turnaround activities until its restart in June 2010.
     The average price of Gulf Coast gasoline for 2010 increased 41.7 cpg, or 25.5%, to 205.2 cpg, compared to 163.5 cpg for 2009. The average Gulf Coast ultra-low sulfur diesel price for 2010 increased 49.2 cpg, or 29.6%, to 215.6 cpg, compared to 166.4 cpg for 2009. The average price of West Coast LA CARBOB gasoline for 2010 increased 36.2 cpg, or 19.5%, to 221.4 cpg, compared to 185.2 cpg for 2009. The average West Coast LA ultra-low sulfur diesel price for 2010 increased 50.6 cpg, or 29.7%, to 221.2 cpg, compared to 170.6 cpg for 2009.
     Asphalt Segment. Net sales for our asphalt segment were $399.3 million for 2010, compared to $440.9 million for 2009, a decrease of $41.6 million or 9.4%. The decrease was due primarily to a decrease in asphalt sales volume and partially offset by higher asphalt sales prices in 2010. For 2010, the asphalt volume decreased 27.5%, from 1.191 million tons in 2009 to 0.863 million tons in 2010. Also, the average blended asphalt sales price increased 16.4% from $409.88 per ton for 2009 to $477.26 per ton for 2010 and the average non-blended asphalt sales price increased 91.8% from $170.05 per ton for 2009 to $326.16 per ton for 2010.
     Retail and Branded Marketing Segment. Net sales for our retail and branded marketing segment were $1,044.8 million for 2010, compared to $808.2 million for 2009, an increase of $236.6 million or 29.3%. This increase was primarily attributable to increases in motor fuel prices, motor fuel volume and merchandise sales.
Cost of Sales
     Consolidated. Cost of sales were $3,703.4 million for 2010, compared to $3,502.8 million for 2009, an increase of $200.6 million or 5.7%. This increase was primarily due to increased costs in all segments due to higher crude oil prices, higher motor fuel volume and merchandise sales and the realized gain recognized in 2009 for the unwind of the heating oil hedge, partially offset by lower refinery throughput and lower asphalt sales volumes.
     Refining and Unbranded Marketing Segment. Cost of sales for our refining and unbranded marketing segment were $3,302.8 million for 2010, compared to $3,117.5 million for 2009, an increase of $185.3 million or 5.9%. This increase was primarily due to higher crude oil costs and the realized gain recognized in 2009 for the unwind of the heating oil hedge, partially offset by lower refinery throughput volumes. The average WTI per barrel for 2010 increased $17.59 per barrel to $79.41 per barrel, compared to $61.82 per barrel for 2009, an increase of 28.5%.
     Asphalt Segment. Cost of sales for our asphalt segment were $355.3 million for 2010, compared to $386.0 million for 2009, a decrease of $30.7 million or 8.0%. The decrease was due primarily to lower asphalt sales volumes and partially offset by higher crude oil costs in 2010.

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     Retail and Branded Marketing Segment. Cost of sales for our retail and branded marketing segment was $912.9 million for 2010, compared to $691.7 million for 2009, an increase of $221.2 million or 32.0%. This increase was primarily attributable to increases in motor fuel prices, motor fuel volumes and merchandise costs.
Direct Operating Expenses
     Consolidated. Direct operating expenses were $249.9 million for 2010, compared to $265.5 million for 2009, a decrease of $15.6 million or 5.9%. This decrease was due to lower refinery throughput volumes for 2010 compared to 2009.
     Refining and Unbranded Marketing Segment. Direct operating expenses for our refining and unbranded marketing segment for 2010 were $205.8 million, compared to $221.4 million for 2009, a decrease of $15.6 million or 7.0%. This decrease was due to lower refinery throughput volumes for 2010 compared to 2009. This decrease was partially offset by the acquisition of the Bakersfield refinery in 2010.
     Asphalt Segment. Direct operating expenses for our asphalt segment for 2010 and 2009 were $44.1 million.
Selling, General and Administrative Expenses
     Consolidated. SG&A expenses for 2010 were $128.1 million, compared to $129.4 million for 2009, a decrease of $1.3 million or 1.0%.
     Refining and Unbranded Marketing Segment. SG&A expenses for our refining and unbranded marketing segment for 2010 were $22.8 million, compared to $29.4 million for 2009, a decrease of $6.6 million or 22.4%. This decrease was primarily due to net bad debt recoveries of $1.5 million in 2010 compared to bad debt expense of $3.3 million in 2009.
     Asphalt Segment. SG&A expenses for our asphalt segment for 2010 were $5.5 million, compared to $4.6 million for 2009, an increase of $0.9 million or 19.6%. This increase is due to employee related costs in 2010.
     Retail and Branded Marketing Segment. SG&A expenses for our retail and branded marketing segment for 2010 were $99.0 million, compared to $94.7 million for 2009, an increase of $4.3 million or 4.5%. The increase was primarily attributable to increased payroll and related costs.
Depreciation and Amortization
     Depreciation and amortization for 2010 was $102.1 million, compared to $97.2 million for 2009, an increase of $4.9 million or 5.0%. This increase was primarily attributable to depreciation on the capital expenditures placed into service during the fourth quarter of 2009 and in 2010.
Operating Income (Loss)
     Consolidated. Operating loss for 2010 was $160.8 million, compared to $80.8 million for 2009, an increase of $80.0 million. This increase was primarily due to lower refinery throughput and margins, lower asphalt sales volumes and the realized gain recognized in 2009 for the unwind of the heating oil hedge, partially offset by higher motor fuel volumes and higher merchandise sales and margins.
     Refining and Unbranded Marketing Segment. Operating loss for our refining and unbranded marketing segment was $166.0 million for 2010, compared to $86.5 million for 2009, an increase of $79.5 million. This increase was primarily due to lower refinery throughput at all our refineries, lower refining margins at our Krotz Springs and California refineries for 2010 compared to the same period last year and the realized gain recognized in 2009 for the unwind of the heating oil hedge. This was partially offset by higher margins at our Big Spring refinery, lower direct operating costs and net bad debt recoveries of $1.5 million in 2010 compared to bad debt expense of $3.3 million in 2009.

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     Refinery operating margin at the Big Spring refinery was $6.03 per barrel for 2010 compared to $4.35 per barrel for 2009. The Big Spring refinery light product yields were approximately 89.4% for 2010 and 82.1% for 2009. Refinery operating margin at the California refineries was $1.08 per barrel for 2010 compared to $1.83 per barrel for 2009. The Krotz Springs refinery operating margin for 2010 was $2.24 per barrel compared to $5.66 per barrel for 2009.
     Asphalt Segment. Operating loss for our asphalt segment was $12.5 million for 2010, compared to $0.6 million for 2009, an increase of $11.9 million. The increase was primarily due to lower sales volumes in 2010.
     Retail and Branded Marketing Segment. Operating income for our retail and branded marketing segment was $19.8 million for 2010, compared to $7.8 million for 2009, an increase of $11.8 million. This increase was primarily attributable to higher motor fuel volumes and higher merchandise sales and margins.
Interest Expense
     Interest expense was $94.9 million for 2010, compared to $111.1 million in 2009, a decrease of $16.2 million or 14.6%.The decrease is primarily due to $20.5 million of unamortized debt issuance costs written off as a result of the prepayment of $163.8 million of term debt in 2009 and $5.7 million of interest expenses related to the liquidation of our heating oil hedge in 2009. This was partially offset by $6.7 million of debt issuance costs written off associated with our prepayment of the Alon Refining Krotz Springs, Inc. revolving credit facility in 2010.
Gain from Bargain Purchase
     In connection with the Bakersfield refinery acquisition in June 2010, the acquisition date fair value of the identifiable net assets acquired exceeded the fair value of the consideration transferred, resulting in a $17.5 million bargain purchase gain in 2010.
Income Tax Benefit
     Income tax benefit was $90.5 million in 2010, compared to $64.9 million in 2009, an increase of $25.6 million. The increase in income tax benefit was attributable to our lower 2010 taxable income compared to 2009. The pre-tax loss for 2010 includes the $17.5 million non-taxable bargain purchase gain. Our effective tax rate was 37.6% for 2010, excluding the $17.5 million non-taxable bargain purchase gain, compared to an effective tax rate of 38.8% for 2009.
Non-controlling Interest in Loss of Subsidiaries
     Non-controlling interest in loss of subsidiaries represents the proportional share of net loss related to non-voting common stock owned by non-controlling interest stockholders in two of our subsidiaries, Alon Assets and Alon Operating. Non-controlling interest in loss of subsidiaries was $9.6 million for 2010, compared to $8.6 million for 2009, an increase of $1.0 million.
Net Loss Available to Common Stockholders
     Net loss available to common stockholders was $122.9 million for 2010, compared to $115.2 million for 2009, an increase in loss of $7.7 million. This increase was attributable to the factors discussed above.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Net Sales
     Consolidated. Net sales for 2009 were $3,915.7 million compared to $5,156.7 million for 2008, a decrease of $1,241.0 million or 24.1%. This decrease was primarily due to lower refined product prices, and was partially offset by higher sales volume from a full year of operations at our Big Spring and Krotz Springs refineries.

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     Refining and Unbranded Marketing Segment. Net sales for our refining and unbranded marketing segment were $3,359.0 million for 2009, compared to $4,551.8 million for 2008, a decrease of $1,192.8 million or 26.2%. The decrease in net sales was primarily due to significantly lower refined product prices partially offset by the inclusion of an additional six months of sales from the Krotz Springs refinery acquired in July 2008 and lower 2008 throughput volumes as a result of the February 18, 2008 Big Spring refinery fire.
     The Big Spring refinery and California refineries combined throughput for 2009 averaged 91,028 bpd consisting of 59,870 bpd at the Big Spring refinery and 31,158 bpd at the California refineries compared to average total refinery throughput for 2008 of 68,892 bpd, consisting of 37,793 bpd at the Big Spring refinery and 31,099 bpd at the California refineries. The Krotz Springs refinery throughput for 2009 averaged 48,337 bpd and for the period from its acquisition effective July 1, 2008 through December 31, 2009 averaged 58,184 bpd.
     The decrease in refined product prices that our refineries experienced was similar to the price decreases experienced in each refinery’s respective markets. The average price of Gulf Coast gasoline for 2009 decreased 83.6 cpg, or 33.8%, to 163.5 cpg, compared to 247.1 cpg for 2008. The average Gulf Coast ultra-low sulfur diesel price for 2009 decreased 125.4 cpg, or 43.0%, to 166.4 cpg, compared to 291.8 cpg for 2008. The average price of West Coast LA CARBOB gasoline for 2009 decreased 82.7 cpg, or 30.9%, to 185.2 cpg, compared to 267.9 cpg for 2008. The average West Coast LA ultra-low sulfur diesel price for 2009 decreased 117.7 cpg, or 40.8%, to 170.6 cpg, compared to 288.3 cpg for 2008.
     Asphalt Segment. Net sales for our asphalt segment were $440.9 million for 2009, compared to $647.2 million for 2008, a decrease of $206.3 million or 31.9%. The decrease was due primarily to a decrease in the average asphalt sales price and lower asphalt sales volumes for the year 2009. For the year 2009, we sold 1.191 million tons of asphalt compared to 1.298 million tons of asphalt sold in 2008, a decrease of 0.107 million tons of asphalt or 8.2%. Also, the average blended asphalt sales price decreased 19.9% from $511.95 per ton for 2008 to $409.88 per ton for 2009 and the average non-blended asphalt sales price decreased 46.1% from $315.48 per ton for 2008 to $170.05 per ton for 2009. The blended asphalt sales accounted for 92% of total asphalt sales for 2009. The percentage decrease in the blended asphalt sales price of 19.9% was less than the 37.9% decrease in WTI prices for 2009.
     Retail and Branded Marketing Segment. Net sales for our retail and branded marketing segment were $808.2 million for 2009, compared to $1,227.3 million for 2008, a decrease of $419.1 million or 34.1%. This decrease was primarily due to a 100.2 million gallon reduction in wholesale non-integrated branded fuel sales related to the net decline of 130 retail outlets that we supplied with motor fuel and lower sales prices. This net decline in retail outlets supplied by us was a result of our efforts to reduce our exposure in markets not integrated with our Big Spring refinery by allowing fuel supply agreements to expire by their terms. This reduction was partially offset by higher integrated branded fuel sales, retail fuel sales and merchandise sales.
Cost of Sales
     Consolidated. Cost of sales was $3,502.8 million for 2009, compared to $4,853.2 million for 2008, a decrease of $1,350.4 million or 27.8%. This decrease was primarily due to decreased costs in all segments due to lower crude oil prices, and was partially offset by higher cost of sales volume from a full year of operations at our Big Spring and Krotz Springs refineries.
     Refining and Unbranded Marketing Segment. Cost of sales for our refining and unbranded marketing segment were $3,117.5 million for 2009, compared to $4,505.1 million for 2008, a decrease of $1,387.6 million or 30.8%. This decrease was primarily due to lower crude oil costs, partially offset by the inclusion of an additional six months of cost of sales from the Krotz Springs refinery acquired in July 2008 and lower 2008 throughput volumes at the Big Spring refinery from the February 2008 fire. The average price per barrel of WTI for 2009 decreased $37.74 per barrel to an average of $61.82 per barrel, compared to an average of $99.56 per barrel for 2008, a decrease of 37.9%.
     Asphalt Segment. Cost of sales for our asphalt segment were $386.0 million for 2009, compared to $500.0 million for 2008, a decrease of $114.0 million or 22.8%. The decrease was due to the decreased cost of crude oil and lower asphalt sales volumes in 2009.

