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, 2012
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.)
 
 
 
12700 Park Central Dr., Suite 1600, 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. o
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, 2012, the last day of the registrant’s most recently completed second fiscal quarter was $129,500,553.
The number of shares of the Registrant’s common stock, par value $0.01 per share, outstanding as of March 1, 2013, was 62,464,123.
Documents incorporated by reference: Proxy statement of the registrant relating to the registrant’s 2013 annual meeting of stockholders, which is incorporated into Part III of this Form 10-K.
 
 



TABLE OF CONTENTS

 
 
 
 
 
MANAGEMENT EMPLOYMENT AGREEMENT, DATED AS OF MAY 1, 2008, BETWEEN KYLE C. MCKEEN AND ALON USA GP, LLC
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. Generally, the words "we", "our" and "us" include Alon USA Partners, LP and its subsidiaries (the "Partnership") as consolidated subsidiaries of Alon USA Energy, Inc. unless when used in disclosures of transactions or obligations between the Partnership and Alon USA Energy, Inc., or its other subsidiaries.
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, 2012, we operated 298 convenience stores in Central and West Texas and New Mexico, primarily under the 7-Eleven and Alon brand names. Our principal executive offices are located at 12700 Park Central Dr., Suite 1600, 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. 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, 12700 Park Central Dr., Suite 1600, 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 marketing, (ii) asphalt and (iii) retail. In the fourth quarter of 2012, based on a change in our internal reporting structure as a result of the


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Partnership's initial public offering, the branded marketing operations have been combined with the refining and marketing segment and are no longer included with the retail segment. Information for the branded marketing operations for the full year of 2012 is included in the refining and marketing segment. Information for the years ended December 31, 2011 and 2010 has been recast to provide a comparison to the current year results.
Additional information regarding our operating segments and properties is presented in the notes to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
Refining and Marketing
Our refining and marketing segment includes sour and heavy crude oil refineries that are located in Big Spring, Texas; 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.
Alon USA Partners, LP (NYSE: ALDW)
On November 26, 2012, the Partnership completed its initial public offering of 11,500,000 common units representing limited partner interests at a public offering price of $16.00 per common unit. As of December 31, 2012, the common units held by the public represent 18.4% of the Partnership's common units outstanding. Alon owns the remaining 81.6% of the Partnership's common units and Alon USA Partners GP, LLC (the "General Partner"), Alon's wholly owned subsidiary, owns 100% of the non-economic general partner interest in the Partnership.
The Partnership was formed to own, operate and grow our strategically located Big Spring refinery and its petroleum products marketing business. The Partnership is consolidated within our refining and marketing segment.
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.
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 which was primarily 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.


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Crude Oil Pipelines
We receive WTS crude oil and West Texas Intermediate (“WTI”), a light, sweet crude oil, primarily from regional common carrier pipelines. We also have the ability to access 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.
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 2012, gasoline accounted for approximately 50.3% 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”).
Distillates. In 2012, diesel and jet fuel accounted for approximately 32.5% of our Big Spring refinery’s production. All of the on-road specification diesel fuel we produce meets the EPA’s ultra-low sulfur diesel standard of 15 ppm. Our jet fuel production conforms to the JP-8 grade military specifications.
Asphalt. Asphalt accounted for approximately 5.9% of our Big Spring refinery’s production in 2012. 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 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.
Branded Marketing. We market motor fuels under the Alon brand name to distributors servicing approximately 640 locations, including our convenience stores. We supply our branded customers with motor fuels, brand support and payment processing services, in addition to the license of the Alon 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 64.6% 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, 2012, we sold 393.6 million gallons of branded motor fuel for distribution to our retail convenience stores and other retail distribution outlets. In 2012, approximately 95% 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 expired in August 2012 in accordance with its terms. We developed the Alon brand and logo in anticipation of this license expiration and converted all of our locations and substantially all locations served by our branded marketing business to the new Alon brand. Under the Alon brand we are no longer 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 21 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.


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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 36 distributors supplying approximately 115 additional stores. As part of the brand conversion process, all legacy FINA licenses have been 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 and is required to comply with the minimum standards program and utilize our payment card processing services.
Unbranded Marketing. We presently sell a majority of the diesel fuel and approximately 23.1% 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 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 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. In December 2012, the California refineries suspended operations, which included the Bakersfield hydrocracker.


