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, 2011
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 þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value for the registrant’s common stock held by non-affiliates as of June 30, 2011, the last day of the registrant’s most recently completed second fiscal quarter was $145,270,762.
The number of shares of the Registrant’s common stock, par value $0.01 per share, outstanding as of March 1, 2012, was 56,107,986.
Documents incorporated by reference: Proxy statement of the registrant relating to the registrant’s 2012 annual meeting of stockholders, which is incorporated into Part III of this Form 10-K.
 
 



TABLE OF CONTENTS

 
 
 
 
 
FORM OF CERTIFICATE OF DESIGNATION OF THE 8.75% SERIES B CONVERTIBLE PREFERRED STOCK
TENTH AMENDMENT TO AMENDED REVOLVING CREDIT AGREEMENT
AGREEMENT OF PRINCIPLES OF EMPLOYMENT BETWEEN DAVID WIESSMAN AND THE COMPANY
AMENDMENT TO SHAREHOLDER AGREEMENTS – OPTION SHARES, BETWEEN ALON ASSETS, INC., ALON OPERATING, INC., ALON USA ENERGY, INC. AND JOSEPH A. CONCIENNE
SUPPLY AND OFFTAKE AGREEMENT BY AND BETWEEN PARAMOUNT PETROLEUM CORPORATION  AND J. ARON & COMPANY
FORM OF SERIES B CONVERTIBLE PREFERRED STOCK PURCHASE AGREEMENT
SUBSIDIARIES OF ALON USA ENERGY, INC.
CONSENT OF KPMG LLP
EX-31.1 CERTIFICATION OF CEO PURSUANT TO SECTION 302
EX-31.2 CERTIFICATION OF CFO PURSUANT TO SECTION 302
EX-32.1 CERTIFICATION OF CEO AND CFO PURSUANT TO SECTION 906



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PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES.
Statements in this Annual Report on Form 10-K, including those in Items 1 and 2, “Business and Properties,” and Item 3, “Legal Proceedings,” that are not historical in nature should be deemed forward-looking statements that are inherently uncertain. See “Forward-Looking Statements” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of forward-looking statements and of factors that could cause actual outcomes and results to differ materially from those projected.
Company Overview
In this Annual Report, the words “we,” “our” and “us” refer to Alon USA Energy, Inc. and its consolidated subsidiaries or to Alon USA Energy, Inc. or an individual subsidiary, and not to any other person.
We are a Delaware corporation formed in 2000 to acquire 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, 2011, we operated 302 convenience stores in Central and West Texas and New Mexico, primarily under the 7-Eleven, Alon and FINA brand names. 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.
Our stock trades 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 67% 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.
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 1 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.


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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, petrochemical feedstocks, asphalt, and other petroleum-based products, 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 during the first quarter of 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 80.0% 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.
Big Spring Refinery Raw Material Supply
Sour crude oil has typically accounted for approximately 80% of our crude oil input at the Big Spring refinery, of which approximately 83.3% was West Texas Sour (“WTS”) crude oil. 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.
J. Aron and Company ("J.Aron"), through arrangements with various oil companies, currently supplies the majority of the Big Spring refinery's crude oil input materials.
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 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.
Big Spring Refinery Production
Gasoline. In 2011, gasoline accounted for approximately 49.1% of our Big Spring refinery’s production. We produce various grades of gasoline, ranging from 84 sub-octane regular unleaded to 91 octane premium unleaded, and use a computerized component blending system to optimize gasoline blending. 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”).


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Distillates. In 2011, diesel and jet fuel accounted for approximately 32.3% 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 7.1% of our Big Spring refinery’s production in 2011. 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.
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.
We presently sell a majority of the diesel fuel and approximately 21.4% of the gasoline produced at our Big Spring refinery on an unbranded basis, largely sold through our physically integrated system. We market substantially all the jet fuel produced at our Big Spring refinery as JP-8 grade to the Defense Energy Supply Center. Jet fuel production in excess of existing contracts is sold through unbranded rack sales. We sell transportation fuel production in excess of our branded and unbranded marketing needs through bulk sales and exchange channels with various oil companies and traders.
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.
Product Terminals
We primarily utilize six product terminals in Big Spring, Abilene, Orla, Southlake and Wichita Falls, Texas and Duncan, Oklahoma to market transportation fuels produced at our Big Spring refinery. All six of these terminals 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. We also have direct access to 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, LLC (“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


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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 located on approximately 600 acres in Bakersfield, California, with a nameplate capacity of approximately 70,000 barrels. The Bakersfield refinery is characterized as a ”coking refinery”, which generally refers to a refinery utilizing vacuum distillation, hydrocracking and delayed coking 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.  At this time, we are not operating the refinery as a traditional coking refinery.  Instead, we are processing untreated vacuum gas oil produced by our other California refineries through the hydrocracker and other hydrotreating units located at the Bakersfield refinery.  This allows us to convert this untreated vacuum gas oil, which was previously sold to the market at prices typically below the cost of crude, to lighter products such as CARBOB gasoline, CARB diesel, and other petroleum products.
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 heavy crude oils. In 2011 at the California refineries, medium sour crude oil accounted for approximately 27.5% of crude oil input and heavy crude oil accounted for 72.5%. The Paramount and Long Beach refineries are connected by pipelines we own.
Our California refineries currently produce CARBOB gasoline, CARB diesel, jet fuel, asphalt and other petroleum products. In 2011 these refineries converted approximately 57.1% of crude oil into higher value products such as gasoline, diesel and jet fuel, and 32.6% converted to asphalt, fuel oil and sulfur. The remaining 10.2% of production was sold as unfinished feedstocks to other refineries and third parties.
Our California refineries operated at low rates for 2011, 2010 and 2009 due to continued efforts to optimize asphalt production with demand. In 2011, we averaged approximately 28.5% utilization of our California refineries’ crude oil throughput capacity.We continuously evaluate and optimize throughput at our California refineries based on the margin environment.
California Refineries Raw Material Supply
For 2011, heavy crude oil accounted for approximately 72.5% of our crude oil input of which approximately 34.1% 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.
Crude Oil Pipelines
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.
We also utilize our crude oil and unfinished products pipeline system known as the “Black Oil System” to provide our Paramount refinery and other third-party shippers with access to refineries and waterborne terminals.
California Refineries Production
Gasoline. In 2011, CARBOB gasoline accounted for approximately 22.8% of our California refineries’ production. The California refineries utilize a computerized component blending system to optimize gasoline blending.
Distillates. In 2011, CARB diesel, Ultra-low sulfur EPA diesel, Jet A and military fuels accounted for approximately 17.2% 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.


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Asphalt. In 2011, asphalt accounted for approximately 29.4% 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. The gas oils are sent to our Bakersfield facility for further processing into gasoline and diesel. These gas oils can still be sold to third parties if necessary.
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 process. 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 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.
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 bpd 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.


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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.
Krotz Springs Refinery Raw Material Supply
In 2011, sweet crude oil accounted for approximately 100% of our crude oil input at the Krotz Springs refinery, of which approximately 80.0% was Light Louisiana Sweet (“LLS”) crude oil and 20.0% 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 59% 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 and WTI 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, through arrangements with various oil companies, supplies the majority of Krotz Springs 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 2011, gasoline accounted for approximately 41.4% 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 2011, diesel, light cycle oil and jet fuel accounted for approximately 45.6% 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 2011, slurry oil, LPG and petrochemical feedstocks accounted for approximately 13.0% of the Krotz Springs 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.
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.
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 transported via barge for sale. 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 isobutane and natural gasoline on a spot basis.
Asphalt
In addition to gasoline and distillates, our California and Big Spring refineries produce significant quantities of vacuum


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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 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 process and the type and quality of the asphalt produced. In 2011, approximately 7.1% of our Big Spring refinery’s production and 29.4% of our California refineries' production was asphalt. As part of our efforts to maximize the return generated by the production of asphalt, we have an exclusive license to use FINA’s advanced 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, 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.
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, we currently operate the Willbridge facility as an asphalt terminal and supply it with asphalt produced at the California refineries or purchased from third parties. Including 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 and Flagstaff) and Nevada (Fernley) (50% interest) as well as a 50% interest in Wright.
In 2011, 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. Sales of asphalt, particularly paving asphalts, are seasonal with products predominately sold between May and October 2011.
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 2011, 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
Our retail and branded marketing segment operates 302 convenience stores and markets motor fuels to over 640 locations, including our convenience stores, under the Alon and FINA brand names. In November 2011 we introduced the new Alon design and logo which will replace the FINA brand at all of our locations served by our branded marketing segment.
Retail
We are the largest 7-Eleven licensee in the United States and through our 7-Eleven licensing agreement have the exclusive right to operate 7-Eleven convenience stores in substantially all of our existing retail markets and many surrounding areas. As of December 31, 2011, we operated 302 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.