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     Retail and Branded Marketing Segment. Cost of sales for our retail and branded marketing segment was $691.7 million for 2009, compared to $1,117.7 million for 2008, a decrease of $426.0 million or 38.1%. This decrease was primarily due to a 100.2 million gallon reduction in wholesale non-integrated branded fuel sales related to the net decline of 130 retail outlets that we supplied with motor fuel and lower product costs. This reduction was partially offset by higher integrated branded fuel sales, retail fuel sales and merchandise sales.
Direct Operating Expenses
     Consolidated. Direct operating expenses were $265.5 million for 2009, compared to $216.5 million for 2008, an increase of $49.0 million or 22.6%. This increase was primarily due to the direct operating expenses associated with the Krotz Springs refinery acquired in July 2008 and higher throughput volumes at the Big Spring refinery for 2009 compared to 2008.
     Refining and Unbranded Marketing Segment. Direct operating expenses for our refining and unbranded marketing segment for 2009 were $221.4 million, compared to $173.1 million for 2008, an increase of $48.3 million or 27.9%. This increase was primarily due to the inclusion of an additional six months of direct operating expenses associated with the Krotz Springs refinery acquired in July 2008 and higher throughput volumes at the Big Spring refinery for 2009 compared to 2008. This was partially offset by lower natural gas prices in 2009.
     Asphalt Segment. Direct operating expenses for our asphalt segment for 2009 were $44.1 million, compared to $43.4 million for 2008, an increase of $0.7 million or 1.6%.
Selling, General and Administrative Expenses
     Consolidated. SG&A expenses for 2009 were $129.4 million, compared to $119.9 million for 2008, an increase of $9.5 million or 7.9%. This increase was primarily due to the inclusion of an additional six months of SG&A costs associated with the Krotz Springs refinery acquired in July 2008 and an increase of $3.3 million in allowance for doubtful accounts.
     Refining and Unbranded Marketing Segment. SG&A expenses for our refining and unbranded marketing segment for 2009 were $29.4 million, compared to $17.8 million for 2008, an increase of $11.6 million or 65.2%. This increase was primarily due to the inclusion of an additional six months of SG&A costs associated with the Krotz Springs refinery acquired in July 2008 and an increase of $3.3 million in allowance for doubtful accounts.
     Asphalt Segment. SG&A expenses for our asphalt segment for 2009 were $4.6 million, compared to $4.3 million for 2008, an increase of $0.3 million or 7.0%.
     Retail and Branded Marketing Segment. SG&A expenses for our retail and branded marketing segment for 2009 were $94.7 million, compared to $97.2 million for 2008, a decrease of $2.5 million or 2.6%. This decrease was primarily attributable to implementation of improved inventory control procedures to reduce shrinkage.
Depreciation and Amortization
     Depreciation and amortization for 2009 was $97.2 million, compared to $66.8 million for 2008, an increase of $30.4 million or 45.5%. This increase was primarily attributable to a full year of depreciation of the assets acquired from the acquisition of the Krotz Springs refinery and depreciation on the capital expenditures related to the rebuild of the Big Spring refinery.

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Operating Income (Loss)
     Consolidated. Operating income (loss) for 2009 was ($80.8) million, compared to $223.5 million for 2008, a decrease of $304.3 million. This decrease was primarily due to gains recorded in 2008 for the involuntary conversion of assets and business interruption recovery associated with the Big Spring refinery fire, partially offset by fire related costs. Operating income in 2008 also included a gain on disposition of assets related to the HEP transaction. Refining margins at our Big Spring refinery and California refineries were higher for 2009 compared to the same period last year, and the Krotz Springs refinery acquired in July 2008 included six months of operating margin in 2008 and twelve months of operating margin in 2009.
     Refining and Unbranded Marketing Segment. Operating income (loss) for our refining and unbranded marketing segment was ($86.5) million for 2009, compared to $128.8 million for 2008, a decrease of $215.3 million. This decrease was primarily due to gains recorded in 2008 for the involuntary conversion of assets of $279.7 million and business interruption recovery of $55.0 million associated with the Big Spring refinery fire, offset by fire related costs of $56.9 million. Additionally, gains on disposition of assets of $45.2 million were recorded in 2008 related to the HEP transaction. Partially offsetting these 2008 gains were higher refining margins at our Big Spring refinery and California refineries for 2009 compared to the same period last year. In addition, the Krotz Springs refinery acquired in July 2008 included six months of operating margin in 2008 and twelve months of operating margin in 2009.
     Refinery operating margin at the Big Spring refinery was $4.35 per barrel for 2009 compared to ($3.18) per barrel for 2008. This increase was primarily due to the depressed margins experienced in conjunction with the fire at the Big Spring refinery in 2008. The Big Spring refinery light product yields were approximately 82.1% for 2009 and 69.8% for 2008. Refinery operating margin at the California refineries was $1.83 per barrel for 2009 compared to $1.65 per barrel for 2008. The Krotz Springs refinery operating margin for 2009 was $5.66 per barrel compared to $7.25 per barrel for the period from its acquisition effective July 1, 2008 through December 31, 2008. The lower Krotz Springs refinery operating margin is due primarily to lower Gulf coast 2/1/1 high sulfur diesel margins in 2009.
     Asphalt Segment. Operating income (loss) for our asphalt segment was ($0.6) million for 2009, compared to $97.4 million for 2008, a decrease of $98.0 million. The decrease was primarily due to the lower sales prices and sales volumes in 2009.
     Retail and Branded Marketing Segment. Operating income (loss) for our retail and branded marketing segment was $7.8 million for 2009, compared to ($1.2) million for 2008, an increase of $9.0 million. This increase was primarily attributable to higher branded fuel margins.
Interest Expense
     Interest expense was $111.1 million for 2009, compared to $67.6 million in 2008, an increase of $43.5 million or 64.3%. The increase is primarily due to interest on our borrowings and letter of credit fees related to the Krotz Springs refinery acquisition in July 2008, interest expenses related to the liquidation of our heating oil hedge in 2009 of $5.7 million and the write-off of unamortized debt issuance costs of $20.5 million as a result of the prepayment of the Krotz Term Loan in 2009.
Income Tax Expense (Benefit)
     Income tax expense (benefit) was ($64.9) million in 2009, compared to $62.8 million in 2008, a decrease of $127.7 million. The decrease in income tax expense (benefit) was attributable to our lower 2009 taxable income compared to 2008. Our effective tax rate for 2009 was 38.8% compared to 40.3% for 2008.
Non-controlling Interest in Income (Loss) of Subsidiaries
     Non-controlling interest in income (loss) of subsidiaries represents the proportional share of net income related to non-voting common stock owned by non-controlling interest stockholders in two of our subsidiaries, Alon Assets

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and Alon Operating. Non-controlling interest in income (loss) of subsidiaries was ($8.6) million for 2009, compared to $5.9 million for 2008, a decrease of $14.5 million.
Accumulated Dividends on Preferred Stock of Subsidiary
     Accumulated dividends on preferred stock of subsidiary for the year ended December 31, 2009, represent dividends of $12.9 million for the conversion of the preferred stock into Alon common stock. Also included for the year ended December 31, 2009 is $8.6 million of accumulated dividends.
Net Income (Loss) Available to Common Stockholders
Net income (loss) available to common stockholders was ($115.2) million for 2009, compared to $82.9 million for 2008, a decrease of $198.1 million. This decrease 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, borrowings under our revolving credit facilities and capital contributions or loans from affiliates.
     During the first quarter of 2011, we have completed three agreements. In January 2011, we completed a Standby Equity Distribution Agreement for a commitment by an unrelated party to purchase up to $25.0 million of our common stock over a two-year period. In February 2011, we signed a multi-year agreement with J. Aron for the supply of crude oil that will support the operation of the Big Spring refinery at 70,000 barrels per day. This agreement became effective on March 1, 2011. The structure of this new agreement is also expected to result in lower borrowing costs as we used the proceeds from the sale of inventories to repay approximately $125.0 million of loans under our Alon USA LP Credit Facility. Also, the structure will substantially reduce our need to issue letters of credit to support Big Spring refinery crude oil purchases. In addition, the structure will allow us to make crude oil purchases without the constraint of increases in crude oil prices customary with a typical revolving credit facility. Also, in February 2011, Alon Brands issued 5-year unsecured notes for $30.0 million to a group of investors, including Alon Israel.
     We believe that the aforementioned sources of funds and other sources of capital available to us will be sufficient to satisfy the anticipated cash requirements associated with our business 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.
     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, extend or replace existing revolving credit facilities or for other corporate purposes.
Cash Flow
     The following table sets forth our consolidated cash flows for the years ended December 31, 2010, 2009 and 2008:
                         
    Year Ended December 31  
    2010     2009     2008  
    (dollars in thousands)          
Cash provided by (used in):
                       
Operating activities
  $ 21,330     $ 283,145     $ (812 )
Investing activities
    (40,925 )     (138,691 )     (610,322 )
Financing activities
    50,845       (122,471 )     560,973  
 
                 
Net increase (decrease) in cash and cash equivalents
  $ 31,250     $ 21,983     $ (50,161 )
 
                 
Cash Flows Provided By (Used in) Operating Activities
     Net cash provided by operating activities in 2010 was $21.3 million, compared to $283.1 million in 2009. The change of $261.9 million in net cash provided by operating activities in 2010 is primarily attributable to the difference of $162.7 million in net income, adjusted for non-cash reconciling items such as deferred income tax

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expense, bargain purchase gain, gain on the disposition of assets and depreciation, in 2010 compared to 2009, and the receipt of proceeds from the liquidation of our heating oil crack spread hedge in 2009 for $133.6 million.
     Net cash provided by (used in) operating activities in 2009 was $283.1 million, compared to ($0.8) million in 2008. The change of $283.9 million in net cash provided by operating activities in 2009 was attributable to the receipt of proceeds from the liquidation of our heating oil crack spread hedge in 2009 for $133.6 million, receipt of income tax receivables in 2009 of $113.0 million and the change in net income compared to 2008, adjusted for non-cash reconciling items such as deferred income tax expense, gain on involuntary conversion of assets, gain on the disposition of assets and depreciation.
Cash Flows Used In Investing Activities
     Net cash used in investing activities was $40.9 million in 2010 compared to $138.7 million in 2009. The change in net cash used in investing activities of $97.8 was primarily due to lower 2010 capital expenditures of $93.3 million compared to 2009, proceeds received from the disposition of assets and sale of securities of $22.0 million and $36.9 million, respectively, and a decrease in the earnout payments made to Valero of $10.9 million from 2009. This was partially offset by the acquisition of the Bakersfield refinery of $32.4 million in 2010 and insurance proceeds of $34.1 million received in 2009 to rebuild the Big Spring refinery.
     Net cash used in investing activities was $138.7 million in 2009 compared to $610.3 million in 2008. The change in cash used in investing activities of $471.6 million was primarily due to the July 3, 2008 acquisition of the Krotz Springs refinery of $481.0 million and 2008 capital expenditures to rebuild the Big Spring refinery, net of insurance proceeds. This was partially offset by higher capital expenditures, $106.4 million in 2009 compared to $72.3 million in 2008, and earnout payments made to Valero of $19.7 million as part of the Krotz Springs refinery acquisition in 2009.
Cash Flows Provided By (Used In) Financing Activities
     Net cash provided by (used in) financing activities was $50.8 million in 2010 compared to ($122.5) million in 2009. The change in net cash used in financing activities of $173.4 million was primarily attributable to the proceeds received from the sale of preferred stock of $40.0 million, cash received from the inventory supply agreement of $45.8 million in 2010 compared to cash received from an inventory supply agreement of $20.2 million in 2009, as well as an overall decrease in payments made on long-term debt and debt issuance costs during 2010.
     Net cash provided by (used in) financing activities was ($122.5) million in 2009 compared to $561.0 million in 2008. The change in net cash used in financing activities of $683.5 million was primarily attributable to proceeds received in 2008 from the Krotz Term Loan of $252.0 million to purchase the Krotz Springs refinery and $276.8 million of borrowings on the revolving credit facilities plus an $80.0 million investment from our parent. These proceeds were partially offset by debt issuance costs of $28.1 million and payments on long-term debt of $11.9 million. In 2009, the prepayment of the Krotz Term Loan and repayments of borrowings under revolving credit facilities of $322.2 million were made from proceeds associated with the receipt of income tax receivables, the liquidation of the heating oil crack spread hedge and net proceeds received from the issuance of the senior notes of $205.4 million. 2009 also included cash used of $17.8 million for debt issuance cost, associated with the senior secured notes, and $20.2 million of cash received from an inventory supply agreement.
Cash and Cash Equivalents
     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.
     As of December 31, 2010, our total cash and cash equivalents were $71.7 million and we had total debt of $916.3 million.