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We refer to the Paramount, Bakersfield and Long Beach refineries together as our “California refineries." Our California refineries are included in our refining and 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 2012, at the California refineries, medium sour crude oil accounted for approximately 53.0% of crude oil input and heavy crude oil accounted for 47.0%. 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. During 2012 these refineries converted approximately 57.2% of crude oil into higher value products such as gasoline, diesel and jet fuel, and 28.2% converted to asphalt, fuel oil and sulfur. The remaining 14.6% of production was sold as unfinished feedstocks to other refineries and third parties.
Our California refineries operated at low rates for 2012, 2011 and 2010 due to continued efforts to optimize asphalt production with demand. During 2012, we averaged approximately 23.6% 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
During 2012, heavy crude oil accounted for approximately 47.0% of our crude oil input of which approximately 13.2% 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. In February 2012, we entered into an agreement with J. Aron to supply a majority of the California refineries' crude oil input requirements. 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 2012, CARBOB and other unfinished gasolines accounted for approximately 20.8% of our California refineries’ production. The California refineries utilize a computerized component blending system to optimize gasoline blending.
Distillates. In 2012, CARB diesel, Ultra-low sulfur EPA diesel, Jet A and military fuels accounted for approximately 36.4% of our California refineries’ production. All of the diesel fuel we produce is ultra-low sulfur CARB/EPA diesel. We produce both commercial Jet A and JP-8 grade military jet fuel.
Asphalt. In 2012, asphalt accounted for approximately 25.6% of our California refineries’ production. 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 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.


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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.
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 2012, the Krotz Springs refinery received crude oil from West Texas through the Amdel pipeline, which terminates at the Nederland terminal. The crude oil is then transported from the Nederland terminal to the Krotz Springs refinery via the Intracoastal Canal and the Atchafalaya River. The Krotz Springs refinery also has access to various types of domestic and foreign crude oils via an ExxonMobil pipeline (“EMPCo”), barge delivery, or truck rack delivery. Approximately 52% of the crude oil is received by pipeline with the remainder received by barge or truck.
We receive Light Louisiana Sweet ("LLS") and foreign crude oils from the EMPCo “Northline System.” The Northline System delivers LLS and foreign crude oils from the St. James, Louisiana crude oil terminalling complex.
In 2012, sweet crude oil accounted for all of the crude oil inputs at the Krotz Springs refinery, of which approximately 70.0% was Gulf Coast sweet crude oils and 30.0% was WTI priced crude oil.


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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 2012, gasoline accounted for approximately 42.4% 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 2012, diesel, light cycle oil and jet fuel accounted for approximately 41.4% 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 2012, slurry oil, LPG and petrochemical feedstocks accounted for approximately 16.2% 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 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 2012, approximately 5.9% of our Big Spring refinery’s production and 25.6% 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


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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 2012, 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 2012.
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 2012, Wright obtained approximately 83% 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
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, 2012, we operated 298 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.
The following table shows our owned and leased convenience stores by location:
Location
 
Owned
 
Leased
 
Total
Big Spring, Texas
 
6

 
2

 
8

Wichita Falls, Texas
 
9

 
2

 
11

Waco, Texas
 
11

 

 
11

Midland, Texas
 
10

 
7

 
17

Lubbock, Texas
 
17

 
4

 
21

Albuquerque, New Mexico
 
12

 
11

 
23

Odessa, Texas
 
13

 
22

 
35

Abilene, Texas
 
33

 
8

 
41

El Paso, Texas
 
13

 
70

 
83

Other locations in Central and West Texas
 
29

 
19

 
48

Total stores
 
153

 
145

 
298

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.
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.
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.
The principal competitive factors affecting our refining and marketing segment are costs of crude oil and other feedstocks, refinery efficiency, operating costs, refinery product mix and costs of product distribution and transportation.


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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. This pipeline was reversed in 2012 and currently transports lower costs WTI to Gulf Coast refiners, which include some of the world’s largest and most complex refineries, which results in greater competition to our Krotz Springs refinery.
The principal competitive factors affecting our 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 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 2013. Depending on the final standard, one 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 2007 the EPA adopted final rules to reduce the levels of benzene in gasoline on a nationwide basis. More specifically, beginning in 2011, refiners were required to 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 were required to 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 2012 in order for the Big Spring refinery to install controls to comply with the standards. We have spent $10.3 million through 2012 in order for the Krotz Springs refinery to install controls to meet the standards. On April 12, 2012, the EPA granted an extension of time through December 31, 2012 to comply with the annual average standard at our Krotz Springs refinery.