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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

 
4

 
21

Albuquerque, New Mexico
 
12

 
11

 
23

Odessa, Texas
 
11

 
24

 
35

Abilene, Texas
 
32

 
9

 
41

El Paso, Texas
 
13

 
71

 
84

Other locations in Central and West Texas
 
29

 
19

 
48

Total stores
 
147

 
155

 
302

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, Core-Mark Mid-Continent, Inc., for non-DSD products. We purchase the products from Core-Mark at cost plus an agreed upon mark-up. Our current supply contract with CoreMark was entered into in January 2012 and expires in December 2017. For the year ended December 31, 2011, approximately 50% of our retail merchandise sales were purchased from McLane Company, Inc., our previous wholesale distributor, and we anticipate our purchase percentages to be substantially similar with Core-Mark. We typically do not have contracts with our DSD vendors.
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.
Branded Marketing
We market motor fuels under the Alon and FINA brand names to distributors servicing approximately 640 locations, including our convenience stores. We supply our branded supply customers with motor fuels, brand support and payment processing services, in addition to the license of the Alon or FINA brand name and associated trade dress. In markets where we do not supply fuel products, we offer the same brand support and payment services through a licensing arrangement that is not tied to a fuel supply agreement.
Approximately 62.4% of our branded fuel sales are in West Texas and Central Texas that we own or have access rights through various terminals. For the year ended December 31, 2011, we sold 368.4 million gallons of branded motor fuel for distribution to our retail convenience stores and other retail distribution outlets. In 2011, approximately 91% of Alon’s branded marketing operations, including retail operations, were supplied by our Big Spring refinery.
We have operated under an exclusive license to use the FINA trademark in the wholesale distribution of motor fuel within Texas, Oklahoma, New Mexico, Arizona, Arkansas, Louisiana, Colorado and Utah since 2000. Our license to use the FINA brand will expire in August 2012 in accordance with its terms. We developed the Alon brand and logo in anticipation of this expiration of this license and have begun the process of converting all of our locations and all locations served by our branded marketing business to the new Alon brand. Under the Alon brand we will no longer be subject to the geographic limitations contained in the FINA license agreement.
Distribution Network and Distributor Arrangements. We sell motor fuel to our retail locations and to approximately 22 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.
Brand Licensing. We offer Alon brand licensing to distributors supplying geographic areas other than our integrated supply system. In addition to a license to use the brands, we also provide payment card processing services, advertising programs and loyalty and other marketing programs to 47 distributors supplying approximately 230 additional stores. As part of the brand conversion process, all legacy FINA licenses will be converted to Alon licenses. This licensing program allows us to expand the geographic footprint of our brand, thereby increasing its recognition. Each licensee pays royalties on a per gallon basis, is required to comply with the minimum standards program and utilize our payment card processing services.


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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.
Petroleum refining and marketing is highly competitive. The principal competitive factors affecting our refining and unbranded marketing segment are costs of crude oil and other feedstocks, refinery efficiency, operating costs, refinery product mix and costs of product distribution and transportation.
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.
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® brand), Alimentation Couche-Tard Inc. (Circle K® brand), 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 convenience stores that sell motor fuels. Increasingly, national grocery and dry goods retailers such as Wal-Mart, Kroger and Costco, 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 and diesel to 15 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. The EPA is expected to publish a proposed rule to further reduce sulfur in gasoline and diesel fuel in 2012, which is expected to be finalized later this year. Depending on the final standard, one


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or more of our refineries may be required to install controls to further reduce sulfur. The need for or costs of any such controls is not known at this time.
In February 2007, the EPA adopted final rules to reduce the levels of benzene in gasoline on a nationwide basis. More specifically, 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 spent $14.2 million through 2011 and estimate an additional $21 million (through 2014) will be necessary in order for the Big Spring refinery to install controls to comply with the standards. We have spent $5.8 million through 2011 and estimate an additional $5.0 million (through 2014) 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.
We are subject to the renewable fuel standard which requires refiners to blend renewable fuels (e.g., ethanol, biodiesel) into their finished transportation fuels or purchase renewable energy credits, called RINs, in lieu of blending. The EPA establishes new annual renewable fuel percentage standards for each compliance year in the preceding year. For 2012, the EPA raised the renewable fuel percentage standard to approximately 9%. Each of our refineries has received an extension of the deadline to comply with the renewable fuel standard. Therefore, we will not be required to blend renewable fuels or purchase RINs for compliance until 2013, unless a further extension is received.
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. We cannot currently determine the amounts of such future expenditures.
Compliance
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 been issued and are currently under review by both impacted industry and state regulators. It is expected that these regulations will be amended in response to public comments and upon further review by the state. Although development of such regulations is still ongoing 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.
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 companies (representing over 90% of the U.S. refining capacity) have entered into “global settlements” under the initiative. 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 control requirements and civil penalty are expected to be comparable to other settling refiners.
The Krotz Springs and Bakersfield refineries were subject to “global settlements” with the EPA under the National Petroleum Refining Initiative, when we acquired them. 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. If we are unable to meet the agreed upon reductions without add-on controls, our capital costs could increase. Because the


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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.
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 July 15, 2010, the EPA disapproved Texas’ “flexible permit” program and contends that sources operating under a "flexible permit" issued by the Texas Commission on Environmental Quality ("TCEQ") are not properly permitted and are subject to enforcement. We have committed to apply for an EPA 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.
Remediation Efforts. We are currently remediating historical soil and groundwater contamination at our Big Spring refinery. To date, we have substantially completed the remediation of the potentially contaminated areas and continue 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 with an aggregate indemnification cap of $20.0 million. We are also remediating historical soil and groundwater contamination at the Hawley, Southlake, 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. 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. Approximately $2.4 million was spent in 2011 for all of these remediation projects of which our portion was $1.8 million. We estimate that an additional $2.1 million will be spent in 2012 with our portion being approximately $1.1 million.
In conjunction with our acquisition of the Long Beach 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 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 $0.4 million was spent in 2011 for these remediation costs, of which our portion was $0.2 million, and we estimate that an additional $0.9 million will be spent during 2012, of which our portion will be $0.7 million.
In conjunction with our acquisition of the Bakersfield refinery on June 1, 2010, we entered into an indemnification agreement with a prior owner for remediation expenses of conditions that existed at the Bakersfield refinery on the acquisition date. We are required to make indemnification claims to the prior owner by March 15, 2015. Approximately $0.6 million was spent in 2011 for these remediation costs, of which our portion was $0.1 million. We estimate that an additional $0.8 million will be spent during 2012, of which our portion will be $0.1 million. Additionally, the local Water Board has issued a draft Clean-up and Abatement Order that is still under negotiation. Depending on the scope of the remedial action ultimately required under this order, we may be required to make additional capital expenditures which cannot be estimated at this time.
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 Insurance. We purchased two environmental insurance policies to cover expenditures not covered by the


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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.
Environmental Indemnity to HEP. In connection with our sale of pipelines and terminals to Holly Energy Partners ("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 remediation required for environmental conditions existing prior to the date of sale, we are performing such remediation ourselves at the Wichita Falls terminal in lieu of indemnifying HEP for their costs of performing such remediation.
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. 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. The California State Fire Marshall’s Office enforces federal pipeline regulations for pipelines in the State of California.
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. Under the PMPA, we may not terminate or fail to renew branded distributor contracts unless certain enumerated preconditions or grounds for termination or nonrenewal are met and we also comply with the prescribed notice requirements.
Employees
As of December 31, 2011, we had approximately 2,824 employees. Approximately 742 employees worked in our refining and unbranded marketing segment, of which 647 were employed at our refineries and approximately 95 were employed at our corporate offices in Dallas, Texas. Approximately 123 employees worked in our asphalt segment and approximately 1,959 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, 2011, we were the lessee under a number of cancelable and non-cancelable leases for certain properties. Our leases are discussed more fully in Note 19 to our