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Credit Facilities
Alon USA Energy, Inc. Credit Facilities
     Term Loan Credit Facility. We have a term loan (the “Alon Energy Term Loan”) that will mature on August 2, 2013. Principal payments of $4.5 million per annum are paid in quarterly installments, subject to reduction from mandatory repayments associated with certain events.
     Borrowings under the Alon Energy Term Loan bear interest at a rate based on a margin over the Eurodollar rate from between 1.75% to 2.50% per annum based upon the ratings of the loans by Standard & Poor’s Rating Service and Moody’s Investors Service, Inc. Currently, the margin is 2.25% over the Eurodollar rate.
     The Alon Energy Term Loan is jointly and severally guaranteed by all of our subsidiaries except for our retail subsidiaries and those subsidiaries established in conjunction with the Krotz Springs refinery acquisition and certain subsidiaries established in conjunction with the Bakersfield acquisition. The Alon Energy Term Loan is secured by a second lien on cash, accounts receivable and inventory and a first lien on most of our remaining assets excluding those of our retail subsidiaries and those subsidiaries established in conjunction with the Krotz Springs refinery acquisition and certain subsidiaries established in conjunction with the Bakersfield acquisition.
     The Alon Energy Term Loan contains restrictive covenants, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, different businesses, certain lease obligations, and certain restricted payments. The Alon Energy Term Loan does not contain any maintenance financial covenants.
     At December 31, 2010 and 2009, the Alon Energy Term Loan had an outstanding balance of $429.8 million and $434.3 million, respectively.
     Letter of Credit Facility. In March 2010, we entered into an unsecured credit facility with Israel Discount Bank of New York (the “Alon Energy Letter of Credit Facility”) for the issuance of letters of credit in an amount not to exceed $60.0 million and with a sub-limit for borrowings not to exceed $30.0 million. This facility will terminate on January 31, 2013. The Alon Energy Letter of Credit Facility contains certain restrictive covenants including maintenance financial covenants. On December 31, 2010, Alon had $60.0 million of outstanding letters of credit under this facility. Borrowings under this facility bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%.
Alon USA, LP Credit Facility
     Revolving Credit Facility. We have a $240.0 million revolving credit facility (the “Alon USA LP Credit Facility”) that will mature on January 1, 2013. The Alon USA LP Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility.
     Borrowings under the Alon USA LP Credit Facility bear interest at the Eurodollar rate plus 3.00% per annum subject to an overall minimum interest rate of 4.00%.
     The Alon USA LP Credit Facility is secured by (i) a first lien on our cash, accounts receivables, inventories and related assets and (ii) a second lien on our fixed assets and other specified property, in each case, excluding those of Alon Paramount Holdings, Inc. (“Alon Holdings”), and its subsidiaries other than Alon Pipeline Logistics, LLC (“Alon Logistics”), the subsidiaries established in conjunction with the Krotz Springs refinery acquisition, the subsidiaries established in conjunction with the Bakersfield refinery acquisition and our retail subsidiaries.
     The Alon USA LP Credit Facility contains certain restrictive covenants including maintenance financial covenants.

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     Borrowings of $122.0 million and $88.0 million were outstanding under the Alon USA LP Credit Facility at December 31, 2010 and 2009, respectively. At December 31, 2010 and 2009, outstanding letters of credit under the Alon USA LP Credit Facility were $117.0 million and $129.0 million, respectively.
Paramount Petroleum Corporation Credit Facility
     Revolving Credit Facility. Paramount Petroleum Corporation has a $300.0 million revolving credit facility (the “Paramount Credit Facility”) that will mature on February 28, 2012. The Paramount Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility.
     Borrowings under the Paramount Credit Facility bear interest at the Eurodollar rate plus a margin based on excess availability. Based on the excess availability at December 31, 2010, the margin was 2.00%.
     The Paramount Credit Facility is primarily secured by (i) a first lien on cash, accounts receivables, inventories and related assets and (ii) a second lien on Alon Holdings’ (excluding Alon Logistics) fixed assets and other specified property.
     The Paramount Credit Facility contains certain restrictive covenants related to working capital, operations and other matters.
     Borrowings of $63.1 million and $45.3 million were outstanding under the Paramount Credit Facility at December 31, 2010 and 2009, respectively. At December 31, 2010 and 2009, outstanding letters of credit under the Paramount Credit Facility were $1.3 million and $18.0 million, respectively.
Alon Refining Krotz Springs, Inc. Credit Facilities
     Senior Secured Notes. In October 2009, Alon Refining Krotz Springs, Inc. (“ARKS”) issued 13.50% senior secured notes (the “Senior Secured Notes”) in aggregate principal amount of $216.5 million in a private offering. In February 2010, ARKS exchanged $216.5 million of Senior Secured Notes for an equivalent amount of Senior Secured Notes (“Exchange Notes”) registered under the Securities Act of 1933. The Exchange Notes will mature on October 15, 2014 and the entire principal amount is due at maturity. Interest is payable semi-annually in arrears on April 15 and October 15. The Exchange Notes are substantially identical to the Senior Secured Notes, except that the Exchange Notes have been registered with the Securities and Exchange Commission and are not subject to transfer restrictions. The Senior Secured Notes were issued at an offering price of 94.857% and ARKS received gross proceeds of $205.4 million (before fees and expenses related to the offering). ARKS used the proceeds to repay in full all outstanding obligations under its term loan at that time. The remaining proceeds from the offering were used for general corporate purposes.
     The terms of the Senior Secured Notes are governed by an indenture (the “Indenture”) and the obligations under the Indenture are secured by a first priority lien on ARKS’ property, plant and equipment and a second priority lien on ARKS’ cash, accounts receivable and inventory.
     The Indenture also contains restrictive covenants such as restrictions on loans, mergers, sales of assets, additional indebtedness and restricted payments. The Indenture does not contain any maintenance financial covenants.
     At December 31, 2010 and 2009, the Senior Secured Notes had an outstanding balance (net of unamortized discount) of $207.4 million and $205.7 million, respectively. ARKS is utilizing the effective interest method to amortize the original issue discount over the life of the Senior Secured Notes.
     Short-Term Credit Facility. In March 2010, ARKS entered into a $65.0 million short-term credit facility with Bank Hapoalim B.M. (the “ARKS Term Facility”). The ARKS Term Facility was drawn upon closing and all outstanding amounts were repaid during 2010.

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     Revolving Credit Facility. In March 2010, ARKS terminated its revolving credit facility agreement (the “ARKS Facility”) and repaid all outstanding amounts thereunder. As a result of the prepayment of the ARKS Facility, we recorded a write-off of unamortized debt issuance costs of $6.7 million as interest expense in the first quarter of 2010.
     Borrowings of $83.3 million and outstanding letters of credit of $2.8 million were outstanding under the ARKS Facility at December 31, 2009.
Retail Credit Facilities
     Term Credit Agreement. Southwest Convenience Stores, LLC (“SCS”) is party to a credit agreement (the “SCS Credit Agreement”) that, as amended, matures on December 30, 2015. On December 30, 2010, SCS entered into an amendment to the SCS Credit Agreement. The amendment increased the amount outstanding from $73.4 million (“SCS Refinancing Term Loan”) by $10.0 million (“SCS Additional Term Loan”) and also included a revolving credit loan (“SCS Revolving Credit Loan”) with a maximum loan amount of the lesser of the borrowing base or $10.0 million.
     Borrowings under the SCS Refinancing Term Loan bear interest at a Eurodollar rate plus 2.00% per annum with principal payments made in quarterly installments based on a 15-year amortization schedule.
     Borrowings under the SCS Additional Term Loan bear interest at a Eurodollar rate plus 2.75% per annum with principal payments made in quarterly installments based on a 5-year amortization schedule.
     Borrowings under the SCS Revolving Credit Loan bear interest at a Eurodollar rate plus 2.75% per annum.
     The obligations under the SCS Credit Agreement are secured by a pledge of substantially all of the assets of SCS and Skinny’s, LLC and each of their subsidiaries, including cash, accounts receivable and inventory.
     The SCS Credit Agreement contains certain restrictive covenants including maintenance financial covenants.
     At December 31, 2010 and 2009, the SCS Credit Agreement had an outstanding balance under the term loans of $83.4 million and $79.7 million, respectively. At December 31, 2010, the SCS Revolving Credit Loan had an outstanding balance of $10.0 million.
Other Retail Related Credit Facilities
     In 2003, we obtained $1.5 million 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. At December 31, 2010 and 2009, the outstanding balances were $0.7 million and $0.8 million, respectively.
Capital Spending
     Each year our Board of Directors approves capital projects, including regulatory and planned turnaround projects that our management is authorized to undertake in our annual capital budget. Additionally, at times when conditions warrant or as new opportunities arise, other projects or the expansion of existing projects may be approved. Our capital expenditure budgets, including expenditures for chemical catalyst and turnarounds, for 2011 and 2012 are $108.9 million and $115.0 million, respectively. The following table summarizes our expected capital expenditures for 2011 and 2012 by operating segment and major category:

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    2011     2012  
    (dollars in thousands)  
Refining and Unbranded Marketing Segment:
               
Sustaining maintenance
  $ 25,642     $ 69,670  
Growth/profit improvement/other
    48,186       11,450  
Chemical catalyst and turnaround
    10,264       13,820  
 
           
Total
    84,092       94,940  
 
           
Asphalt Segment:
               
Sustaining maintenance
    3,596       4,887  
Growth/profit improvement
    2,073       2,614  
 
           
Total
    5,669       7,501  
 
           
Retail and Branded Marketing Segment:
               
Sustaining maintenance
    7,102       4,655  
Growth/profit improvement
    9,312       5,500  
 
           
Total
    16,414       10,155  
 
           
Corporate Segment:
               
Sustaining
    2,774       2,390  
 
           
Total Capital Expenditures
  $ 108,949     $ 114,986  
 
           
     Turnaround and Chemical Catalyst Costs. Our 2010 turnaround and chemical catalyst costs were $13.1 million.
     Between our major turnarounds, we also perform periodic scheduled turnaround projects on various units at our Big Spring, Krotz Springs and California refineries. A summary of our expected turnaround and chemical catalyst costs for the following five years are as follows:
                                         
    2011     2012     2013     2014     2015  
    (dollars in thousands)  
Scheduled turnaround costs
  $ 1,170     $ 5,500     $ 9,000     $ 18,300     $ 15,400  
Chemical catalyst costs
    9,094       8,320       11,074       16,501       9,148  
 
                             
Total
  $ 10,264     $ 13,820     $ 20,074     $ 34,801     $ 24,548  
 
                             
Contractual Obligations and Commercial Commitments
     Information regarding our known contractual obligations of the types described below as of December 31, 2010 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
  $ 11,512     $ 624,355     $ 280,169     $ 269     $ 916,305  
Operating lease obligations
    36,385       51,071       24,568       43,390       155,414  
Pipelines and Terminals Agreement (1)
    31,324       64,487       66,889       139,037       301,737  
Other commitments (2)
    3,741       7,482       7,482       23,379       42,084  
 
                             
Total obligations
  $ 82,962     $ 747,395     $ 379,108     $ 206,075     $ 1,415,540  
 
                             
 
(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, 2010, we did not have any material capital lease obligations or any agreements to purchase goods or services, other than those included in the table above, that were binding on us.
     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, 2010. However, certain expected payments related to our anticipated pension contributions in 2010 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.

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Off-Balance Sheet Arrangements
     We have no material 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 unbranded 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 the 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. A reduction of inventory volumes during 2010, 2009 and 2008 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 $18.6 million, $10.2 million, and $4.1 million in 2010, 2009 and 2008, respectively. Market values of crude oil, refined products, asphalts and blendstocks exceeded LIFO costs by $115.1 million and $100.5 million at December 31, 2010 and 2009, respectively.
     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. At December 31, 2010, for those payments we considered fixed and determinable, payments were discounted at a 4% rate. We record them without considering potential recoveries from third parties. Recoveries of environmental remediation costs from third parties are recorded as assets when receipt is deemed probable. We update our estimates to reflect changes in factual information, available technology or applicable laws and regulations.
     Turnarounds and Chemical Catalyst Costs. We record the cost of planned major refinery maintenance, referred to as turnarounds, and 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 Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Subtopic 360-10, Property, Plant, and Equipment. 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

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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. Alon uses ASC Subtopic 410-20, Asset Retirement Obligations, which established accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement costs. The provisions of ASC Subtopic 410-20 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. ASC Subtopic 410-20 also 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.
     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 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.
     At December 31, 2010, Alon had three reporting units with goodwill; California refining, California asphalt, and Retail operations. The fair values of our reporting units in 2010 that contain goodwill were determined using two methods, one based on discounted cash flow models with estimated cash flows based on internal forecasts of revenues and expenses and the other based on market earnings multiples. Each reporting unit was evaluated separately. Cash flows were discounted at rates that approximate a market participants’ weighted average cost of capital; 10% for both California refining and California asphalt and 8.5% for Retail operations. We believe these two approaches are appropriate valuation techniques for the purposes of our impairment testing. Therefore, we concluded from our valuations, based on business conditions and market values that existed at December 31, 2010, that none of our goodwill was impaired. However, the market value of our common stock at December 31, 2010 continued to reflect the effects of the difficult economic environment, the market’s perception of our asset utilization and significant competition in most of our markets. If, among other factors, (1) our equity value declines further, (2) the fair value of our reporting units decline, or (3) the impact of economic or competitive factors adversely affect beyond what was anticipated, we could conclude in future periods that impairment losses are required in order to reduce the carrying value of our goodwill, and, to a lesser extent, long-lived assets. Depending on the severity of the changes in the key factors underlying the valuation of our reporting units, such losses could be significant.
Reconciliation of Amounts Reported Under Generally Accepted Accounting Principles
     Reconciliation of Adjusted EBITDA to amounts reported under generally accepted accounting principles in financial statements.
     Adjusted EBITDA represents earnings before non-controlling interest in income of subsidiaries, income tax expense, interest expense, depreciation and amortization, gain on bargain purchase and gain on disposition of assets. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in Adjusted