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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 generally 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%. The EPA has not yet finalized the 2013 renewable fuel percentage standard, but has proposed to raise it to approximately 9.6%. Each of our refineries received an extension of the deadline to comply with the renewable fuel standard. Therefore, we have not been required to blend renewable fuels or purchase RINs for compliance until 2013.
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 (“GHG”) emission levels to 1990 levels through a market based "cap-and-trade" program, have been issued. Although ongoing legal challenges could disrupt implementation of the program, 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 GHGs from our California refineries and possibly our other California terminals.
While it is possible that the federal government 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.
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 were required to install control technology, known as “Best Available Control Technology,” to address the GHG emissions.
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, at least 31 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 asphalt 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 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 indicated 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. To address the EPA's concerns, we have applied for a non-flexible permit. The Big Spring refinery is one of over 100 regulated facilities in Texas that will be required to obtain a new, non-flexible permit. We do not anticipate that the new non-flexible permit will require new pollution control equipment or a change in our operations. On August 13, 2012, the U.S. Fifth Circuit Court of Appeals vacated the EPA's final rule disapproving Texas' flexible permit program and remanded


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the program back to the EPA for further considerations. We are presently assessing our Big Spring refinery's air emissions permitting alternatives as a result of this ruling.
On August 14, 2012, the EPA sent letters to the petroleum refining industry regarding the EPA's recently issued enforcement alert entitled EPA Enforcement Targets Flaring Efficiency Violations. The Enforcement Alert identified new standards that refiners are required to meet for combustion efficiency. The EPA has already commenced enforcement against several refining companies and we understand that other settlement negotiations are underway.
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 Abilene, 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 and is currently being remediated. Approximately $3.0 million was spent in 2012 for all of these remediation projects of which our portion was $2.0 million. We estimate that an additional $1.9 million will be spent in 2013 with our portion being approximately $1.3 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 2012 for these remediation costs, of which our portion was $0.1 million, and we estimate an additional $0.7 million will be spent during 2013.
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 $2.2 million was spent in 2012 for these remediation costs, of which our portion was $0.6 million. We estimate that an additional $3.3 million will be spent during 2013, 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 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


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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, 2012, we had approximately 2,824 employees. Approximately 754 employees worked in our refining and marketing segment, of which 629 were employed at our refineries and approximately 125 were employed at our corporate offices in Dallas, Texas. Approximately 94 employees worked in our asphalt segment and approximately 1,976 employees worked in our retail segment.
Approximately 120 of the 190 employees at our Big Spring refinery are covered by a collective bargaining agreement that expires on April 1, 2015. None of the employees in our asphalt segment, retail segment or in our corporate offices are represented by a union. We consider our relations with our employees to be satisfactory.
Properties
Our principal properties are described above under the captions “Refining and Marketing,” “Asphalt” and “Retail” in Item 1. We believe that our facilities are generally adequate for our operations and are maintained in a good state of repair in the ordinary course of business. As of December 31, 2012, we were the lessee under a number of cancelable and non-cancelable leases for certain properties. Our leases are discussed more fully in Note 20 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.


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Executive Officers of the Registrant
Our current executive officers and key employees (identified by an asterisk), their ages as of March 1, 2013, and their business experience during at least the past five years are set forth below.
Name
 
Age
 
Position
David Wiessman
 
58

 
Executive Chairman of the Board of Directors
Jeff D. Morris
 
61

 
Vice Chairman of the Board of Directors
Paul Eisman
 
57

 
Chief Executive Officer and President
Shai Even
 
44

 
Senior Vice President and Chief Financial Officer
Claire A. Hart
 
57

 
Senior Vice President
Alan Moret
 
58

 
Senior Vice President of Supply
Michael Oster
 
41

 
Senior Vice President of Mergers and Acquisitions
Jimmy C. Crosby*
 
53

 
Vice President of Refining — Big Spring
Gregg Byers*
 
58

 
Vice President of Refining — Krotz Springs
Rick Bird*
 
59

 
Vice President of Asphalt Operations — Paramount
Kyle McKeen*
 
49

 
President and Chief Executive Officer of Alon Brands
Josef Lipman*
 
67

 
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.
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 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 materially from those projected.