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consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
Executive Officers of the Registrant
Our current executive officers and key employees (identified by an asterisk), their ages as of March 1, 2012, and their business experience during at least the past five years are set forth below.
Name
 
Age
 
Position
David Wiessman
 
57

 
Executive Chairman of the Board of Directors
Jeff D. Morris
 
60

 
Vice Chairman of the Board of Directors
Paul Eisman
 
56

 
Chief Executive Officer and President
Shai Even
 
43

 
Senior Vice President and Chief Financial Officer
Claire A. Hart
 
56

 
Senior Vice President
Alan Moret
 
57

 
Senior Vice President of Supply
Michael Oster
 
40

 
Senior Vice President of Mergers and Acquisitions
Jimmy C. Crosby*
 
52

 
Vice President of Refining — Big Spring
Ed Juno*
 
59

 
Vice President of Refining — Paramount
Gregg Byers*
 
57

 
Vice President of Refining — Krotz Springs
Rick Bird*
 
58

 
Vice President of Asphalt Operations — Paramount
Kyle McKeen*
 
48

 
President and Chief Executive Officer of Alon Brands
Josef Lipman*
 
66

 
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 35 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 Vice Chairman of the Board of Directors of Alon since May 2011 and a director since May 2005. Prior to this Mr. Morris served as our Chief Executive Officer from May 2005 to May 2011, our Chief Executive Officer of our operating subsidiaries from July 2000 to May 2011,our President from May 2005 until March 2010 and our President of our 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 Chief Executive Officer in May 2011 and 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 Senior Vice President of Refining.
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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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, with responsibility for operation at the Big Spring Refinery. Prior to this Mr. Crosby served as Vice President of Refining — California Refineries from March 2009 until January 2010, as Vice President of Refining and Supply from May 2007 to March 2009, as Vice President of Supply and Planning from May 2005 to May 2007 and as 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, with responsibility for operations at the California refineries. 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.
Gregg Byers has served as our Vice President of Refining — Krotz Springs since February 2012, with responsibility for operations at the Krotz Springs refinery. Mr. Byers rejoined Alon in September 2011 as Senior Director of Engineering Services.  Mr. Byers has been employed in the refining industry for over 35 years, most recently with Sinclair Oil Corporation as Operations Manager of Sinclair's Wyoming refinery from 2008 to 2011. Prior to this, Mr. Byers served as Engineering & Project Development Director at the Krotz Springs refinery under the Company's ownership in 2008 and Valero Energy Corporation's ownership from 2001 to 2008.
Richard Bird has served as Vice President, Paramount Asphalt since March 2012, with responsibility over asphalt marketing and operations.  Prior to this Mr. Bird served at the California refineries as Vice President, Asphalt Marketing from August 2008 to March 2012,  Vice President of Supply & Transportation in the asphalt division from March 2008 to August 2008 and Vice President, Operations in the asphalt division from July 2006 to March 2008.  Prior to joining Alon, Mr. Bird held various positions of increasing responsibilities at Paramount Petroleum Corporation from August 2000 to Alon acquisition of Paramount Petroleum Corporation in July 2006.  Mr. Bird has over 23 years of experience in the asphalt industry working for Alon, Paramount Petroleum Corporation, Conoco, Petro Source Corp. and Interwest Group. 
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.
Josef 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.
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


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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 between refined product prices and the prices for crude oil and other feedstocks. 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. 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;
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;
infrastructure limitations;
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 and product slates to optimize our operating results based on market conditions, there are inherent limitations on 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 has historically required 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 differential between the cost of crude oils processed by our refineries and those processed by our competitors. Changes in this differential could negatively affect our profitability.
We select grades of crude oil to process based, in part, on each individual refinery's configuration and operating units. Our profitability is partially derived from our ability to purchase and process crude oil feedstocks that are less expensive than those


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processed by competing refiners. We quantify this differential in crude prices by comparing our crude acquisition price with benchmark crude oil grades such as West Texas Intermediate. Crude oil differentials can vary significantly depending on overall economic conditions, trends and conditions within the markets for crude oil and refined products, and infrastructure constraints. A decline in these differentials affecting one or more of our refineries could have a negative impact on our earnings.
Our indebtedness could adversely affect our financial condition or make us more vulnerable to adverse economic conditions.
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 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. 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.


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We are subject to interruptions of supply as a result of our reliance on pipelines for transportation of crude oil and refined products.
Our 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.
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.
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.
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


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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. We anticipate spending approximately $6.4 million in investigation and remediation expenses in connection with our Big Spring refinery and terminals over the next 15 years. We anticipate spending an additional $38.8 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 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.
In connection with our acquisition of the Krotz Springs refinery from Valero, we became party to an agreement that allocated the parties' respective obligations under the Valero global settlement Consent Decree. The parties are in discussions regarding the appropriate levels of NOx emissions for the refinery's catalytic cracking unit, which is part of a Valero system-wide NOx emissions limit in the Consent Decree. Depending on the outcome of these discussions, it may be necessary for us to install additional controls or take other steps to reduce emissions of NOx from the catalytic cracking unit.
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


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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 located in close proximity to other commercial facilities, and our Bakersfield refinery is adjacent to newly developed commercial and retail property. 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 the event of an earthquake or hurricane or other weather-related event that causes damage to our refining, pipeline or asphalt terminal assets, or the infrastructure necessary for the operation of these assets, such as the availability of usable roads, electricity, water, or natural gas, we may experience a significant interruption in our refining and/or marketing operations. Such an interruption could have a material adverse effect on our business, results of operations and cash flows.
Terrorist attacks, threats of war or actual war may negatively affect our operations, financial condition, results of operations and prospects.
Terrorist attacks, threats of war or actual war, as well as events occurring in response to or in connection with them, may adversely affect our operations, financial condition, results of operations and prospects. Energy-related assets (which could include refineries, terminals and pipelines such as ours) may be at greater risk of 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


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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.
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, 2011, 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


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investments to improve operating results;
difficulties in achieving anticipated operational improvements;
incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and
issuance of additional equity, which could result in further dilution of the ownership interest of existing stockholders.
We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.
We depend upon our subsidiaries for cash to meet our obligations and pay any dividends, and we do not own 100% of the stock of our operating subsidiaries.
We are a holding company. Our subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or pay dividends to our stockholders depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends, tax sharing payments or otherwise. Our subsidiaries’ ability to make any payments will depend on their earnings, cash flows, the terms of their indebtedness, tax considerations and legal restrictions. Three of our current and former 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, 2011, the shares owned by these executive officers represent 5.66% of the aggregate equity interest in these subsidiaries. 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. MINE SAFTETY DISCLOSURES
None.


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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
 
 
 
 
 
2011
 
 
 
 
Fourth Quarter
 
$
12.09

 
$
5.35

Third Quarter
 
13.20

 
6.11

Second Quarter
 
15.58

 
9.81

First Quarter
 
13.98

 
5.91

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

Holders
As of March 1, 2012, there were approximately 25 common stockholders of record.
Dividends
Common Stock Dividends. 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.
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.
On March 15, 2011, 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 $0.288 million.
On June 15, 2011, 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 $0.143 million.
On September 15, 2011, 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 $0.139 million.
On December 15, 2011, 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 $0.134 million.
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


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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.
Preferred Stock Dividends. We issued 328,000 and 101,000 shares in aggregate of common stock for payment of preferred stock dividends for the years ended December 31, 2011 and 2010, respectively.
Recent Sales of Unregistered Securities
On October 10, 2011, Alon issued 83,936 shares of Alon Common Stock to Joe Concienne, a former officer of Alon. Pursuant to the terms of a shareholders agreement between Mr. Concienne, Alon and two subsidiaries of Alon (Alon Assets and Alon Operating), Mr. Concienne exchanged 673.07 shares of non-voting common stock of Alon Assets and 252.73 shares of non-voting common stock of Alon Operating for 83,936 shares of common stock in Alon and a cash payment of $300,479.75 (prior to tax withholding obligations). The issuance of the shares of Common Stock was exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.
On March 8, 2012, pursuant to the terms of Series B Convertible Preferred Stock Agreement, Alon issued 3,000,000 shares of 8.5% Series B Convertible Preferred Stock to a group of investors who held, in the aggregate, $30.0 million of notes issued by Alon Brands, Inc., the Alon Brands term loans, and 3,092,783 warrants to purchase shares of Alon common stock. Pursuant to such agreement, Alon repaid in full the obligations under the Alon Brands term loans and the warrants were surrendered to Alon. The terms of the Series B Convertible Preferred Stock are described in the Company's Certificate of Designation for the Series B Convertible Preferred Stock. The issuance of the Series B Preferred Stock was exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
None.