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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 non-controlling interest in income of subsidiaries, income tax expense, interest expense, gain on disposition of assets, gain on bargain purchase and the accounting effects of capital expenditures and acquisitions, items that may vary for different companies for reasons unrelated to overall operating performance.
     Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:
    Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
 
    Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;
 
    Adjusted EBITDA does not reflect the prior claim that non-controlling interest have on the income generated by non-wholly-owned subsidiaries;
 
    Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and
 
    Our calculation of Adjusted EBITDA may differ from EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.
     Because of these limitations, 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 Adjusted EBITDA only supplementally.
     The following table reconciles net income (loss) available to common stockholders to Adjusted EBITDA for the years ended December 31, 2010, 2009 and 2008, respectively:
                         
    For the Year Ended December 31,  
    2010     2009     2008  
    (in thousands)  
Net income (loss) available to common stockholders
  $ (122,932 )   $ (115,156 )   $ 82,883  
Non-controlling interest in income (loss) of subsidiaries (including accumulated dividends on preferred stock of subsidiary)
    (9,641 )     12,949       10,241  
Income tax expense (benefit)
    (90,512 )     (64,877 )     62,781  
Interest expense
    94,939       111,137       67,550  
Depreciation and amortization
    102,096       97,247       66,754  
Gain on bargain purchase
    (17,480 )            
(Gain) loss on disposition of assets
    (945 )     1,591       (45,244 )
 
                 
Adjusted EBITDA
  $ (44,475 )   $ 42,891     $ 244,965  
 
                 
     Adjusted EBITDA for the year ended December 31, 2008 includes a gain on involuntary conversion of assets of $279.7 million representing the insurance proceeds received with respect to property damage resulting from the Big Spring refinery fire in excess of the net book value of the assets impaired; net costs associated with the fire at the Big Spring refinery of $56.9 million; and a charge for inventory adjustments related to the Krotz Springs acquisition of $127.4 million.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Quantitative and Qualitative Disclosure About Market Risk
     Changes in commodity prices and purchased fuel prices 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, 2010, we held approximately 2.4 million barrels of crude oil and product inventories valued under the LIFO valuation method with an average cost of $38.81 per barrel. Market value exceeded carrying value of LIFO costs by $115.1 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced by $2.4 million.
     In accordance with fair value provisions of ASC 825-10, 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, 2010:
                                                 
    Contract Volume                                
Description of Activity   (in barrels)     Wtd Avg Price     Wtd Avg Price     Contract Value     Fair Value     Gain (Loss)  
                            (in thousands)  
                             
Forwards — long (Crude)
    101,475       91.93           $ 9,329     $ 9,552     $ 223  
Forwards — short (Crude)
    (143,466 )           91.93       (13,189 )     (13,505 )     (316 )
Forwards — long (Gasoline)
    168,731       94.00             15,861       16,535       674  
Forwards — short (Gasoline)
    (25,000 )           98.46       (2,461 )     (2,519 )     (58 )
Forwards — short (Slurry)
    (36,999 )           69.71       (2,579 )     (2,628 )     (49 )
Forwards — long (Catfeed)
    9,641       91.54             883       919       36  
Forwards — short (Slop)
    (10,976 )           79.23       (870 )     (893 )     (23 )
Forwards — long (Diesel)
    299,229       100.99             30,219       31,257       1,038  
Forwards — short (Diesel)
    (50,012 )           101.03       (5,053 )     (5,218 )     (165 )
Futures — short (Gasoline)
    (22,000 )           106.06       (2,188 )     (2,334 )     (146 )

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    Contract Volume     Wtd Avg     Wtd Avg                    
Description of Activity   (in barrels)     Contract Spread     Market Spread     Contract Value     Fair Value     Gain (Loss)  
                            (in thousands)  
                             
Futures — swaps (Heating Oil)
    218,800       11.38       8.26     $ 2,489     $ 1,808     $ (681 )
Futures — calls (Heating oil)
    (3,008,500 )     13.43       14.49       (40,394 )     (43,581 )     (3,187 )
Interest Rate Risk
     As of December 31, 2010, $608.2 million of our outstanding debt was at floating interest rates out of which approximately $122.0 million was at the Eurodollar rate plus 3.00%, subject to a minimum interest rate of 4.00%. As of December 31, 2010, we had an interest rate swap agreement with a notional amount of $100.0 million with a remaining period of 24 months and a fixed interest rate of 4.25%. An increase of 1% in the Eurodollar rate on floating rate indebtedness net of the instrument subject to the minimum interest rate would result in an increase in our interest expense of approximately $5.2 million per year.
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 furnish under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or furnish under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures.
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 Exchange Act) for Alon. Our management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2010. In management’s evaluation, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Management believes that as of December 31, 2010, our internal control over financial reporting was effective based on those criteria.
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, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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.
ITEM 9B. OTHER INFORMATION.
     In February 2011, Alon Brands issued 5-year unsecured notes for $30.0 million to a group of investors, including Alon Israel. In connection with the issuance of the unsecured notes, these investors were given warrants to invest up to $30.0 million in the aggregate in Alon and Alon Brands. Pursuant to the warrant agreements entered into in March 2011, Alon issued to the investors warrants to purchase 3,082,783 shares of Alon’s common stock at an initial exercise price of $9.70, which is equal to the amount that is 18% over the average reported closing price of a share of Alon’s common stock on the New York Stock Exchange during the forty-five calendar days immediately preceding February 21, 2011, the date of entry into the agreements. The investors may pay the exercise price of the warrants in cash or may exercise the warrants on a net-issuance basis. The warrants are assignable to affiliates of the investors and exercisable immediately and at any time through March 2016. Any or all of the warrants may be exchanged only prior to Alon Brands initial public offering for warrants to purchase shares of the common stock of Alon Brands.
     The warrants were offered and sold in reliance on the exemption from registration set forth in Section 4(2) of the Securities Act. Alon determined that such exemption was and is available based on representations of the investors and information available to Alon to the effect that each of the investors is sophisticated within the meaning of Section 4(2) of the Securities Act among other factors. In addition, the issuances of the warrants did not involve any public offering; Alon made no solicitation in connection with the sale other than communications with the investors; and Alon has taken necessary steps to ensure that the warrants and the shares issuable upon exercise of the warrants are offered for resale or resold only pursuant to an effective registration statement or in a transaction that is exempt from the registration requirements of the Securities Act.
     In connection with the issuance of the warrants, Alon also entered into a registration rights agreement with certain of the investors (the “Registration Rights Agreement”) pursuant to which Alon agreed to register the offer and sale of such investors’ warrant shares in up to two separate demand registrations and, for a period of seven years, pursuant to registration statements on Form S-3, provided the minimum amount that will be registered by means of any such registration is $3.0 million. The Registration Rights Agreement also provides certain rights for the investors to include their warrant shares in other registrations of securities by Alon.

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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
     The information concerning our directors set forth under “Corporate Governance Matters — The Board of Directors” in the proxy statement for our 2011 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, AND DIRECTOR INDEPENDENCE.
     The information set forth under “Certain Relationships and Related Transactions” and under “Corporate Governance Matters — Independent Directors” 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.
(a)   Schedule II — Valuation and Qualifying accounts is included in the Notes to Consolidated Financial Statements.
(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 and 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).
 
   
4.2
  Specimen 8.50% Series A Convertible Preferred Stock Certificate. (incorporated by reference to Exhibit 4.4 to Form 10-Q, filed by the Company on November 9, 2010).
 
   
4.3
  Indenture, dated as of October 22, 2009, by and among Alon Refining Krotz Springs, Inc. and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K, filed by the Company on October 23, 2009, SEC File No. 001-32567).
 
   
4.4
  Form of Certificate of Designation of the 8.75% Series A Convertible Preferred Stock (incorporated by reference to Exhibit 4.3 to Form 10-Q filed by Alon on November 9, 2010, SEC File No. 001-32567).
 
   
10.1
  Trademark License Agreement, dated as of July 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).
 
   
10.2
  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).
 
   
10.3
  Pipeline Lease Agreement, dated as of December 12, 2007, between Plains Pipeline, L.P. and Alon USA, L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on February 2, 2008, SEC File No. 001-32567).
 
   
10.4
  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).
 
   
10.5
  Amendment and Supplement to Pipeline Lease Agreement, dated as of August 31, 2007, by and between HEP Pipeline Assets, Limited Partnership and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on November 8, 2007).
 
   
10.6
  Contribution Agreement, dated as of January 25, 2005, among Holly Energy Partners, L.P., Holly Energy Partners —Operating, L.P., T & R Assets, Inc., Fin-Tex Pipe Line Company, Alon USA Refining, Inc., Alon Pipeline Assets, LLC, Alon Pipeline Logistics, LLC, Alon USA, Inc. and Alon USA, LP (incorporated by reference to Exhibit 10.7 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).

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Exhibit No.   Description of Exhibit
10.7
  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).
 
   
10.8
  Pipeline Lease Agreement, dated as of December 12, 2007, between Plains Pipeline, L.P. and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on February 5, 2008, SEC File No. 001-32567).
 
   
10.9
  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).
 
   
10.10
  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).
 
   
10.11
  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).
 
   
10.12
  Registration Rights Agreement, dated October 22, 2009, between Alon Refining Krotz Springs, Inc. and Jefferies & Company, Inc. (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on October 23, 2009, SEC File No. 001-32567).
 
   
10.13
  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).
 
   
10.14
  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 (incorporated by reference to Exhibit 10.25 to Form 10-K, filed by the Company on March 15, 2007 SEC File No. 001-32567).
 
   
10.15
  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).
 
   
10.16
  Third Amendment to Amended Revolving Credit Agreement, dated as of June 29, 2007, to the Amended Revolving Credit Agreement, dated as of June 22, 2006, among Alon USA Energy, Inc., 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 July 20, 2007, SEC File No. 001-32567).
 
   
10.17
  Waiver, Consent, Partial Release and Fourth Amendment, dated as of July 2, 2008, by and among Alon USA, LP, 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 10.4 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
 
   
10.18
  Fifth Amendment to Amended Revolving Credit Agreement, dated as of July 31, 2009, by and among Alon USA, LP, 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 10.3 to Form 10-Q, filed by the Company on August 6, 2009, SEC File No. 001-32567).
 
   

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Exhibit No.   Description of Exhibit
10.19
  Sixth Amendment to Amended Revolving Credit Agreement, dated as of May 10, 2010, by and among Alon USA, LP, 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 10.1 to Form 10-Q, filed by the Company on May 10, 2010, SEC File No. 001-32567).
 
   
10.20
  Seventh Amendment to Amended Revolving Credit Agreement, dated as of June 1, 2010, by and among Alon USA, LP, 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 10.1 to Form 10-Q, filed by the Company on August 9, 2010, SEC File No. 001-32567).
 
   
10.21
  Eighth Amendment to Amended Revolving Credit Agreement, dated as of June 16, 2010, by and among Alon USA, LP, 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 10-Q, filed by the Company on August 9, 2010, SEC File No. 001-32567).
 
   
10.22
  Ninth Amendment to Amended Revolving Credit Agreement, dated as of February 22, 2011, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein.
 
   
10.23
  Revolving Credit Line Agreement, dated March 9, 2010, by and between Alon and Israel Discount Bank of New York (incorporated by reference to Exhibit 10.96 to Form 10-K, filed by the Company on March 16, 2010, SEC File No. 001-32567).
 
   
10.24
  Amendment and Waiver, dated February 24, 2011, to Revolving Credit Line Agreement, dated March 9, 2001, among Alon and Israel Discount Bank of New York.
 
   
10.25
  Credit Agreement, dated March 15, 2010 (as amended, supplemented or otherwise modified from time to time), among Alon Refining Krotz Springs, Inc., each other party joined as a borrower thereunder from time to time, the Lenders party thereto, and Bank Hapoalim B.M., as Administrative Agent (incorporated by reference to Exhibit 10.97 to Form 10-K, filed by the Company on March 16, 2010, SEC File No. 001-32567).
 
   
10.26
  Amendment No. 1 to Credit Agreement, dated May 28, 2010 (as amended, supplemented or otherwise modified from time to time), among Alon Refining Krotz Springs, Inc., each other party joined as a borrower thereunder from time to time, the Lenders party thereto, and Bank Hapoalim B.M., as Administrative Agent (incorporated by reference to Exhibit 10.3 to Form 10-Q, filed by the Company on August 9, 2010, SEC File No. 001-32567).
 
   
10.27
  Amendment No. 2 to Credit Agreement, dated June 15, 2010 (as amended, supplemented or otherwise modified from time to time), among Alon Refining Krotz Springs, Inc., each other party joined as a borrower thereunder from time to time, the Lenders party thereto, and Bank Hapoalim B.M., as Administrative Agent (incorporated by reference to Exhibit 10.4 to Form 10-Q, filed by the Company on August 9, 2010, SEC File No. 001-32567).
 