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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 general economic conditions;
changes in the underlying demand for our products;
the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;
worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa and Latin America;
the level of foreign and domestic production of crude oil and refined products and the volume of crude oil, feedstock and refined products imported into and exported from the United States;
refinery utilization rates;
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 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 each of our 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.


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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 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.
Our ability to service our indebtedness will depend on our ability to generate cash in the future.
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 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, waterborne transportation accidents, 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.
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


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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 refinery at full capacity. A failure to operate our refinery at full capacity could adversely affect our profitability and cash flows. Alternatively, these more burdensome payment terms may require us to incur additional indebtedness under our revolving credit facility, which could increase our interest expense and adversely affect our cash flows.
Our arrangement with J. Aron exposes us to J. Aron related credit and performance risk.
We have supply and offtake agreements with J. Aron, who is our largest supplier of crude oil and largest customer of refined products. In the future, we could purchase up to 100% of our supply needs from J. Aron pursuant to this agreement. Additionally, we are obligated to repurchase all consigned inventories and certain other inventories upon termination of this agreement, which may be terminated by J. Aron as early as May 31, 2016. Relying on J. Aron’s ability to honor its fuel requirements purchase obligations exposes us to J. Aron’s credit and business risks. An adverse change in J. Aron’s business, results of operations, liquidity or financial condition could adversely affect its ability to perform its obligations, which could consequently have a material adverse effect on our business, results of operations or liquidity. In addition, we may be required to use substantial capital to repurchase inventories from J. Aron upon termination of the agreements, which could have a material adverse effect on our financial condition.
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


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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.
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.
In October 2006, we were contacted by Region 6 of the U.S. Environmental Protection Agency (“EPA”) and invited to enter into discussions under the EPA’s National Petroleum Refinery Initiative (the “Initiative”). This Initiative is a coordinated, integrated compliance and enforcement strategy to address federal Clean Air Act compliance issues at the nation’s largest petroleum refineries, including compliance with New Source Review/Prevention of Significant Deterioration requirements, New Source Performance Standards, Leak Detection and Repair requirements, and National Emission Standards for Hazardous Air Pollutants for Benzene Waste Operations. Since March 2000, at least 31 refining companies (representing over 90% of the U.S. refining capacity) have entered into “global settlements” under the Initiative. In February 2007, we committed in writing to enter into discussions with the EPA regarding our Big Spring refinery and, since that time, have held negotiations with the agency with respect to entering into a global settlement under the Initiative. Based on our on-going negotiations as well as consideration of prior settlements that the EPA has reached with other petroleum refineries under the Initiative, we believe that the EPA will seek relief under any global settlement 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 the Big Spring refinery. At this time, while we cannot estimate the cost of any such civil penalties, pollution controls or environmentally beneficial projects, these costs could be significant and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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 program.” According to the EPA, the Texas flexible permit program and its implementing rule was never approved by the EPA for inclusion in the Texas state clean-air


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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. We have agreed to convert the refinery’s non-flexible permit to a federally enforceable non-flexible permit and currently are in the process of such conversion. It is unclear whether we will have any obligation to install new air pollution controls or be assessed civil penalties. On August 13, 2012, the U.S. Fifth Circuit Court of Appeals vacated the EPA’s final rule disapproving Texas’ flexible permit program and remanded the program back to the EPA for further consideration. We are presently assessing our Big Spring refinery’s air emissions permitting alternatives as a result of this ruling.
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. For example, on June 1, 2012, the EPA issued final amendments to the New Source Performance Standards (“NSPS”) for petroleum refineries, including standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. EPA has finalized this rule and published it in the Federal Register on September 12, 2012. We are currently evaluating the effect that the NSPS rule may have on our refinery operations. As another example, the EPA proposed new “Tier 3” motor vehicle emission and fuel standards in 2012 which may result in further restrictions on the permissible levels of sulfur in gasoline. 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 but we may incur increased operating costs and capital expenditures to comply, which could be material. 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.
Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and a reduced demand for our refining services.
In December 2009 the EPA determined that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act including one rule that requires a reduction in emissions of GHGs from motor vehicles and another rule that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. The stationary source final rule addresses the permitting of GHG emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit programs, pursuant to which these permit programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources subject to permitting first and smaller sources subject to permitting later. Facilities required to obtain PSD permits for their GHG emissions will be required to reduce those emissions according to “best available control technology” standards for GHGs. The EPA’s rule relating to emissions of GHGs from large stationary sources of emissions has been subject to a number of legal challenges, with the federal D.C. Circuit Court of Appeals dismissing the challenges to EPA’s tailoring rule on June 26, 2012. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis, for emissions occurring after January 1, 2010.
In addition, the federal Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or monitoring and reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas produced by our customers, which could reduce demand for our refining services. One or more of these developments could have an adverse effect on our business, financial condition and results of operations.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.