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Stockholder Return Performance Graph
The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, each as amended, except to the extent we specifically incorporate it by reference into such filing.
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 December 31, 2006 to December 31, 2011, assuming an initial investment of $100 dollars and the reinvestment of all dividends, if any. The “Peer Group” includes HollyFrontier Corporation, Tesoro Corporation, Valero Energy Corporation, Delek US Holdings, Inc., Western Refining, Inc. and CVR Energy, Inc..
 
12/2006
 
12/2007
 
12/2008
 
12/2009
 
12/2010
 
12/2011
Alon
$
100.00

 
$
103.81

 
$
35.43

 
$
26.91

 
$
24.14

 
$
35.73

S&P 500
100.00

 
105.50

 
66.45

 
84.03

 
96.68

 
98.72

Peer Group
100.00

 
132.31

 
40.46

 
36.79

 
53.89

 
56.85



27


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, 2008 and 2007, and the selected consolidated balance sheet data as of December 31, 2009, 2008 and 2007 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, 2011, 2010 and 2009, and the selected consolidated balance sheet data as of December 31, 2011 and 2010, 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, 2011, 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,
 
 
2011
 
2010
 
2009
 
2008
 
2007
 
 
(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
 
 
 
 
 
Net sales
 
$
7,186,257

 
$
4,030,743

 
$
3,915,732

 
$
5,156,706

 
$
4,542,151

Operating costs and expenses
 
7,005,465

 
4,192,469

 
3,994,977

 
5,258,153

 
4,363,238

Gain on involuntary conversion of assets (1)
 

 

 

 
279,680

 

Gain (loss) on disposition of assets (2)
 
729

 
945

 
(1,591
)
 
45,244

 
7,206

Operating income (loss)
 
181,521

 
(160,781
)
 
(80,836
)
 
223,477

 
186,119

Net income (loss) available to common stockholders
 
42,507

 
(122,932
)
 
(115,156
)
 
82,883

 
103,936

Earnings (loss) per share, basic
 
$
0.77

 
$
(2.27
)
 
$
(2.46
)
 
$
1.77

 
$
2.22

Weighted average shares outstanding, basic
 
55,431

 
54,186

 
46,829

 
46,788

 
46,763

Earnings (loss) per share, diluted
 
$
0.69

 
$
(2.27
)
 
$
(2.46
)
 
$
1.72

 
$
2.16

Weighted average shares outstanding, diluted
 
61,401

 
54,186

 
46,829

 
49,583

 
46,804

Cash dividends per common share
 
$
0.16

 
0.16

 
0.16

 
0.16

 
0.16

CASH FLOW DATA:
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
69,560

 
$
21,330

 
$
283,145

 
$
(812
)
 
$
123,950

Investing activities
 
(126,542
)
 
(40,925
)
 
(138,691
)
 
(610,322
)
 
(147,254
)
Financing activities
 
142,361

 
50,845

 
(122,471
)
 
560,973

 
27,753

BALANCE SHEET DATA:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents and short-term investments
 
$
157,066

 
$
71,687

 
$
40,437

 
$
18,454

 
$
95,911

Working capital
 
99,452

 
990

 
84,257

 
250,384

 
279,580

Total assets
 
2,330,382

 
2,088,521

 
2,132,789

 
2,413,433

 
1,581,386

Total debt
 
1,050,196

 
916,305

 
937,024

 
1,103,569

 
536,615

Total equity
 
395,784

 
341,767

 
431,918

 
536,867

 
403,922

(1)
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.
(2)
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.


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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 spread between West Texas Intermediate ("WTI") crude oil and West Texas Sour ("WTS") crude oil;
changes in the spread between WTI crude oil and Light Louisiana Sweet and Heavy Louisiana Sweet crude oils, as well as the spread between California crudes such as Buena Vista and WTI;
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 and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;
operating hazards, natural disasters such as flooding, casualty losses and other matters beyond our control;
the global financial crisis’ impact on our business and financial condition; and
the other factors discussed in this Annual Report on Form 10-K under the caption “Risk Factors.”
Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.


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Company Overview
We are an independent refiner and marketer of petroleum products operating primarily in the 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 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 these refineries we refine crude oil into petroleum products, including gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks and asphalts, which are marketed primarily in the South Central, Southwestern, and Western United States. At Bakersfield, we convert intermediate products into finished products and do not refine crude oil.
We market transportation fuels produced by 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's convenience stores and unbranded distributors 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 by our California refineries to wholesale distributors, other refiners and third parties primarily on the West Coast. We started up the Bakersfield hydrocracker unit in late June 2011 and began processing vacuum gas oil produced by our other California locations.
We market refined products produced by our Krotz Springs refinery to 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. 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. Our asphalt segment markets asphalt produced at our 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. Our asphalt segment markets asphalt through 11 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington (Richmond Beach), Arizona (Phoenix and Flagstaff) and Nevada (Fernley) (50% interest) as well as through 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 302 convenience stores located 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, Alon and FINA brand names. Substantially all of the motor fuel sold through our retail operations and the majority of the motor fuels marketed in our branded business is supplied by our Big Spring refinery. In 2011, approximately 91% of the motor fuel requirements of our branded marketing operations, including retail operations, 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 Alon and FINA brand names through a network of approximately 640 locations, including our convenience stores. Approximately 55% of the gasoline and 21% 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 Alon and FINA brand names and provides credit card processing services to approximately 230 licensed locations that are not under fuel supply agreements with us.


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Summary of 2011 Developments
We shut down the California refineries in December 2010, to redirect our resources towards the integration of the Bakersfield hydrocracker unit to process vacuum gas oil produced at our California refineries. The California refineries restarted operations in March and production from the Bakersfield hydrocracker began in June 2011.
In February 2011, we entered into a Supply and Offtake Agreement (the “Alon Supply and Offtake Agreement”), with J. Aron & Company (“J. Aron”). Pursuant to the Alon Supply and Offtake Agreement (i) J. Aron agreed to sell to us, and we agreed to buy from J. Aron, at market prices, crude oil for processing at the Big Spring refinery and (ii) we agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced by the Big Spring refinery.
In June 2011, we completed the Bakersfield refinery integration project marking the realization of the plan to have a hydrocracker unit to increase the light products yields of our California refineries. We began selling products produced by our Bakersfield refinery at the beginning of the third quarter of 2011.
At our Krotz Springs refinery, we completed several capital projects during the first two weeks of November 2011 that are intended to improve crude slate flexibility, FCC capacity and yields, and jet fuel yield. In addition, we completed arrangements that allowed us to to begin receiving WTI-priced crudes during December 2011 with the goal of processing on average 20,000 to 25,000 barrels per day of such crudes during 2012.
2011 Operational and Financial Highlights
Highlights for 2011 include:
Combined refinery throughput for 2011 averaged 146,149 bpd, consisting of 63,614 bpd at the Big Spring refinery, 22,815 bpd at the California refineries and 59,720 bpd at the Krotz Springs refinery, where throughput was reduced during the second quarter of 2011 due to flooding in Louisiana and the impact on crude oil supply to the refinery, compared to 105,868 bpd for 2010, 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.
Operating margin at the Big Spring refinery was $18.84 per barrel in 2011, compared to $6.03 per barrel in 2010. This increase is due to higher Gulf Coast 3/2/1 crack spreads and improved operating efficiencies at higher throughput rates.
Operating margin at the California refineries was $(1.31) per barrel in 2011, compared to $1.08 per barrel in 2010. This decrease primarily reflects the impact of the California refineries' shutdown until its restart in late March 2011 offset by higher West Coast 3/1/1/1 crack spreads and light product yields.
Operating margin at the Krotz Springs refinery was $3.05 per barrel in 2011, compared to $2.24 per barrel in 2010. This increase reflects the effects of the refinery being shut down for the first five months of 2010 and the increase in the Gulf Coast 2/1/1 high sulfur diesel crack spread.
The average sweet/sour spread for 2011 was $2.06 per barrel compared to $2.15 per barrel for 2010. The average LLS to WTI spread for 2011 was $16.76 per barrel compared to $2.49 per barrel for 2010. The average WTI to Buena Vista spread for 2011 was $(13.36) per barrel compared to $1.33 per barrel for 2010.
The average Gulf Coast 3/2/1 crack spread was $23.37 per barrel for 2011 compared to $8.22 per barrel for 2010. The average West Coast 3/1/1/1 crack spread for 2011 was $9.20 per barrel compared to $8.34 per barrel for 2010. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for 2011 was $7.00 per barrel compared to $5.26 per barrel for 2010.
Asphalt margins in 2011 were $26.99 per ton compared to $51.06 per ton in 2010. This decrease was due primarily to higher crude oil costs without having the ability to increase asphalt sales prices accordingly. The average blended asphalt sales price increased 13.4% from $477.26 per ton in 2010 to $541.44 per ton in 2011 and the average non-blended asphalt sales price increased $0.53 from $326.16 per ton in 2010 to $326.69 per ton in 2011. The average price of Buena Vista crude increased 38.9% from $78.08 per barrel in 2010 to $108.43 per barrel in 2011.
Retail fuel sales volume increased by 10.2% from 142.2 million gallons in 2010 to 156.7 million gallons in 2011. Branded fuel sales volume increased by 15.5% from 318.9 million gallons in 2010 to 368.4 million gallons in 2011.
Major Influences on Results of Operations
Refining and Unbranded Marketing. 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