   
10.28
  Amendment No. 3 to Credit Agreement, dated August 11, 2010 (as amended, supplemented or otherwise modified from time to time), among Alon Refining Krotz Springs, Inc., each other party joined as a borrower thereunder from time to time, the Lenders party thereto, and Bank Hapoalim B.M., as Administrative Agent (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on August 13, 2010, 2010, SEC File No. 001-32567).
 
   
10.29
  Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc. and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.5 to Form 10-Q, filed by the Company on August 9, 2010, SEC File No. 001-32567).
 
   

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Exhibit No.   Description of Exhibit
10.30
  Amended and Restated Credit Agreement, dated as of December 30, 2010, among Southwest Convenience Stores, LLC, Skinny’s, LLC, the lenders party thereto and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 6, 2011, SEC File No. 001-32567).
 
   
10.31
  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).
 
   
10.32
  Amendment No. 1 to the Credit Agreement, dated as of February 28, 2007, by and among Alon USA Energy, Inc., the lenders party thereto and Credit Suisse (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on March 5, 2007, SEC File No. 001-32567).
 
   
10.33
  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).
 
   
10.34
  First Amendment to Second Amended and Restated Credit Agreement, dated as of March 30, 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 10.37 to Form 10-K, filed by the Company on March 11, 2008, SEC File No. 001-32567).
 
   
10.35
  Term Loan Agreement, dated as of July 3, 2008, by and among Alon Refining Louisiana, Inc., Alon Refining Krotz Springs, Inc., the lenders party thereto and Credit Suisse, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
 
   
10.36
  First Amendment Agreement, dated as of April 9, 2009, by and among Alon Refining Louisiana, Inc., Alon Refining Krotz Springs, Inc., the lenders party thereto and Wells Fargo Bank, National Association, as successor to Credit Suisse, Cayman Islands Branch, as agent (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on August 6, 2009, SEC File No. 001-32567).
 
   
10.37
  Loan and Security Agreement, dated as of July 3, 2008, by and among Alon Refining Louisiana, Inc., Alon Refining Krotz Springs, Inc., the lenders party thereto and Bank of America, N.A., as administrative agent (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
 
   
10.38
  First Amendment to Loan and Security Agreement, dated as of December 18, 2008, by and among Alon Refining Louisiana, Inc., Alon Refining Krotz Springs, Inc., the lenders party thereto and Bank of America, N.A. (incorporated by reference to Exhibit 10.28 to Form 10-K, filed by the Company on April 10, 2009, SEC File No. 001-32567).
 
   
10.39
  Second Amendment to Loan and Security Agreement, dated as of April 9, 2009, by and among Alon Refining Louisiana, Inc., Alon Refining Krotz Springs, Inc., the lenders party thereto and Bank of America, N.A., as agent (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on April 27, 2009, SEC File No. 001-32567).
 
   
10.40
  Amended and Restated Loan and Security Agreement, dated as of October 22, 2009 (as amended, supplemented or otherwise modified from time to time), among Alon Refining Louisiana, Inc., Alon Refining Krotz Springs, Inc., each other party joined as a borrower thereunder from time to time, the Lenders party thereto, and Bank of America, N.A., as Agent (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on October 23, 2009, SEC File No. 001-32567).
 
   
10.41
  Purchase Agreement, dated October 13, 2009, between Alon Refining Krotz Springs, Inc. and Jefferies & Co. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on October 19, 2009, SEC File No. 001-32567).
 
   

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Exhibit No.   Description of Exhibit
10.42
  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).
 
   
10.43
  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).
 
   
10.44*
  Executive Employment Agreement, dated as of July 31, 2000, between Jeff D. Morris and Alon USA GP, Inc., as amended by the Amendment to Executive/Management Employment Agreement, dated May 1, 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).
 
   
10.45*
  Second Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon USA GP, LLC (incorporated by reference to Exhibit 10.9 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
 
   
10.46*
  Management Employment Agreement, dated as of March 1, 2010, between Paul Eisman and Alon USA GP, LLC.
 
   
10.47*
  Executive Employment Agreement, dated as of July 31, 2000, between Claire A. Hart and Alon USA GP, Inc., as amended by the Amendment to Executive/Management Employment Agreement, dated May 1, 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).
 
   
10.48*
  Second Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Claire A. Hart and Alon USA GP, LLC (incorporated by reference to Exhibit 10.10 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
 
   
10.49*
  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).
 
   
10.50*
  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).
 
   
10.51*
  Second Amendment to Executive/Management Employment Agreement, dated as of November 4, 2008, between Yosef Israel and Alon USA GP, LLC (incorporated by reference to Exhibit 10.13 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
 
   
10.52*
  Executive Employment Agreement, dated as of August 1, 2003, between Shai Even and Alon USA GP, LLC (incorporated by reference to Exhibit 10.49 to Form 10-K, filed by the Company on March 15, 2007, SEC File No. 001-32567).
 
   
10.53*
  Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Shai Even and Alon USA GP, LLC. (incorporated by reference to Exhibit 10.14 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
 
   
10.54*
  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).
 
   
10.55*
  Management Employment Agreement, dated as of October 30, 2008, between Michael Oster and Alon USA GP, LLC (incorporated by reference to Exhibit 10.71 to Form 10-K, filed by the Company on April 10, 2009, SEC File No. 001-32567).
 
   
10.56*
  Description of Annual Bonus Plans.
 
   
10.57*
  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).
 
   
10.58*
  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).
 
   

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Exhibit No.   Description of Exhibit
10.59*
  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).
 
   
10.60*
  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).
 
   
10.61*
  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).
 
   
10.62*
  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).
 
   
10.63*
  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).
 
   
10.64*
  Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended by the Amendment to the Incentive Stock Option Agreement, dated 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).
 
   
10.65*
  Second Amendment to Incentive Stock Option Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon Assets, Inc. (incorporated by reference to Exhibit 10.15 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
 
   
10.66
  Shareholder Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended by the Amendment to the Shareholder Agreement, dated 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).
 
   
10.67*
  Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Jeff D. Morris, as amended by the Amendment to the Incentive Stock Option Agreement, dated 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).
 
   
10.68*
  Second Amendment to Incentive Stock Option Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon USA Operating, Inc. (incorporated by reference to Exhibit 10.16 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
 
   
10.69
  Shareholder Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Jeff D. Morris, as amended by the Amendment to the Shareholder Agreement, dated 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).
 
   
10.70*
  Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.42 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
 
   
10.71
  Shareholder Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended by the Amendment to the Shareholder Agreement, dated 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).
 
   
10.72*
  Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended by the Amendment to the Incentive Stock Option Agreement, dated 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).
 
   

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Exhibit No.   Description of Exhibit
10.73
  Shareholder Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended by the Amendment to the Shareholder Agreement, dated 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).
 
   
10.74*
  Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III, as amended by the Amendment to the Incentive Stock Option Agreement, dated 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).
 
   
10.75
  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).
 
   
10.76*
  Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III, as amended by the Amendment to the Incentive Stock Option Agreement, dated 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).
 
   
10.77
  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).
 
   
10.78
  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).
 
   
10.79*
  Alon USA Energy, Inc. Amended and Restated 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 7, 2010, SEC File No. 001-32567).
 
   
10.80*
  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).
 
   
10.81*
  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).
 
   
10.82*
  Form II of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on November 8, 2005, SEC File No. 001-32567).
 
   
10.83*
  Form of Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 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 March 12, 2007, SEC File No. 001-32567).
 
   
10.84*
  Form of Amendment to Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on January 27, 2010, SEC File No. 001-32567).
 
   
10.85*
  Form II of Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 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 January 27, 2010, SEC File No. 001-32567).
 
   
10.86
  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).
 
   

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Exhibit No.   Description of Exhibit
10.87
  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).
 
   
10.88
  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).
 
   
10.89
  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).
 
   
10.90
  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).
 
   
10.91
  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).
 
   
10.92
  Stock Purchase Agreement, dated May 7, 2008, between Valero Refining and Marketing Company and Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 13, 2008, SEC File No. 001-32567).
 
   
10.93
  First Amendment to Stock Purchase Agreement, dated as of July 3, 2008, by and among Valero Refining and Marketing Company, Alon Refining Krotz Springs, Inc. and Valero Refining Company-Louisiana (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
 
   
10.94
  Series A Preferred Stock Purchase Agreement, dated as of July 3, 2008, by and between Alon Refining Louisiana, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
 
   
10.95
  Stockholders Agreement, dated as of July 3, 2008, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
 
   
10.96
  Amended and Restated Stockholders Agreement dated as of March 31, 2009, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.88 to Form 10-K, filed by the Company on April 10, 2009, SEC File No. 001-32567).
 
   
10.97†
  First Amendment to Amended and Restated Stockholders Agreement dated as of December 31, 2009, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 5, 2010, SEC File No. 001-32567).
 
   
10.98†
  Offtake Agreement, dated as of July 3, 2008, by and between Valero Marketing and Supply Company and Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 10.9 to Form 10-Q, filed by the Company on August 8, 2008, SEC File No. 001-32567).
 
   

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Exhibit No.   Description of Exhibit
10.99†
  Earnout Agreement, dated as of July 3, 2008, by and between Valero Refining and Marketing Company and Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 10.10 to Form 10-Q, filed by the Company on August 8, 2008, SEC File No. 001-32567).
 
   
10.100†
  First Amendment to Earnout Agreement, dated as of August 27, 2009, by and between Valero Refining and Marketing Company and Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on November 6, 2009, SEC No. 001-32567).
 
   
10.101
  Amended and Restated Supply and Offtake Agreement, dated May 28, 2010 by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.6 to Form 10-Q, filed by the Company on August 9, 2010, SEC File No. 001-32567).
 
   
10.102
  Form of Series A Convertible Preferred Stock Purchase Agreement (incorporated by reference to Exhibit 10.105 to Form S-1/A, filed by the Company on October 22, 2010, SEC File No. 333-169583).
 
   
10.103
  Standby Equity Distribution Agreement, dated as of January 20, 2011, among Alon USA Energy, Inc. and YA Global Master SPV, Ltd. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 24, 2011, SEC File No. 001-32567).
 
   
10.104
  Warrant Agreement, dated March 10, 2011, between the Company, FIMI Opportunity IV, L.P and FIMI Israel Opportunity IV, Limited Partnership.
 
   
10.105
  Warrant Agreement, dated March 10, 2011, between the Company, FIMI Opportunity IV, L.P and FIMI Israel Opportunity IV, Limited Partnership.
10.106
  Warrant Agreement, dated March 14, 2011, between the Company and Alon Israel Oil Company, Ltd.
 
   
10.107
  Registration Rights Agreement, dated as of March 10, 2011, between Alon USA Energy, Inc., FIMI Opportunity IV L.P., and FIMI Israel Opportunity IV, Limited Partnership.
 
   
12.1
  Statement Regarding Computation of Ratio of Earnings to Fixed Charges.
 
   
21.1
  Subsidiaries of Alon USA Energy, Inc.
 
   
23.1
  Consent of KPMG LLP.
 
   
31.1
  Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2
  Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1
  Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
 
*   Identifies management contracts and compensatory plans or arrangements.
 
  Filed under confidential treatment request.

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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, 2010 and 2009, 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, 2010. 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 auditing standards of the Public Company 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 its subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Alon USA Energy, Inc.’s internal control over financial reporting as of December 31, 2010 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring organizations of Treadway commission (COSO), and our report dated March 14, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
         
     
  /s/ KPMG LLP    
Dallas, Texas
March 14, 2011

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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Alon USA Energy, Inc.:
We have audited Alon USA Energy, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Alon USA Energy, Inc.’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, included in the accompanying Management’s Report on Internal control over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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, Alon USA Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
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, 2010 and 2009, 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, 2010, and our report dated March 14, 2011 expressed an unqualified opinion on those consolidated financial statements.
         