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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 $6.3 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 $37.3 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 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


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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 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


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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, 2012, we employed approximately 190 people at our Big Spring refinery, approximately 120 of whom were covered by a collective bargaining agreement. The collective bargaining agreement expires on April 1, 2015. 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 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;
our ability to understand and capitalize on supply/demand balances in the markets of such acquired assets;
liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;
greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for investments to improve operating results;
difficulties in achieving anticipated operational improvements;
incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and
issuance of additional equity, which could result in further dilution of the ownership interest of existing stockholders.
We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.
We depend upon our subsidiaries for cash to meet our obligations and pay any dividends, and we do not own 100% of the stock of our operating subsidiaries.
We are a holding company. Our subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or pay dividends to our stockholders depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends, tax sharing payments or otherwise. Our subsidiaries’ ability to make any payments will depend on their earnings, 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, are parties to stockholders’ agreements with Alon Assets, Alon Operating and us, 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.” Alon owns 81.6% of the Partnership's common units and 100% of Alon USA


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Partners GP, LLC, the general partner of the Partnership. To the extent the Partnership is unable to make distributions to its partners, we may be unable to pay any dividends.
The wholesale fuel distribution industry is characterized by intense competition and fragmentation and our failure to effectively compete could adversely affect our business and results of operations.
The market for distribution of wholesale motor fuel is highly competitive and fragmented. We have numerous competitors, some of which have significantly greater resources and name recognition than us. We rely on our ability to provide reliable supply and value-added services and to control our operating costs in order to maintain our margins and competitive position. If we were to fail to maintain the quality of our services, customers could choose alternative distribution sources and our competitive position could be adversely affected. Furthermore, we compete against major oil companies with integrated marketing businesses. Through their greater resources and access to crude oil, these companies may be better able to compete on the basis of price or offer lower wholesale and retail pricing which could negatively affect our fuel margins. The occurrence of any of these events could have a material adverse effect on our business and results of operations.
Commodity derivative contracts may limit our potential gains, exacerbate potential losses, result in period-to-period earnings volatility and involve other risks.
We may enter into commodity derivatives contracts to mitigate our crack spread risk with respect to a portion of our expected gasoline and diesel production. We enter into these arrangements with the intent to secure a minimum fixed cash flow stream on the volume of products hedged during the hedge term. However, our hedging arrangements may fail to fully achieve these objectives for a variety of reasons, including our failure to have adequate hedging contracts, if any, in effect at any particular time and the failure of our hedging arrangements to produce the anticipated results. We may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, while intended to reduce the adverse effects of fluctuations in crude oil and refined product prices, such transactions may limit our ability to benefit from favorable changes in margins. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:
the volumes of our actual use of crude oil or production of the applicable refined products is less than the volumes subject to the hedging arrangement;
accidents, interruptions in feedstock transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refinery, or those of our suppliers or customers;
the counterparties to our futures contracts fail to perform under the contracts; or
a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.
As a result, the effectiveness of our risk mitigation strategy could have a material adverse impact on our financial results and our ability to make distributions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk.”
The adoption of regulations implementing recent financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.
The U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act in 2010 (the “Dodd-Frank Act”). This comprehensive financial reform legislation establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. The CFTC has adopted regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or derivative instruments would be exempt from these position limits. The Dodd-Frank Act may also require compliance with margin requirements and with certain clearing and trade-execution requirements in connection with certain derivative activities, although the application of those provisions to us is uncertain at this time. The legislation may also require certain counterparties to our commodity derivative contracts to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty, or cause the entity to comply with the capital requirements, which could result in increased costs to counterparties such as us. The final rules will be phased in over time according to a specified schedule which is dependent on finalization of certain other rules to be promulgated by the CFTC and the SEC.
The Dodd-Frank Act and any new regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, reduce the availability of some derivatives to protect against risks we