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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 calculate the per barrel operating margin for each refinery by dividing the 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 Big Spring refinery’s per barrel operating margin to the Gulf 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, 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 compare our California refineries’ per barrel operating margin to the West Coast 3/1/1/1 crack spread. A 3/1/1/1 crack spread is calculated assuming that three barrels of a benchmark crude oil are converted into one barrel of gasoline, one barrel of diesel and one barrel of fuel oil. We calculate the West Coast 3/1/1/1 crack spread using the market values of West Coast LA CARBOB pipeline gasoline, LA ultra-low sulfur pipeline diesel, and LA 380 pipeline CST (fuel oil) and the market value of Buena Vista crude oil.
We compare our Krotz Springs refinery’s per barrel margin to the Gulf Coast 2/1/1 crack spread. A 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 Light Louisiana Sweet, or LLS, 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 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 Buena Vista crude oil. A widening of this 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 was primarily comprised of Heavy Louisiana Sweet, or HLS crude oil, and 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.
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 expectations for 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.


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Table of Contents

Asphalt. 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 and markets asphalt at 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 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, revenues from 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. Earnings and cash flows from our retail and branded marketing segment are primarily affected by merchandise and motor fuel sales volumes and margins at our convenience stores and the motor fuel sales volumes and margins from sales to our Alon and FINA-branded distributors, together with licensing and credit card related fees generated from our Alon and 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 result over the three-year period ended December 31, 2011 have been influenced by the following factors which are fundamental to understanding comparisons of our period-to-period financial performance.
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 was non-operational at the time and required turnaround work and additional capital expenditures before it could be returned to operations and integrated with our 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 June 2011, we completed the Bakersfield integration project marking the realization of the plan to have a hydrocracker unit to increase the light products yields of our California refineries. We began selling products produced by our Bakersfield refinery at the beginning of the third quarter of 2011.
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. Crude throughput was reduced at the Krotz Springs refinery during the second quarter of 2011 due to the flooding in Louisiana and its impact on crude oil supply to the refinery.
We implemented new operating procedures at the Big Spring refinery during 2010 that resulted in reduced throughput.
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 until its restart in the first quarter of 2011 to redeploy resources for the integration of the Bakersfield refinery.
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 and includes inter-segment 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.


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Table of Contents

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 and asphalt terminals, 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.


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Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED
Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for us and our three operating segments for years ended December 31, 2011, 2010 and 2009. 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.
 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
Net sales (1)
$
7,186,257

 
$
4,030,743

 
$
3,915,732

Operating costs and expenses:
 
 
 
 
 
Cost of sales
6,462,947

 
3,712,358

 
3,502,782

Direct operating expenses
285,666

 
249,933

 
265,502

Selling, general and administrative expenses (2)
143,122

 
128,082

 
129,446

Depreciation and amortization (3)
113,730

 
102,096

 
97,247

Total operating costs and expenses
7,005,465

 
4,192,469

 
3,994,977

Gain (loss) on disposition of assets
729

 
945

 
(1,591
)
Operating income (loss)
181,521

 
(160,781
)
 
(80,836
)
Interest expense (4)
(88,310
)
 
(94,939
)
 
(111,137
)
Equity earnings of investees
5,128

 
5,439

 
24,558

Gain on bargain purchase (5)

 
17,480

 

Other income (loss), net (6)
(35,673
)
 
9,716

 
331

Income (loss) before income tax expense (benefit)
62,666

 
(223,085
)
 
(167,084
)
Income tax expense (benefit)
18,918

 
(90,512
)
 
(64,877
)
Net income (loss)
43,748

 
(132,573
)
 
(102,207
)
Net income (loss) attributable to non-controlling interest
1,241

 
(9,641
)
 
(8,551
)
Accumulated dividends on preferred stock of subsidiary (7)

 

 
21,500

Net income (loss) available to common stockholders
$
42,507

 
$
(122,932
)
 
$
(115,156
)
Earnings (loss) per share, basic
$
0.77

 
$
(2.27
)
 
$
(2.46
)
Weighted average shares outstanding, basic (in thousands)
55,431

 
54,186

 
46,829

Earnings (loss) per share, diluted
$
0.69

 
$
(2.27
)
 
$
(2.46
)
Weighted average shares outstanding, diluted (in thousands)
61,401

 
54,186

 
46,829

Cash dividends per share
$
0.16

 
$
0.16

 
$
0.16

CASH FLOW DATA:
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
69,560

 
$
21,330

 
$
283,145

Investing activities
(126,542
)
 
(40,925
)
 
(138,691
)
Financing activities
142,361

 
50,845

 
(122,471
)
OTHER DATA:
 
 
 
 
 
Adjusted EBITDA (8) (A)
$
263,977

 
$
(44,475
)
 
$
42,891

Capital expenditures (9)
112,625

 
46,707

 
81,660

Capital expenditures to rebuild Big Spring refinery

 

 
46,769

Capital expenditures for turnaround and chemical catalyst
9,734

 
13,131

 
24,699

(A)
Adjusted EBITDA does not exclude loss on heating oil call option crack spread contracts of $36,280 for the year ended December 31, 2011. The heating oil call option crack spread contracts are considered a financing activity. Adjusted EBITDA excluding the loss on these heating oil call option crack spread contracts would be $300,257.


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Table of Contents

 
As of December 31,
 
2011
 
2010
BALANCE SHEET DATA:
 
 
 
Cash and cash equivalents
$
157,066

 
$
71,687

Working capital
99,452

 
990

Total assets
2,330,382

 
2,088,521

Total debt
1,050,196

 
916,305

Total equity
395,784

 
341,767

(1)
Includes excise taxes on sales by the retail segment of $60,686, $54,930 and $47,137 for the years ended December 31, 2011, 2010 and 2009, respectively.
(2)
Includes corporate headquarters selling, general and administrative expenses of $752, $752 and $757 for the years ended December 31, 2011, 2010 and 2009, respectively, which are not allocated to our three operating segments.
(3)
Includes corporate depreciation and amortization of $1,925, $1,380 and $724 for the years ended December 31, 2011, 2010 and 2009, respectively, which are not allocated to our three operating segments.
(4)
Interest expense of $94,939 for the year ended December 31, 2010, includes a charge of $6,659 for the write-off of debt issuance costs associated with our prepayment of the Alon Refining Krotz Springs, Inc. revolving credit facility. Interest expense for the year ended December 31, 2009, includes $20,482 of unamortized debt issuance costs written off as a result of prepayments of $163,819 of term debt in October 2009. Interest expense for 2009 also includes $5,715 related to the liquidation of heating oil hedges in the second quarter of 2009.
(5)
In connection with the Bakersfield refinery acquisition in 2010, the acquisition date fair value of the identifiable net assets acquired exceeded the fair value of the consideration transferred, resulting in a $17,480 bargain purchase gain.
(6)
Other income (loss), net for the year ended December 31, 2011, is substantially the loss on heating oil crack spread contracts. Other income (loss), net for the year ended December 31, 2010, includes a gain from the sale of our investment in Holly Energy Partners of $7,277 and a loss on heating oil crack spread contracts of $4,119.
(7)
Accumulated dividends on preferred stock of subsidiary for the year ended December 31, 2009, represent dividends of $12,900 for the conversion of the preferred stock into Alon common stock. Also included for the year ended December 31, 2009, is $8,600 of accumulated dividends through December 31, 2009.
(8)
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.
(9)
Includes corporate capital expenditures of $1,540, $2,335 and $3,704 for the years ended December 31, 2011, 2010 and 2009, respectively, which are not allocated to our three operating segments.