     
  /s/ KPMG LLP    
Dallas, Texas
March 14, 2011

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ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands except share data)
                 
    As of December 31,  
    2010     2009  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 71,687     $ 40,437  
Accounts and other receivables, net
    115,541       103,094  
Income tax receivable
    8,642       65,418  
Inventories
    141,050       214,999  
Deferred income tax asset
    49,052       7,700  
Prepaid expenses and other current assets
    7,875       4,188  
 
           
Total current assets
    393,847       435,836  
 
           
Equity method investments
    18,664       43,052  
Property, plant, and equipment, net
    1,488,532       1,477,426  
Goodwill
    105,943       105,943  
Other assets
    81,535       70,532  
 
           
Total assets
  $ 2,088,521     $ 2,132,789  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
 
               
Current liabilities:
               
Accounts payable
  $ 292,991     $ 248,253  
Accrued liabilities
    88,354       92,380  
Current portion of long-term debt
    11,512       10,946  
 
           
Total current liabilities
    392,857       351,579  
 
           
Long-term debt
    904,793       926,078  
Other non-current liabilities
    160,976       95,076  
Deferred income tax liability
    288,128       328,138  
 
           
Total liabilities
    1,746,754       1,700,871  
 
           
Commitments and contingencies (Note 21)
               
Stockholders’ equity:
               
Preferred stock, par value $0.01, 10,000,000 shares authorized; 4,000,000 shares issued and outstanding at December 31, 2010
    40,000        
Common stock, par value $0.01, 100,000,000 shares authorized; 54,281,636 and 54,170,913 shares issued and outstanding at December 31, 2010 and 2009, respectively
    543       542  
Additional paid-in capital
    290,809       289,853  
Accumulated other comprehensive loss, net of income tax
    (21,917 )     (32,871 )
Retained earnings
    33,052       165,248  
 
           
Total stockholders’ equity
    342,487       422,772  
 
           
Non-controlling interest in subsidiaries
    (720 )     9,146  
 
           
Total equity
    341,767       431,918  
 
           
Total liabilities and equity
  $ 2,088,521     $ 2,132,789  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands except per share data)
                         
    Year Ended December 31,  
    2010     2009     2008  
Net sales (1)
  $ 4,030,743     $ 3,915,732     $ 5,156,706  
Operating costs and expenses:
                       
Cost of sales
    3,703,416       3,502,782       4,853,195  
Direct operating expenses
    249,933       265,502       216,498  
Selling, general and administrative expenses
    128,082       129,446       119,852  
Unrealized loss associated with consignment inventory
    8,942              
Net costs associated with fire
                56,854  
Business interruption recovery
                (55,000 )
Depreciation and amortization
    102,096       97,247       66,754  
 
                 
Total operating costs and expenses
    4,192,469       3,994,977       5,258,153  
 
                 
Gain on involuntary conversion of assets
                279,680  
Gain (loss) on disposition of assets
    945       (1,591 )     45,244  
 
                 
Operating income (loss)
    (160,781 )     (80,836 )     223,477  
Interest expense
    (94,939 )     (111,137 )     (67,550 )
Equity earnings (losses) of investees
    5,439       24,558       (1,522 )
Gain on bargain purchase
    17,480              
Other income, net
    9,716       331       1,500  
 
                 
Income (loss) before income tax expense (benefit), non-controlling interest in income (loss) of subsidiaries, and accumulated dividends on preferred stock of subsidiary
    (223,085 )     (167,084 )     155,905  
Income tax expense (benefit)
    (90,512 )     (64,877 )     62,781  
 
                 
Income (loss) before non-controlling interest in income (loss) of subsidiaries and accumulated dividends on preferred stock of subsidiary
    (132,573 )     (102,207 )     93,124  
Non-controlling interest in income (loss) of subsidiaries
    (9,641 )     (8,551 )     5,941  
Accumulated dividends on preferred stock of subsidiary
          21,500       4,300  
 
                 
Net income (loss) available to common stockholders
  $ (122,932 )   $ (115,156 )   $ 82,883  
 
                 
Earnings (loss) per share, basic
  $ (2.27 )   $ (2.46 )   $ 1.77  
 
                 
Weighted average shares outstanding, basic (in thousands)
    54,186       46,829       46,788  
 
                 
Earnings (loss) per share, diluted
  $ (2.27 )   $ (2.46 )   $ 1.72  
 
                 
Weighted average shares outstanding, diluted (in thousands)
    54,186       46,829       49,583  
 
                 
Cash dividends per share
  $ 0.16     $ 0.16     $ 0.16  
 
                 
 
(1)   Includes excise taxes on sales by the retail and branded marketing segment of $54,930, $47,137 and $37,483 for the years ended December 31, 2010, 2009, and 2008, respectively.
The accompanying notes are an integral part of these consolidated financial statements.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(dollars in thousands)
                                                                 
                            Accumulated Other                            
                    Additional Paid-In     Comprehensive             Total Stockholders’     Non-controlling        
    Common Stock     Preferred Stock     Capital     Income (Loss)     Retained Earnings     Equity     Interest (1)     Total Equity  
Balance at December 31, 2007
  $ 468     $     $ 182,932     $ (7,700 )   $ 212,502     $ 388,202     $ 15,720     $ 403,922  
Stock compensation expense
                710                   710       (1,062 )     (352 )
Dividends
                            (7,490 )     (7,490 )     (386 )     (7,876 )
Sale of preferred stock by subsidiary (1)
                                        80,000       80,000  
Income before non-controlling interest in income of subsidiaries and accumulated
dividends on preferred stock of subsidiary (1)
                            82,883       82,883       10,241       93,124  
Other comprehensive income (loss):
                                                               
Defined benefit pension plans, net of tax of $8,780
                      (13,481 )           (13,481 )     (1,044 )     (14,525 )
Fair value of commodity derivative contracts, net of tax of $677
                      (1,071 )           (1,071 )     (83 )     (1,154 )
Fair value of interest rate swaps, net of tax of $6,828
                      (15,102 )           (15,102 )     (1,170 )     (16,272 )
 
                                                         
Total comprehensive income
                                            53,229       7,944       61,173  
 
                                               
Balance at December 31, 2008
    468             183,642       (37,354 )     287,895       434,651       102,216       536,867  
Stock compensation expense
                485                   485       17       502  
Dividends
                            (7,491 )     (7,491 )     (576 )     (8,067 )
Conversion of preferred stock of subsidiary for common stock
    74             105,726                   105,800       (105,800 )      
Income (loss) before non-controlling interest in income (loss) of subsidiaries and
accumulated dividends on preferred stock of subsidiary (1)
                            (115,156 )     (115,156 )     12,949       (102,207 )
Other comprehensive income (loss):
                                                               
Defined benefit pension plans, plus tax of $887
                      2,110             2,110       162       2,272  
Fair value of commodity derivative contracts, net of tax of $2,000
                      (3,166 )           (3,166 )     (243 )     (3,409 )
Fair value of interest rate swaps, net of tax of $3,207
                      5,539             5,539       421       5,960  
 
                                                         
Total comprehensive income (loss)
                                            (110,673 )     13,289       (97,384 )
 
                                               
Balance at December 31, 2009
    542             289,853       (32,871 )     165,248       422,772       9,146       431,918  
Stock compensation expense
                575                   575       4       579  
Dividends
                            (9,264 )     (9,264 )     (593 )     (9,857 )
Dividends of common stock on preferred stock
    1             512                   513             513  
Equity contribution from parent
                138                   138             138  
Preferred stock issuance
          40,000       (269 )                 39,731             39,731  
Income (loss) before non-controlling interest in income (loss) of subsidiaries
                            (122,932 )     (122,932 )     (9,641 )     (132,573 )
Other comprehensive income (loss):
                                                               
Defined benefit pension plans, net of tax of $668
                      691             691             691  
Fair value of commodity derivative contracts, net of tax of $2,678
                      4,209             4,209       287       4,496  
Fair value of interest rate swaps, net of tax of $3,292
                      6,054             6,054       77       6,131  
 
                                                         
Total comprehensive income (loss)
                                            (111,978 )     (9,277 )     (121,255 )
 
                                               
Balance at December 31, 2010
  $ 543     $ 40,000     $ 290,809     $ (21,917 )   $ 33,052     $ 342,487     $ (720 )   $ 341,767  
 
                                               
 
(1)   Includes $80,000 in sale of preferred stock by subsidiary in connection with the Krotz Springs refinery acquisition in July 2008 and accumulated dividends of $21,500 and $4,300 through December 31, 2009 and 2008, respectively.
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,  
    2010     2009     2008  
Cash flows from operating activities:
                       
Net income (loss) available to common stockholders
  $ (122,932 )   $ (115,156 )   $ 82,883  
Adjustments to reconcile net income (loss) available to common stockholders to cash provided by (used in) operating activities:
                       
Depreciation and amortization
    102,096       97,247       66,754  
Stock compensation
    579       502       173  
Deferred income tax expense (benefit)
    (98,595 )     (5,451 )     177,797  
Non-controlling interest in income (loss) of subsidiaries
    (9,641 )     (8,551 )     5,941  
Accumulated dividends on preferred stock of subsidiary
          21,500       4,300  
Equity (earnings) losses of investees (net of dividends)
          (5,391 )     4,296  
Amortization of debt issuance costs
    5,825       7,112       4,128  
Amortization of original issuance discount
    1,685       328        
Write-off of unamortized debt issuance costs
    6,659       20,482        
Mark-to-market of heating oil hedge
                (117,452 )
Gain on involuntary conversion of assets
                (279,680 )
Bargain purchase gain
    (17,480 )            
(Gain) loss on disposition of assets
    (945 )     1,591       (45,244 )
Changes in operating assets and liabilities, net of acquisition effects:
                       
Accounts and other receivables, net
    (8,325 )     67,357       59,336  
Income tax receivable
    56,777       51,146       (81,320 )
Inventories
    91,293       17,321       213,373  
Heating oil crack spread hedge
          117,485        
Prepaid expenses and other current assets
    2,444       2,164       5,933  
Other assets
    (21,501 )     5,992       (5,264 )
Accounts payable
    (3,277 )     40,892       (108,458 )
Accrued liabilities
    6,768       (25,197 )     17,419  
Other non-current liabilities
    29,900       (8,228 )     (5,727 )
 
                 
Net cash provided by (used in) operating activities
    21,330       283,145       (812 )
 
                 
Cash flows from investing activities:
                       
Capital expenditures
    (46,707 )     (81,660 )     (62,356 )
Capital expenditures to rebuild the Big Spring refinery
          (46,769 )     (362,178 )
Capital expenditures for turnarounds and catalysts
    (13,131 )     (24,699 )     (9,958 )
Proceeds from insurance to rebuild the Big Spring refinery
          34,125       270,885  
Dividends from investees, net of equity earnings
    1,242              
Proceeds from disposition of assets
    21,978             7,000  
Proceeds from sale of securities
    36,852              
Earnout payments related to Krotz Springs refinery acquisition
    (8,750 )     (19,688 )      
Sale of short-term investments, net
                27,296  
Acquisition of Bakersfield refinery
    (32,409 )            
Acquisition of Krotz Springs refinery
                (481,011 )
 
                 
Net cash used in investing activities
    (40,925 )     (138,691 )     (610,322 )
 
                 
Cash flows from financing activities:
                       
Dividends paid to non-controlling interest shareholders
    (593 )     (576 )     (386 )
Dividends paid to shareholders
    (8,751 )     (7,491 )     (7,490 )
Proceeds from sale of preferred stock
    40,000              
Proceeds from sale of preferred stock by subsidiary
                80,000  
Cash received from inventory supply agreement
    45,807       20,237        
Deferred debt issuance costs
    (2,946 )     (17,768 )     (28,105 )
Preferred stock issuance costs
    (269 )            
Revolving credit facilities, net
    (21,458 )     (60,241 )     276,818  
Additions to long-term debt
    10,000       205,365       252,000  
Payments on long-term debt
    (10,945 )     (261,997 )     (11,864 )
 
                 
Net cash provided by (used in) financing activities
    50,845       (122,471 )     560,973  
 
                 
Net increase (decrease) in cash and cash equivalents
    31,250       21,983       (50,161 )
Cash and cash equivalents, beginning of period
    40,437       18,454       68,615  
 
                 
Cash and cash equivalents, end of period
  $ 71,687     $ 40,437     $ 18,454  
 
                 
The accompanying notes are an integral part of these consolidated financial statements.

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    Year Ended December 31,  
    2010     2009     2008  
Supplemental cash flow information:
                       
Cash paid for interest, net of capitalized interest
  $ 84,467     $ 87,164     $ 58,504  
 
                 
Cash (received) paid for income tax, net of refunds
  $ (48,363 )   $ (111,791 )   $ (30,334 )
 
                 
Non-cash activities:
                       
Financing activity — payments on long-term debt from deposit held to secure heating oil crack spread hedge
  $     $ (50,000 )   $  
 
                 
Financing activity — proceeds from borrowings retained by bank as deposit for hedge related activities for Krotz Springs refinery acquisition
  $     $     $ 50,000  
 
                 
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: (i) refining and unbranded marketing, (ii) asphalt and (iii) retail and branded marketing.
     Refining and Unbranded Marketing Segment. Our refining and unbranded marketing segment includes sour and heavy crude oil refineries that are located in Big Spring, Texas; and Paramount, Bakersfield and Long Beach, California; and a light sweet crude oil refinery located in Krotz Springs, Louisiana. We refer to the Paramount, Bakersfield and Long Beach refineries together as our “California refineries.” Our refineries have a combined throughput capacity of approximately 240,000 barrels per day (“bpd”). At our refineries we refine crude oil into petroleum products, including gasoline, diesel fuel, jet fuel, petrochemicals, feedstocks and asphalts, which are marketed primarily in the South Central, Southwestern, and Western United States.
     Alon markets transportation fuels 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 retail and branded marketing segment convenience stores 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.
     Alon markets refined products produced from our California refineries to wholesale distributors, other refiners and third parties primarily on the West Coast. Alon plans to integrate the Bakersfield hydrocracker unit by processing vacuum gas oil produced at the other California locations.
     The Krotz Springs refinery supplies multiple demand centers in the Southern and Eastern United States markets through the Colonial products pipeline system. The Krotz Springs refinery processing units are structured to yield approximately 101.5% of total feedstock input, meaning that for each 100 barrels of crude oil and feedstocks input into the refinery, it produces 101.5 barrels of refined products. Of the 101.5%, on average 99.0% is light finished products such as gasoline and distillates, including diesel and jet fuel, petrochemical feedstocks and liquefied petroleum gas, and the remaining 2.5% is primarily heavy oils.
     Asphalt Segment. Alon’s asphalt segment markets asphalt produced at its Big Spring and California refineries included in the refining and unbranded marketing segment and at our Willbridge, Oregon refinery. Asphalt produced by the refineries in our refining and unbranded marketing segment is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. 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), Arizona (Phoenix, Flagstaff and Fredonia), and Nevada (Fernley) (50% interest) as well as a 50% interest in Wright Asphalt Products Company, LLC (“Wright”). We produce both paving and roofing grades of asphalt, including performance-graded asphalts, emulsions and cutbacks.
     Retail and Branded Marketing Segment. Our retail and branded marketing segment operates 304 convenience stores primarily in Central and 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, primarily under the 7-Eleven and FINA brand names. Substantially all of the motor fuel sold through our retail operations and the majority of the motor fuel marketed in our branded business is supplied by our Big Spring refinery. In 2010, approximately 91% of the motor fuel requirements of our branded marketing operations, including retail operations,