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encounter, reduce our ability to monetize or restructure our existing commodity derivative contracts and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and any new regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to make distributions or plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd- Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the Dodd-Frank Act and any new regulations result in lower commodity prices, our net sales could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations and therefore could have an adverse effect on our ability to make distributions.
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
 
 
 
 
 
2012
 
 
 
 
Fourth Quarter
 
$
18.37

 
$
12.06

Third Quarter
 
14.60

 
8.29

Second Quarter
 
9.40

 
7.52

First Quarter
 
11.94

 
8.61

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

Holders
As of March 1, 2013, there were 34 common stockholders of record.
Dividends
Common Stock Dividends. Alon paid regular quarterly cash dividends of $0.04 per share on Alon's common stock in 2012 on each of the following dates: March 15, 2012; June 15, 2012; September 19, 2012; and December 17, 2012. Additionally, the non-controlling interest stockholders of Alon Assets and Alon Operating received aggregate cash dividends of $524.
Alon paid regular quarterly cash dividends of $0.04 per share on Alon's common stock in 2011 on each of the following dates: March 15, 2011; June 15, 2011; September 15, 2011; and December 15, 2011. Additionally, the non-controlling interest stockholders of Alon Assets and Alon Operating received aggregate cash dividends of $704.
We intend to continue to pay quarterly cash dividends on our common stock at an annual rate of $0.16 per share. However, the declaration and payment of future dividends to holders of our common stock will be at the discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, legal requirements, restrictions in our debt agreements, the terms of our preferred stock and other factors our board of directors deems relevant.
Preferred Stock Dividends. We issued 358,000 and 328,000 shares in aggregate of common stock for payment of preferred stock dividends for the years ended December 31, 2012 and 2011, respectively.
Recent Sales of Unregistered Securities
On October 11, 2012, Alon issued 116,347 shares of Alon Common Stock to Jeff D. Morris, the Vice Chairman of the board of directors and a former officer of Alon. Pursuant to the terms of a shareholders agreement between Mr. Morris, Alon and two subsidiaries of Alon (Alon Assets and Alon Operating), Mr. Morris exchanged 621.98 shares of non-voting common stock of Alon Assets and 233.57 shares of non-voting common stock of Alon Operating for 116,347 shares of common stock in Alon.
On October 11, 2012, Alon issued 48,475 shares of Alon Common Stock to Claire A. Hart, a Senior Vice President of Alon. Pursuant to the terms of a shareholders agreement between Mr. Hart, Alon and two subsidiaries of Alon (Alon Assets and Alon Operating), Mr. Hart exchanged 259.14 shares of non-voting common stock of Alon Assets and 97.31 shares of non-voting common stock of Alon Operating for 48,475 shares of common stock in Alon.
On October 11, 2012, Alon issued 115,793 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


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non-voting common stock of Alon Operating for 115,793 shares of common stock in Alon and a cash payment of $300 (prior to tax withholding obligations).
The issuances of the shares of Common Stock to Messrs. Morris, Hart and Concienne were 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.
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, 2007 to December 31, 2012, 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.
 
12/2007
 
12/2008
 
12/2009
 
12/2010
 
12/2011
 
12/2012
Alon
$
100.00

 
$
34.10

 
$
25.90

 
$
23.22

 
$
34.37

 
$
72.43

S&P 500
100.00

 
63.00

 
79.67

 
91.67

 
93.61

 
108.59

Peer Group
100.00

 
30.63

 
27.30

 
39.99

 
41.75

 
79.70



28


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, 2009 and 2008, and the selected consolidated balance sheet data as of December 31, 2010, 2009 and 2008 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, 2012, 2011 and 2010, and the selected consolidated balance sheet data as of December 31, 2012 and 2011, are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
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,
 
 
2012
 
2011
 
2010
 
2009
 
2008
 
 
(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
 
 
 
 
 
Net sales
 
$
8,017,741

 
$
7,186,257

 
$
4,030,743

 
$
3,915,732

 
$
5,156,706

Operating costs and expenses
 
7,745,957

 
7,005,465

 
4,192,469

 
3,994,977

 
5,258,153

Gain on involuntary conversion of assets (1)
 