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Table of Contents

REFINING AND UNBRANDED MARKETING SEGMENT
 
 
 
 
 
 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(dollars in thousands, except per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
 
 
 
 
 
Net sales (1)
$
6,544,913

 
$
3,454,115

 
$
3,359,043

Operating costs and expenses:
 
 

 
 
Cost of sales
5,996,772

 
3,311,771

 
3,117,528

Direct operating expenses
243,018

 
205,838

 
221,378

Selling, general and administrative expenses
32,207

 
22,764

 
29,376

Depreciation and amortization
88,968

 
80,401

 
76,252

Total operating costs and expenses
6,360,965

 
3,620,774

 
3,444,534

Gain (loss) on disposition of assets
12

 
659

 
(1,042
)
Operating income (loss)
$
183,960

 
$
(166,000
)
 
$
(86,533
)
KEY OPERATING STATISTICS:
 
 
 
 
 
Per barrel of throughput:
 
 
 
 
 
Refinery operating margin – Big Spring (2)
$
18.84

 
$
6.03

 
$
4.35

Refinery operating margin – CA Refineries (2)
(1.31
)
 
1.08

 
1.83

Refinery operating margin – Krotz Springs (2)
3.05

 
2.24

 
5.66

Refinery direct operating expense – Big Spring (3)
4.25

 
5.06

 
4.21

Refinery direct operating expense – CA Refineries (3)
7.32

 
7.73

 
4.82

Refinery direct operating expense – Krotz Springs (3)
3.67

 
4.36

 
4.22

Capital expenditures
90,667

 
38,136

 
71,555

Capital expenditures to rebuild Big Spring refinery

 

 
46,769

Capital expenditures for turnaround and chemical catalyst
9,734

 
13,131

 
24,699

PRICING STATISTICS:
 
 
 
 
 
WTI crude oil (per barrel)
$
95.07

 
$
79.41

 
$
61.82

WTS crude oil (per barrel)
93.01

 
77.26

 
60.30

Buena Vista crude oil (per barrel)
108.43

 
78.08

 
59.62

LLS crude oil (per barrel)
110.98

 
80.61

 
60.90

Crack spreads (3/2/1) (per barrel):
 
 
 
 
 
Gulf Coast
$
23.37

 
$
8.22

 
$
7.24

Crack spreads (3/1/1/1) (per barrel):
 
 
 
 
 
West Coast
$
9.20

 
$
8.34

 
$
9.60

Crack spreads (2/1/1) (per barrel):
 
 
 
 
 
Gulf Coast high sulfur diesel
$
7.00

 
$
5.26

 
$
5.58

Crude oil differentials (per barrel):
 
 
 
 
 
WTI less WTS
$
2.06

 
$
2.15

 
$
1.52

LLS less WTI
16.76

 
2.49

 
0.92

WTI less Buena Vista
(13.36
)
 
1.33

 
2.20

Product price (dollars per gallon):
 
 
 
 
 
Gulf Coast unleaded gasoline
$
2.75

 
$
2.05

 
$
1.64

Gulf Coast ultra-low sulfur diesel
2.97

 
2.16

 
1.66

Gulf Coast high sulfur diesel
2.91

 
2.10

 
1.62

West Coast LA CARBOB (unleaded gasoline)
2.89

 
2.21

 
1.85

West Coast LA ultra-low sulfur diesel
3.05

 
2.21

 
1.71

Natural gas (per MMBTU)
4.03

 
4.38

 
4.16



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Table of Contents

THROUGHPUT AND PRODUCTION DATA:
BIG SPRING REFINERY
Year Ended December 31,
2011
 
2010
 
2009
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
Sour crude
51,202

 
80.4

 
39,349

 
80.2

 
48,340

 
80.8

Sweet crude
10,023

 
15.8

 
7,288

 
14.9

 
9,238

 
15.4

Blendstocks
2,389

 
3.8

 
2,391

 
4.9

 
2,292

 
3.8

Total refinery throughput (4)
63,614

 
100.0

 
49,028

 
100.0

 
59,870

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline
31,105

 
49.1

 
24,625

 
50.7

 
26,826

 
45.0

Diesel/jet
20,544

 
32.3

 
15,869

 
32.7

 
19,136

 
32.2

Asphalt
4,539

 
7.1

 
2,827

 
5.8

 
5,289

 
8.9

Petrochemicals
3,837

 
6.0

 
2,939

 
6.0

 
2,928

 
4.9

Other
3,488

 
5.5

 
2,341

 
4.8

 
5,327

 
9.0

Total refinery production (5)
63,513

 
100.0

 
48,601

 
100.0

 
59,506

 
100.0

Refinery utilization (6)
 
 
90.8
%
 
 
 
68.2
%
 
 
 
82.3
%
THROUGHPUT AND PRODUCTION DATA:
CALIFORNIA REFINERIES
Year Ended December 31,
2011
 
2010
 
2009
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
Medium sour crude
5,677

 
24.9

 
3,502

 
19.9

 
13,408

 
43.0

Heavy crude
14,962

 
65.6

 
13,688

 
77.8

 
17,420

 
55.9

Blendstocks
2,176

 
9.5

 
406

 
2.3

 
330

 
1.1

Total refinery throughput (4)
22,815

 
100.0

 
17,596

 
100.0

 
31,158

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline
4,969

 
22.0

 
2,629

 
15.4

 
4,920

 
16.2

Diesel/jet
7,938

 
35.1

 
3,704

 
21.6

 
7,123

 
23.5

Asphalt
6,632

 
29.4

 
5,919

 
34.6

 
8,976

 
29.5

Light unfinished

 

 

 

 
117

 
0.4

Heavy unfinished
2,292

 
10.2

 
4,483

 
26.2

 
8,813

 
29.0

Other
735

 
3.3

 
372

 
2.2

 
418

 
1.4

Total refinery production (5)
22,566

 
100.0

 
17,107

 
100.0

 
30,367

 
100.0

Refinery utilization (6)
 
 
28.5
%
 
 
 
25.9
%
 
 
 
46.2
%
THROUGHPUT AND PRODUCTION DATA:
KROTZ SPRINGS REFINERY
Year Ended December 31,
2011
 
2010
 
2009
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
Light sweet crude
47,177

 
79.0

 
23,810

 
60.7

 
22,942

 
47.5

Heavy sweet crude
11,802

 
19.8

 
14,535

 
37.0

 
22,258

 
46.0

Blendstocks
741

 
1.2

 
899

 
2.3

 
3,137

 
6.5

Total refinery throughput (4)
59,720

 
100.0

 
39,244

 
100.0

 
48,337

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline
24,852

 
41.4

 
15,812

 
40.1

 
22,264

 
45.4

Diesel/jet
27,436

 
45.6

 
18,986

 
48.2

 
21,318

 
43.4

Heavy Oils
2,904

 
4.8

 
1,515

 
3.8

 
1,238

 
2.5

Other
4,914

 
8.2

 
3,107

 
7.9

 
4,258

 
8.7

Total refinery production (5)
60,106

 
100.0

 
39,420

 
100.0

 
49,078

 
100.0

Refinery utilization (6)
 
 
77.9
%
 
 
 
46.1
%
 
 
 