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
(dollars in thousands except as noted)
were supplied by our Big Spring refinery. Our convenience stores that are not part of our integrated supply system, primarily in Central Texas, are supplied with motor fuels we obtain from third-party suppliers. We market gasoline and diesel under the FINA brand name through a network of approximately 630 locations, including our convenience stores. Additionally, our retail and branded marketing segment licenses the use of the FINA brand name and provides credit card processing services to approximately 260 licensed locations that are not under fuel supply agreements.
(2) Summary of Significant Accounting Policies
     (a) Basis of Presentation
     The consolidated financial statements include the accounts of Alon USA Energy, Inc. and its subsidiaries. All significant intercompany balances and transactions have been eliminated.
     (b) Use of Estimates
     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
     (c) Revenue Recognition
     Revenues from sales of refined products are earned and realized upon transfer of title to the customer based on the contractual terms of delivery (including payment terms and prices). Title primarily transfers at the refinery or terminal when the refined product is loaded into the common carrier pipelines, trucks or railcars (free on board origin). In some situations, title transfers at the customer’s destination (free on board destination).
     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. 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.
     In the ordinary course of business, logistical and refinery production schedules necessitate the occasional sale of crude oil to third parties. All purchases and sales of crude oil are recorded net, in cost of sales in the consolidated statements of operations.
     Sulfur credits purchased to meet federal gasoline sulfur regulations are recorded in inventory at the lower of cost or market. Cost is computed on an average cost basis. Purchased sulfur credits are removed from inventory and charged to cost of sales in the consolidated statements of operations as they are utilized. Sales of excess sulfur credits are recognized in earnings and included in net sales in the consolidated statements of operations.
     Alon’s present excise taxes on sales by Alon’s retail and branded marketing segment is presented on a gross basis with supplemental information regarding the amount of such taxes included in revenues provided in a footnote on the face of the consolidated statements of operations. All other excise taxes are presented on a net basis in the consolidated statements of operations.
     (d) Cost Classifications
     Refining and unbranded 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 and branded marketing 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

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
(dollars in thousands except as noted)
and commissions. Cost of sales excludes depreciation and amortization, which is presented separately in the consolidated statements of operations.
     Direct operating expenses, which relate to Alon’s refining and unbranded marketing and asphalt segments, include costs associated with the actual operations of the refineries and terminals, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs. Operating costs associated with Alon’s crude oil and product pipelines are considered to be transportation costs and are reflected in cost of sales in the 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 unbranded 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, financing costs associated with crude oil purchases, and fees, amortization of deferred debt issuance costs and the write-off of unamortized debt issuance costs but excludes 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) Accounts Receivable
     The majority of accounts receivable is 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. Reserve for bad debts is based on a combination of current sales and specific identification methods.
     (g) Inventories
     Crude oil, refined products and blendstocks for the refining and unbranded marketing segment and asphalt for the asphalt segment (including inventory consigned to others) 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 and branded marketing segment merchandise inventories is determined under the retail inventory method and cost for retail and branded marketing segment fuel inventories is determined under the first-in, first-out (“FIFO”) method.
     (h) Hedging Activity
     All derivative instruments are recorded in the consolidated balance sheet as either assets or liabilities measured at their fair value. Alon generally considers all commodity forwards, futures, swaps, and option contracts to be part of its risk management strategy. Alon has elected not to designate these commodity contracts as cash flow hedges for financial accounting purposes. Accordingly, net unrealized gains and losses for changes in the fair value on open commodity derivative contracts are recognized in cost of sales or in other income, net on the consolidated statement of operations.
     Alon selectively designates certain commodity derivative contracts and interest rate derivatives as cash flow hedges. The effective portion of the gains or losses associated with these derivative contracts designated and qualifying as cash flow hedges are initially recorded in accumulated other comprehensive income in the consolidated balance sheet and reclassified into the statement of operations in the period in which the underlying hedged forecasted transaction affects income. The amounts recorded into the consolidated statement of operations

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
(dollars in thousands except as noted)
for commodity derivative contracts is recorded as a part of cost of sales and the amounts recorded for interest rate derivatives are recognized as interest expense. The ineffective portion of the gains or losses on the derivative contracts, if any, is recognized in the statement of operations as it is incurred.
     (i) Property, Plant, and Equipment
     The carrying value of property, plant, and equipment includes the fair value of the asset retirement obligation and has been reflected in the 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 first month of operation 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 unbranded marketing segment and asphalt segment expenditures for routine repairs and maintenance costs are charged to direct operating expense as incurred. Retail and branded marketing 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.
     (j) 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.
     (k) Asset Retirement Obligations
     Alon uses Accounting Standards Codification (“ASC”) subtopic 410-20, Asset Retirement Obligations, which established accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement costs. The provisions of ASC subtopic 410-20 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. ASC subtopic 410-20 also 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 (Note 12).
     (l) 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 the 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 the consolidated statements of operations.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
(dollars in thousands except as noted)
     (m) Income Taxes
     Alon accounts for income taxes 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 basis 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.
     (n) Stock-Based Compensation
     Alon uses the grant date fair value based method for calculating and accounting for stock-based compensation.
     Alon previously accounted for stock-based compensation using the intrinsic value method. 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-initial public offering (“IPO”) stock-based awards continue to be accounted for using the intrinsic value method.
     Stock compensation expense is presented as selling, general and administrative expenses in the consolidated statements of operations (Note 19).
     (o) 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.
     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 unless payments are fixed and determinable. 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.
     (p) Earnings Per Share
     Earnings per share are computed by dividing net income (loss) available to common stockholders by the weighted average number of participating common shares outstanding during the reporting period. Diluted earnings per share are calculated to give effect to all potentially dilutive common shares that were outstanding during the period (Note 18).
     (q) Other Comprehensive Income (Loss)
     Comprehensive income (loss) consists of net income (loss) and other gains and losses affecting stockholders’ equity that, under United States generally accepted accounting principles, are excluded from net income (loss), such as defined benefit pension plan adjustments and gains and losses related to certain derivative instruments. The balance in other comprehensive income (loss), net of tax reported in the consolidated statements of stockholders’ equity consists of defined benefit pension plans, fair value of interest rate swap adjustments, and the fair value of commodity derivative contract adjustments.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
(dollars in thousands except as noted)
     (r) Defined Benefit Pension and Other Postretirement Plans
     Alon recognizes the overfunded or underfunded status of its defined benefit pension and postretirement plans as an asset or a liability in the statement of financial position and recognizes changes in that funded status through comprehensive income in the year the changes occur.
     (s) Commitments and Contingencies
     Liabilities for loss contingencies, arising from claims, assessments, litigation, fines, and penalties and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recorded as assets, and are not offset against the related environmental liability.
     (t) 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.
     (u) Reclassifications
     Certain reclassifications have been made to the prior period balances to conform to the current presentation.
     (3) Acquisitions
      Bakersfield Refinery Acquisition
     On June 1, 2010, Alon completed the acquisition of the Bakersfield, California refinery (“Bakersfield refinery”) from Big West of California, LLC, a subsidiary of Flying J, Inc. The aggregate purchase price was $58,409 in cash, which included the purchase price of hydrocarbon inventories. In connection with the acquisition, an affiliate of Alon purchased certain refinery assets not installed at the Bakersfield refinery location for $26,000. The remaining assets were purchased by Alon. Alon incurred $550 of acquisition-related costs that were recognized in selling, general and administrative expenses in the consolidated statement of operations for the year ended December 31, 2010.
     Alon plans to integrate the Bakersfield hydrocracker unit by processing vacuum gas oil produced at the other California locations. Alon is currently completing the necessary projects to integrate the refineries, which are expected to be completed in June 2011. While these projects are ongoing, the Bakersfield refinery is not in operation and depreciation of the fixed assets will begin when the refinery is ready for its intended use.
     An acquirer is required to recognize and measure the goodwill acquired in a business combination or a gain from a bargain purchase. FASB ASC 805 defines a bargain purchase as a business combination in which the total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any non-controlling interest in the acquiree, and it requires the acquirer to recognize that excess in earnings as a gain attributable to the acquirer.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
(dollars in thousands except as noted)
     An independent appraisal of the net assets acquired in the Bakersfield refinery acquisition has been completed. The fair value of the assets acquired and liabilities assumed are as follows:
         
Current assets
  $ 17,033  
Other assets
    17,122  
Property, plant and equipment
    69,403  
Other non-current liabilities
    (53,669 )
 
     
Fair value of net assets acquired
    49,889  
Less: Gain on bargain purchase
    (17,480 )
 
     
Total Consideration
  $ 32,409  
 
     
     In connection with the acquisition of the Bakersfield refinery, Alon recorded an accrued environmental remediation obligation of $42,122. This amount was included as a non-current liability in the consolidated balance sheet at the acquisition date.
     Also in connection with the acquisition of the Bakersfield refinery, Alon entered into an indemnification agreement with a prior owner for remediation expenses of conditions that existed at the refinery on the acquisition date. Alon is required to make indemnification claims to the prior owner by March 15, 2015. The indemnification amount was $17,122 and was recorded as a non-current receivable in the consolidated balance sheet at the acquisition date.
      Krotz Springs Refinery Acquisition
     Effective July 1, 2008, Alon completed the acquisition of all the capital stock of the refining business located in Krotz Springs, Louisiana, from Valero Energy Corporation (“Valero”). The purchase price was $333,000 in cash plus $141,494 for working capital, including inventories (the “Purchase Price”). The completion of the Krotz Springs refinery acquisition increased Alon’s crude refining capacity by 50% to approximately 250,000 bpd including our refineries located on the West Coast and in West Texas. The Krotz Springs refinery supplies multiple demand centers in the Southern and Eastern United States markets through a pipeline operated by the Colonial product pipeline system.
     The Purchase Price was allocated based on fair values of the assets and liabilities acquired at the date of acquisition. The Purchase Price was determined as set forth below:
         
Cash paid
  $ 474,494  
Transaction costs
    6,517  
 
     
Total Purchase Price
  $ 481,011  
 
     
     The Purchase Price was allocated as follows:
         
Current assets
  $ 145,859  
Property, plant and equipment
    376,702  
Current liabilities
    (29,309 )
Other non-current liabilities
    (12,241 )
 
     
Total Purchase Price
  $ 481,011  
 
     
     (4) Contribution and Sale of Pipelines and Terminals
     HEP Transaction. On February 28, 2005, Alon completed the contribution of the Fin-Tex, Trust and River product pipelines, the Wichita Falls and Abilene product terminals and the Orla tank farm to Holly Energy Partners, LP (“HEP”). In exchange for this contribution, which is referred to as the “HEP transaction”, Alon received $120,000 in cash, prior to closing costs of approximately $2,000, and 937,500 subordinated Class B limited partnership units of HEP (“HEP Units”).