65.3
%


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Table of Contents

(1)
Net sales include intersegment sales to our asphalt and retail and branded marketing segments at prices which approximate wholesale market prices. These intersegment sales are eliminated through consolidation of our financial statements.
(2)
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, 2011, excludes a benefit from inventory reductions of $22,460. The refinery operating margin for the year ended December 31, 2011 for the Krotz Springs refinery excludes unrealized hedging gains of $32,742. The refinery operating margin for the year ended December 31, 2010, excludes an unrealized loss associated with consignment inventory of $8,942. The refinery operating margin for the year ended December 31, 2010, excludes a benefit of $4,515 to cost of sales for inventory adjustments related to the Bakersfield refinery acquisition.
(3)
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 period prior to the startup of the Bakersfield refinery of $3,356 and $3,373 for the years ended December 31, 2011 and 2010, respectively, have been excluded from the per barrel measurement calculation.
(4)
Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process. The throughput data of the California refineries for the year ended December 31, 2011, reflects substantially eight months of operations due to the integration during the first three months of the year and work performed in December to the Bakersfield hydrocracker unit. The throughput data of the California refineries for the year ended December 31, 2010, reflects eleven months of throughput data as the California refineries were shutdown in December to redeploy resources for the integration of the Bakersfield refinery acquired in June 2010. The throughput data of the Krotz Springs refinery for the year ended December 31, 2011, reflects approximately a one month shutdown due to flooding in Louisiana and the impact on crude supply to the refinery and a two week shutdown in November for the tie-in of capital projects work. The throughput data of the Krotz Springs refinery for the year ended December 31, 2010, reflects substantially seven months of operations beginning in June 2010 due to the restart after major turnaround activity.
(5)
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.
(6)
Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.


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Table of Contents

ASPHALT SEGMENT
 
 
 
 
 
 
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
(dollars in thousands, except per ton data)
STATEMENTS OF OPERATIONS DATA:
 
 
 
 
 
 
Net sales
 
$
554,549

 
$
399,334

 
$
440,915

Operating costs and expenses:
 

 

 
 
Cost of sales (1)
 
524,964

 
355,272

 
386,050

Direct operating expenses
 
42,648

 
44,095

 
44,124

Selling, general and administrative expenses
 
5,080

 
5,542

 
4,588

Depreciation and amortization
 
6,376

 
6,875

 
6,807

Total operating costs and expenses
 
579,068

 
411,784

 
441,569

Operating loss
 
$
(24,519
)
 
$
(12,450
)
 
$
(654
)
KEY OPERATING STATISTICS:
 
 
 
 
 
 
Blended asphalt sales volume (tons in thousands) (2)
 
915

 
780

 
994

Non-blended asphalt sales volume (tons in thousands) (3)
 
181

 
83

 
197

Blended asphalt sales price per ton (2)
 
$
541.44

 
$
477.26

 
$
409.88

Non-blended asphalt sales price per ton (3)
 
326.69

 
326.16

 
170.05

Asphalt margin per ton (4)
 
26.99

 
51.06

 
46.07

Capital expenditures
 
3,225

 
1,557

 
2,579

(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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Table of Contents

RETAIL AND BRANDED MARKETING SEGMENT
 
 
 
 
 
 
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
(dollars in thousands, except per gallon data)
STATEMENTS OF OPERATIONS DATA:
 
 
 
 
 
 
Net sales (1)
 
$
1,437,449


$
1,044,851

 
$
808,221

Operating costs and expenses:
 



 
 
Cost of sales (2)
 
1,291,865


912,872

 
691,651

Selling, general and administrative expenses
 
105,083


99,024

 
94,725

Depreciation and amortization
 
16,461


13,440

 
13,464

Total operating costs and expenses
 
1,413,409

 
1,025,336

 
799,840

Gain (loss) on disposition of assets
 
717


286

 
(549
)
Operating income
 
$
24,757

 
$
19,801

 
$
7,832

KEY OPERATING STATISTICS:
 
 
 
 
 
 
Branded fuel sales (thousands of gallons) (3)
 
368,421

 
318,935

 
274,101

Branded fuel margin (cents per gallon) (3)
 
4.5

 
6.2

 
5.8

Number of stores (end of period)
 
302

 
304

 
308

Retail fuel sales (thousands of gallons)
 
156,662

 
142,155

 
120,697

Retail fuel sales (thousands of gallons per site per month) (4)
 
43

 
39

 
33

Retail fuel margin (cents per gallon) (5)
 
16.4

 
12.9

 
13.9

Retail fuel sales price (dollars per gallon) (6)
 
$
3.41

 
$
2.70

 
$
2.29

Merchandise sales
 
$
298,233

 
$
281,674

 
$
268,785

Merchandise sales (per site per month) (4)
 
$
82

 
$
77

 
$
73

Merchandise margin (7)
 
32.8
%
 
31.9
%
 
30.7
%
Capital expenditures
 
$
17,193

 
$
4,679

 
$
3,822

(1)
Includes excise taxes on sales by the retail segment of $60,686, $54,930 and $47,137 for the years ended December 31, 2011, 2010 and 2009, respectively. Net sales also includes net royalty and related net credit card fees of $5,526, $4,221 and $1,382 for the years ended December 31, 2011, 2010 and 2009, 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. The branded fuel 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 convenience store industry to measure in-store, or non-fuel, operating results.


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Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010
Net Sales
Consolidated. Net sales for the year ended December 31, 2011 were $7,186.3 million, compared to $4,030.7 million for the year ended December 31, 2010, an increase of $3,155.6 million. This increase was primarily due to higher refinery throughput volumes in our refining and unbranded marketing segment, increased sales volumes in our asphalt and retail and branded marketing segments and higher refined product prices.
Refining and Unbranded Marketing Segment. Net sales for our refining and unbranded marketing segment were $6,544.9 million for the year ended December 31, 2011, compared to $3,454.1 million for the year ended December 31, 2010, an increase of $3,090.8 million. This increase was due to higher refined product prices and higher refinery throughput in the year ended December 31, 2011 compared to the same period last year.
Combined refinery throughput for the year ended December 31, 2011, averaged 146,149 bpd, consisting of 63,614 bpd at the Big Spring refinery, 22,815 bpd at the California refineries and 59,720 bpd at the Krotz Springs refinery, compared to a combined average throughput of 105,868 bpd for the year ended December 31, 2010, 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.
The increase in refined product prices that our refineries experienced reflected the price increases experienced in each refinery's respective markets. The average per gallon price of Gulf Coast gasoline for the year ended December 31, 2011, increased $0.70, or 34.1%, to $2.75, compared to $2.05 for the year ended December 31, 2010. The average per gallon price of Gulf Coast ultra low-sulfur diesel for the year ended December 31, 2011, increased $0.81, or 37.5%, to $2.97, compared to $2.16 for the year ended December 31, 2010. The average per gallon price for Gulf Coast high-sulfur diesel for the year ended December 31, 2011, increased $0.81, or 38.6%, to $2.91, compared to $2.10 for the year ended December 31, 2010. The average per gallon price of West Coast LA CARBOB gasoline for the year ended December 31, 2011, increased $0.68, or 30.8%, to $2.89, compared to $2.21 for the year ended December 31, 2010. The average price per gallon of West Coast LA ultra low-sulfur diesel for the year ended December 31, 2011, increased $0.84, or 38.0%, to $3.05, compared to $2.21 for the year ended December 31, 2010.
Asphalt Segment. Net sales for our asphalt segment were $554.5 million for the year ended December 31, 2011, compared to $399.3 million for the year ended December 31, 2010, an increase of $155.2 million or 38.9%. This increase was due primarily to an increase in asphalt sales volumes and higher asphalt sales price for our blended asphalt product for the year ended December 31, 2011. The asphalt sales volume increased 27.0% from 863 thousand tons for the year ended December 31, 2010, to 1,096 thousand tons for the year ended December 31, 2011. The average blended asphalt sales price increased 13.4% from $477.26 per ton for the year ended December 31, 2010, to $541.44 per ton for the year ended December 31, 2011, and the average non-blended asphalt sales price increased 0.2% from $326.16 per ton for the year ended December 31, 2010, to $326.69 per ton for the year ended December 31, 2011.
Retail and Branded Marketing Segment. Net sales for our retail and branded marketing segment were $1,437.4 million for the year ended December 31, 2011, compared to $1,044.9 million for the year ended December 31, 2010, an increase of $392.5 million or 37.6%. This increase was primarily attributable to increases in motor fuel prices, motor fuel volumes and merchandise sales.
Cost of Sales
Consolidated. Cost of sales were $6,462.9 million for the year ended December 31, 2011, compared to $3,712.4 million for the year ended December 31, 2010, an increase of $2,750.5 million. This increase was primarily due to higher refinery throughput volumes in our refining and unbranded marketing segment, increased sales volumes in our asphalt and retail and branded marketing segments and higher crude oil prices.
Refining and Unbranded Marketing Segment. Cost of sales for our refining and unbranded marketing segment were $5,996.8 million for the year ended December 31, 2011, compared to $3,311.8 million for the year ended December 31, 2010, an increase of $2,685.0 million. This increase was primarily due to increased refinery throughput as well as an increase in the cost of crude oil used by our refineries. The average price of WTI increased 19.7% from $79.41 per barrel for the year ended December 31, 2010, to $95.07 per barrel for the year ended December 31, 2011. The average price of Buena Vista crude increased 38.9% from $78.08 per barrel for the year ended December 31, 2010, to $108.43 per barrel for the year ended December 31, 2011. The average price of LLS crude increased 37.7% from $80.61 per barrel for the year ended December 31, 2010, to $110.98 per barrel for the year ended December 31, 2011.
Asphalt Segment. Cost of sales for our asphalt segment were $525.0 million for the year ended December 31, 2011, compared to $355.3 million for the year ended December 31, 2010, an increase of $169.7 million or 47.8%. The increase was