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
(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. 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 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. In the second quarter of 2008, Alon recorded a gain of $42,935 that represented the remaining deferred gain associated with the HEP transaction. The gain was recorded due to the termination of the indemnification agreement with HEP.
     In the first quarter of 2010, Alon sold 587,658 HEP Units to related parties (Note 16). The remaining 349,842 HEP Units were sold in open market transactions during the second quarter of 2010.
     (5) Segment Data
     Alon’s revenues are derived from three operating segments: (i) refining and unbranded marketing, (ii) asphalt and (iii) retail and branded marketing. 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 based on operating income.
     (a) Refining and Unbranded Marketing Segment
     Alon’s refining and unbranded marketing segment includes sour and heavy crude oil refineries located in Big Spring, Texas; and at its California refineries and a light sweet crude oil refinery located in Krotz Springs, Louisiana. At these refineries, Alon refines crude oil into 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. 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. Alon also acquires finished products through exchange agreements and third-party suppliers.
     (b) Asphalt Segment
     Alon’s asphalt segment includes the Willbridge, Oregon refinery and 12 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington (Richmond Beach), Arizona (Phoenix, Flagstaff and Fredonia), and Nevada (Fernley) (50% interest) as well as 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. The operations in which Alon has a 50% interest (Fernley and Wright), are recorded under the equity method of accounting, and the investments are included as total assets in the asphalt segment data.
     (c) Retail and Branded Marketing Segment
     Alon’s retail and branded marketing segment operates 304 convenience stores primarily in Central and 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, primarily under the 7-Eleven and FINA brand names. Substantially all of the motor fuel sold through our retail operations and the majority of the motor fuel marketed in our branded business is supplied by our Big Spring refinery. In 2010, approximately 91% of the motor fuel requirements of our branded marketing operations, including retail operations, were supplied by our Big Spring

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
(dollars in thousands except as noted)
refinery. Branded distributors that are not part of Alon’s integrated supply system, primarily in Central Texas, are supplied with motor fuels Alon obtains from third-party suppliers.
     Alon markets gasoline and diesel under the FINA brand name through a network of approximately 630 locations, including our convenience stores. Approximately 63% of the gasoline and 22% of the diesel motor fuel produced at the Big Spring refinery was transferred to the retail and branded marketing segment. These transfers were at prices substantially determined by reference to commodity pricing information published by Platts. Additionally, Alon’s retail and branded marketing segment licenses the use of the FINA brand name and provides credit card processing services to approximately 260 licensed locations that are not under fuel supply agreements.
     (d) Corporate
     Operations that are not included in any of the three segments are included in the corporate category. These operations consist primarily of corporate headquarter operating and depreciation expenses.
     Segment data as of and for the years ended December 31, 2010, 2009, and 2008 is presented below.
                                         
    Refining and             Retail and                
    Unbranded             Branded             Consolidated  
Year ended December 31, 2010   Marketing     Asphalt     Marketing     Corporate     Total  
Net sales to external customers
  $ 2,586,558     $ 399,334     $ 1,044,851     $     $ 4,030,743  
Intersegment sales/purchases
    867,557       (198,662 )     (668,895 )            
Depreciation and amortization
    80,401       6,875       13,440       1,380       102,096  
Operating income (loss)
    (166,000 )     (12,450 )     19,801       (2,132 )     (160,781 )
Total assets
    1,761,266       121,390       189,546       16,319       2,088,521  
Turnaround, chemical catalyst and capital expenditures
    51,267       1,557       4,679       2,335       59,838  
                                         
    Refining and             Retail and                
    Unbranded             Branded             Consolidated  
Year ended December 31, 2009   Marketing     Asphalt     Marketing     Corporate     Total  
Net sales to external customers
  $ 2,666,596     $ 440,915     $ 808,221     $     $ 3,915,732  
Intersegment sales/purchases
    692,447       (233,212 )     (459,235 )            
Depreciation and amortization
    76,252       6,807       13,464       724       97,247  
Operating income (loss)
    (86,533 )     (654 )     7,832       (1,481 )     (80,836 )
Total assets
    1,757,436       172,995       185,185       17,173       2,132,789  
Capital expenditures to rebuild the Big Spring refinery
    46,769                         46,769  
Turnaround, chemical catalyst and capital expenditures
    96,254       2,579       3,822       3,704       106,359  
                                         
    Refining and             Retail and                
    Unbranded             Branded             Consolidated  
Year ended December 31, 2008   Marketing     Asphalt     Marketing     Corporate     Total  
Net sales to external customers
  $ 3,282,166     $ 647,221     $ 1,227,319     $     $ 5,156,706  
Intersegment sales/purchases
    1,269,603       (369,505 )     (900,098 )            
Depreciation and amortization
    50,047       2,139       13,674       894       66,754  
Operating income (loss)
    128,772       97,442       (1,239 )     (1,498 )     223,477  
Total assets
    1,973,324       231,921       193,815       14,373       2,413,433  
Capital expenditures to rebuild the Big Spring refinery
    362,178                         362,178  
Turnaround, chemical catalyst and capital expenditures
    67,534       644       2,928       1,208       72,314  
     Operating income (loss) for each segment consists of net sales less cost of sales; direct operating expenses; selling, general and administrative expenses; depreciation and amortization; and gain (loss) on disposition of assets. Intersegment sales are intended to approximate wholesale market prices. Consolidated totals presented are after intersegment eliminations.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
(dollars in thousands except as noted)
     Total assets of each segment consist of net property, plant and equipment, inventories, cash and cash equivalents, accounts and other receivables and other assets directly associated with the segment’s operations. Corporate assets consist primarily of corporate headquarters information technology and administrative equipment.
     (6) Fair Value
     The carrying amounts of Alon’s cash and cash equivalents, receivables, payables and accrued liabilities approximate fair value due to the short-term maturities of these assets and liabilities. The reported amount of long-term debt approximates fair value. Derivative financial instruments are carried at fair value, which is based on quoted market prices.
     Alon must determine fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, Alon utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy. Alon generally applies the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.
     The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the consolidated balance sheets at December 31, 2010 and 2009, respectively:
                                 
    Quoted Prices                    
    in Active     Significant              
    Markets for     Other     Significant        
    Identical Assets     Observable     Unobservable        
    or Liabilities     Inputs     Inputs     Consolidated  
Year ended December 31, 2010   (Level 1)     (Level 2)     (Level 3)     Total  
Assets:
                               
Commodity contracts (futures and forwards)
  $ 1,214     $     $     $ 1,214  
Liabilities:
                               
Commodity contracts (call options)
          8,876             8,876  
Commodity contracts (swaps)
          681             681  
Interest rate swaps
          7,501             7,501  
 
                               
Year ended December 31, 2009
                               
Assets:
                               
Commodity contracts (futures and forwards)
  $ 322     $     $     $ 322  
Commodity contracts (swaps)
          89             89  
Liabilities:
                               
Commodity contracts (swaps)
          9,983             9,983  
Interest rate swaps
          16,933             16,933  
(7) Derivative Instruments
     Commodity Derivatives — Mark to Market
     Alon selectively utilizes commodity derivatives to manage its exposure to commodity price fluctuations and uses crude oil and refined product commodity derivative contracts to reduce risk associated with potential price changes on committed obligations. Alon does not speculate using derivative instruments. There is not a significant credit risk on Alon’s derivative instruments which are transacted through counterparties meeting established collateral and credit criteria.
     Alon has elected not to designate the following commodity derivatives as cash flow hedges for financial accounting purposes. Therefore, changes in the fair value of the commodity derivatives are included in income in the period of the change.
     At December 31, 2010, Alon had forward contracts for the net purchase of 354,614 barrels of refined product and the sales of 41,991 barrels of crude oil at an average price of $102.80 per barrel. Accordingly, the contracts are

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
(dollars in thousands except as noted)
recorded at their fair market values and an unrealized gain of $1,360 has been recorded in cost of sales in the consolidated statements of operations for the year ended December 31, 2010.
     At December 31, 2010, Alon held futures contracts for sale of 22,000 barrels of refined product at an average price of $99.44 per barrel. Accordingly, the contracts are recorded at their fair market values and an unrealized loss of $146 has been included in cost of sales in the consolidated statements of operations for the year ended December 31, 2010.
     At December 31, 2010, Alon had written call contracts outstanding for the net purchase of 3,008,500 barrels of crude and sale of 3,008,500 barrels of heating oil at an average strike price of $13.43 per barrel for a period of 18 months commencing January 2011. The value of the obligation exceeded the value at the strike price by $3,187 resulting in an unrealized loss included in other income, net in the consolidated statements of operations for the year ended December 31, 2010. The written call contracts are recorded in other income, net as the calls are considered a financing activity due to the receipt of the call premiums at the beginning of the contracts.
     At December 31, 2010, Alon held futures contracts for 218,800 barrels of heating oil swaps at an average spread of $11.38 per barrel. Accordingly, the contracts are recorded at their fair market values and an unrealized loss of $681 has been included in cost of sales in the consolidated statements of operations for the year ended December 31, 2010.
     At December 31, 2009, Alon held futures contracts for purchases and sales of 240,000 barrels of crude oil at an average price of $73.26 per barrel. Accordingly, the contracts are recorded at their fair market values and an unrealized gain of $322 has been included in cost of sales in the consolidated statements of operations for the year ended December 31, 2009.
     At December 31, 2009, Alon held futures contracts for 364,800 barrels of heating oil swaps at an average spread of $11.38 per barrel. Accordingly, the contracts are recorded at their fair market values and an unrealized gain of $89 has been included in cost of sales in the consolidated statements of operations for the year ended December 31, 2009.
     At December 31, 2009, Alon held futures contracts for purchases and sales of 278,322 barrels of crude oil at an average price of $77.99 per barrel. Accordingly, the contracts are recorded at their fair market values and an unrealized loss of $9,983 has been included in cost of sales in the consolidated statements of operations for the year ended December 31, 2009.
     Cash Flow Hedges
     To designate a derivative as a cash flow hedge, Alon documents at the inception of the hedge the assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. If, during the term of the derivative, the hedge is determined to be no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings when the underlying transaction occurs.
     Interest Rate Derivatives. Alon selectively utilizes interest rate related derivative instruments to manage its exposure to floating-rate debt instruments. Alon periodically uses interest rate swap agreements to manage its floating to fixed rate position by converting certain floating-rate debt to fixed-rate debt. As of December 31, 2010, Alon had an interest rate swap agreement with a notional amount of $100,000, a remaining period of two years and a fixed interest rate of 4.25%. This swap was accounted for as a cash flow hedge.
     For cash flow hedges, gains and losses reported in accumulated other comprehensive income in equity are reclassified into interest expense when the forecasted transactions affect income. During the years ended December 31, 2010 and 2009, Alon recognized unrealized after-tax gains of $6,131 and $5,960; respectively, for the fair value measurement of the interest rate swaps. There were no amounts reclassified into interest expense as a result of the discontinuance of cash flow hedge accounting.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
(dollars in thousands except as noted)
     For the years ended December 31, 2010 and 2009, there was no hedge ineffectiveness recognized in income. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.
     Commodity Derivatives In May 2008, as part of financing the acquisition of the Krotz Springs refinery, Alon entered into futures contracts for the forward purchase of crude oil and the forward sale of heating oil of 14,849,750 barrels. These futures contracts were designated as cash flow hedges for accounting purposes. Gains and losses for the futures contracts designated as cash flow hedges reported in accumulated other comprehensive income in the balance sheet are reclassified into cost of sales when the forecasted transactions affect income. In the fourth quarter of 2008, Alon determined during its retrospective assessment of hedge effectiveness that the hedge was no longer highly effective. Cash flow hedge accounting was discontinued in the fourth quarter of 2008 and all changes in value subsequent to the discontinuance were recognized into earnings. In April 2009, Alon completed an unwind of these futures contracts for $139,290.
     An after-tax loss of $4,563 and an after-tax gain of $3,409 have been reclassified from equity to earnings for the years ended December 31, 2010 and 2009, respectively. All adjustments have been recognized in income since the discontinuance of hedge accounting.
     The following table presents the effect of derivative instruments on the consolidated statements of financial position.
                                 
    As of December 31, 2010  
    Asset Derivatives     Liability Derivatives  
    Balance Sheet Location     Fair Value     Balance Sheet Location     Fair Value  
Derivatives not designated as hedging instruments:
                               
Commodity contracts (swaps)
          $     Accounts payable   $ (681 )
Commodity contracts (call options)
                Accrued liabilities     (5,748 )
Commodity contracts (futures and forwards)
  Accounts receivable     1,364     Accrued liabilities     (150 )
Commodity contracts (call options)
                Other non-current liabilities     (3,128 )
 
                           
 
                               
Total derivatives not designated as hedging instruments
          $ 1,364             $ (9,707 )
 
                           
 
                               
Derivatives designated as hedging instruments:
                               
Interest rate swaps
          $     Other non-current liabilities   $ (7,501 )
 
                             
Total derivatives designated as hedging instruments
                          (7,501 )
 
                           
Total derivatives
          $ 1,364             $ (17,208 )
 
                           
                                 
    As of December 31, 2009  
    Asset Derivatives     Liability Derivatives  
    Balance Sheet Location     Fair Value     Balance Sheet Location     Fair Value  
Derivatives not designated as hedging instruments:
                               
Commodity contracts (futures, forwards and SPR swaps)
  Accounts receivable   $ 411     Accrued liabilities   $ (9,983 )
 
                           
Total derivatives not designated as hedging instruments
          $ 411             $ (9,983 )
 
                           
 
                               
Derivatives designated as hedging instruments:
                               
Interest rate swaps
          $     Other non-current liabilities   $ (16,933 )
 
                           
Total derivatives designated as hedging instruments
                          (16,933 )
 
                           
Total derivatives
          $ 411             $ (26,916 )
 
                           

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
(dollars in thousands except as noted)
     The following tables present the effect of derivative instruments on Alon’s consolidated statements of operations and accumulated other comprehensive income (“OCI”).
                                 
                        Gain (Loss) Reclassified  
                        from Accumulated OCI into  
                        Income (Ineffective  
            Gain (Loss) Reclassified from     Portion and Amount  
            Accumulated OCI into Income     Excluded from  
    Gain (Loss)     (Effective Portion)     Effectiveness Testing)  
Cash Flow Hedging Relationships   Recognized in OCI     Location   Amount     Location   Amount  
For the Year Ended December 31, 2010
                               
Commodity contracts (heating oil swaps)
  $     Cost of sales   $ (7,174 )       $  
Interest rate swaps
    9,432     Interest expense     (13,381 )          
 
                         
Total derivatives
  $ 9,432         $ (20,555 )       $  
 
                         
 
                               
For the Year Ended December 31, 2009
                               
Commodity contracts (heating oil swaps)
  $