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due to higher asphalt sales volumes and higher crude oil costs for the year ended December 31, 2011 compared to the year ended December 31, 2010.
Retail and Branded Marketing Segment. Cost of sales for our retail and branded marketing segment were $1,291.9 million for the year ended December 31, 2011, compared to $912.9 million for the year ended December 31, 2010, an increase of $379.0 million or 41.5%. 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 $285.7 million for the year ended December 31, 2011, compared to $249.9 million for the year ended December 31, 2010, an increase of $35.8 million or 14.3%.
Refining and Unbranded Marketing Segment. Direct operating expenses for our refining and unbranded marketing segment for the year ended December 31, 2011 were $243.0 million, compared to $205.8 million for the year ended December 31, 2010, an increase of $37.2 million or 18.1%. This increase is due primarily to expenses associated with the startup of operations at our Bakersfield refinery and increased refinery throughput.
Asphalt Segment. Direct operating expenses for our asphalt segment for the year ended December 31, 2011, were $42.6 million, compared to $44.1 million for the year ended December 31, 2010, a decrease of $1.5 million or 3.4%. This decrease is primarily due to lower natural gas costs.
Selling, General and Administrative Expenses
Consolidated. SG&A expenses for the year ended December 31, 2011, were $143.1 million, compared to $128.1 million for the year ended December 31, 2010, an increase of $15.0 million or 11.7%, primarily due to higher employee-related costs and higher advertising and marketing costs for the year ended December 31, 2011.
Refining and Unbranded Marketing Segment. SG&A expenses for our refining and unbranded marketing segment for the year ended December 31, 2011, were $32.2 million, compared to $22.8 million for the year ended December 31, 2010, an increase of $9.4 million or 41.2%. This increase was primarily due to higher employee-related costs in the year ended December 31, 2011, and $3.5 million related to net bad debt recoveries and insurance premium refunds in the year ended December 31, 2010.
Asphalt Segment. SG&A expenses for our asphalt segment for the year ended December 31, 2011, were $5.1 million, compared to $5.5 million for the year ended December 31, 2010, a decrease of $0.4 million or 7.2%. This decrease is due primarily to lower employee related costs for the year ended December 31, 2011.
Retail and Branded Marketing Segment. SG&A expenses for our retail and branded marketing segment for the year ended December 31, 2011, were $105.1 million, compared to $99.0 million for the year ended December 31, 2010, an increase of $6.1 million or 6.2%. This increase was primarily attributable to higher advertising and marketing costs.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2011, was $113.7 million, compared to $102.1 million for the year ended December 31, 2010, an increase of $11.6 million or 11.4%, due primarily to capital expenditures for the acquisition and integration of the Bakersfield refining assets which began operations in June 2011. Also, depreciation and amortization for the year ended December 31, 2011, includes a full year of amortization of turnaround costs related to the 2010 Krotz Springs turnaround and restart in June 2010, and the write-off of deferred costs for our retail and marketing segment.
Operating Income (Loss)
Consolidated. Operating income (loss) for the year ended December 31, 2011, was $181.5 million, compared to $(160.8) million for the year ended December 31, 2010, an increase of $342.3 million. This increase was primarily due to overall higher refinery margins and throughput, higher retail fuel sales volumes and margins and increased merchandise sales and margins.
Refining and Unbranded Marketing Segment. Operating income (loss) for our refining and unbranded marketing segment was $184.0 million for the year ended December 31, 2011, compared to $(166.0) million for the year ended December 31, 2010, an increase of $350.0 million. This increase was primarily due to overall higher refining margins and increased refinery throughput.
Refinery operating margin at the Big Spring refinery was $18.84 per barrel for the year ended December 31, 2011, compared to $6.03 per barrel for the year ended December 31, 2010. This increase is primarily due to higher Gulf Coast 3/2/1 crack spreads. The average Gulf Coast 3/2/1 crack spread increased 184.3% to $23.37 per barrel for the year ended December 31, 2011, compared to $8.22 per barrel for the year ended December 31, 2010. Refinery operating margin at the


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California refineries was $(1.31) per barrel for the year ended December 31, 2011, compared to $1.08 per barrel for the year ended December 31, 2010. This decrease reflects the impact of the California refineries' shutdown until its restart in late March 2011, offset by higher West Coast 3/1/1/1 crack spreads. The average West Coast 3/1/1/1 crack spreads increased 10.3% to $9.20 per barrel for the year ended December 31, 2011, compared to $8.34 per barrel for the year ended December 31, 2010. The Krotz Springs refinery operating margin for the year ended December 31, 2011, was $3.05 per barrel, compared to $2.24 per barrel for the year ended December 31, 2010. The Krotz Springs refinery restarted operations in June 2010 after being down for the first five months of 2010 for a major turnaround. Additionally, the average Gulf Coast 2/1/1 high sulfur diesel crack spread for the year ended December 31, 2011, was $7.00 per barrel, compared to $5.26 per barrel for the year ended December 31, 2010.
Asphalt Segment. Operating loss for our asphalt segment was $24.5 million for the year ended December 31, 2011, compared to $12.5 million for the year ended December 31, 2010, an increase of $12.0 million or 96.4%. This increase in loss was primarily due to the decrease in asphalt sales margins resulting from the greater increase in crude oil prices relative to the increase in our asphalt sales prices.
Retail and Branded Marketing Segment. Operating income for our retail and branded marketing segment was $24.8 million for the year ended December 31, 2011, compared to $19.8 million for the year ended December 31, 2010, an increase of $5.0 million. This increase was primarily due to higher retail fuel sales volumes and margins and higher merchandise sales and margins.
Interest Expense
Interest expense was $88.3 million for the year ended December 31, 2011, compared to $94.9 million for the year ended December 31, 2010, a decrease of $6.6 million, or 7.0%. This decrease is primarily due to a charge of $6.7 million for the write-off of debt issuance costs associated with our prepayment of the Alon Refining Krotz Springs, Inc. revolving credit facility for the year ended December 31, 2010.
Income Tax Expense (Benefit)
Income tax expense (benefit) was $18.9 million for the year ended December 31, 2011, compared to $(90.5) million for the year ended December 31, 2010. This increase resulted from our higher pre-tax income for the year ended December 31, 2011, compared to the year ended December 31, 2010, and a decrease in the effective tax rate. Our effective tax rate was 30.2% for the year ended December 31, 2011, compared to an effective tax rate of 37.6% for the year ended December 31, 2010. The lower effective tax rate for the year ended December 31, 2011, was due primarily to benefits arising from carry-back claims on prior year income taxes.
Net Income (Loss) Attributable to Non-controlling Interest
Net income (loss) attributable to non-controlling interest was $1.2 million for the year ended December 31, 2011, compared to $(9.6) million for the year ended December 31, 2010, an increase of $10.8 million primarily due to its proportional share of the higher after-tax income in 2011.
Net Income (Loss) Available to Common Stockholders
Net income (loss) available to common stockholders was $42.5 million for the year ended December 31, 2011, compared to $(122.9) million for the year ended December 31, 2010, an increase of $165.4 million. This increase was attributable to the factors discussed above.
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Net Sales
Consolidated. Net sales for the year ended