 

 

 

 
279,680

Gain (loss) on disposition of assets (2)
 
(2,309
)
 
729

 
945

 
(1,591
)
 
45,244

Operating income (loss)
 
269,475

 
181,521

 
(160,781
)
 
(80,836
)
 
223,477

Net income (loss) available to stockholders
 
79,134

 
42,507

 
(122,932
)
 
(115,156
)
 
82,883

Earnings (loss) per share, basic
 
$
1.29

 
$
0.77

 
$
(2.27
)
 
$
(2.46
)
 
$
1.77

Weighted average shares outstanding, basic
 
57,501

 
55,431

 
54,186

 
46,829

 
46,788

Earnings (loss) per share, diluted
 
$
1.24

 
$
0.69

 
$
(2.27
)
 
$
(2.46
)
 
$
1.72

Weighted average shares outstanding, diluted
 
63,917

 
61,401

 
54,186

 
46,829

 
49,583

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
 
$
387,810

 
$
69,560

 
$
21,330

 
$
283,145

 
$
(812
)
Investing activities
 
(104,980
)
 
(126,542
)
 
(40,925
)
 
(138,691
)
 
(610,322
)
Financing activities
 
(323,600
)
 
142,361

 
50,845

 
(122,471
)
 
560,973

BALANCE SHEET DATA:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
116,296

 
$
157,066

 
$
71,687

 
$
40,437

 
$
18,454

Working capital
 
87,242

 
99,452

 
990

 
84,257

 
250,384

Total assets
 
2,223,574

 
2,330,382

 
2,088,521

 
2,132,789

 
2,413,433

Total debt
 
587,017

 
1,050,196

 
916,305

 
937,024

 
1,103,569

Total equity
 
621,186

 
395,784

 
341,767

 
431,918

 
536,867

(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.


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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 oil, 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;
termination of our Supply and Offtake Agreements with J. Aron & Company (“J. Aron”), which include all our refineries and under which J. Aron is our largest supplier of crude oil and our largest customer of refined products. Additionally, we are obligated to repurchase all consigned inventories and certain other inventories upon termination of these Supply and Offtake Agreements;
changes in fuel and utility costs incurred by our facilities;
disruptions due to equipment interruption, pipeline disruptions, waterborne barge shipment disruptions or failures 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, casualty losses and other matters beyond our control;
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 Marketing Segment. Our refining and 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 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.
Alon owns the Big Spring refinery and wholesale marketing operations through Alon USA Partners, LP. Alon markets transportation fuels produced at its Big Spring refinery in West and Central Texas, Oklahoma, New Mexico and Arizona. Alon refers to its operations in these regions as its “physically integrated system” because it supplies its Alon branded and unbranded distributors in these regions with motor fuels produced at its Big Spring refinery and distributed through a network of pipelines and terminals which it either owns or has access to through leases or long-term throughput agreements.
We supply gasoline and diesel to approximately 640 Alon branded retail sites, including our retail segment convenience stores. Approximately 54% of the gasoline and 23% of the diesel motor fuel produced at the Big Spring refinery was transferred to our retail segment convenience stores at prices substantially determined by wholesale market prices. Additionally, we license the use of the Alon brand name and provide credit card processing services to approximately 115 licensed locations that are not under fuel supply agreements.
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 expired in August 2012 in accordance with its terms. We developed our own brand and logo in anticipation of the expiration of this license and have converted all of our locations and substantially all locations served by our branded marketing business to the new Alon brand. Under the Alon brand, we are no longer subject to the geographic limitations contained in the FINA license agreement.
We market refined products produced by our California refineries to wholesale distributors, other refiners and third parties primarily on the West Coast. At Bakersfield, we operate the hydrocracker unit and process 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. 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 marketing segment and at our Willbridge, Oregon refinery. Asphalt produced by the refineries in our refining and marketing segment is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. Our 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 Segment. Our retail segment operates 298 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 and Alon brand names. Substantially all of the motor fuel sold through our retail segment is supplied by our Big Spring refinery.


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Summary of 2012 Developments
On November 26, 2012, Alon USA Partners, LP (the "Partnership") completed its initial public offering (NYSE: ALDW) of 11,500,000 common units representing 18.4% of the Partnership's limited partner interests. The initial public offering generated proceeds of $167.8 million net of offering costs.
In conjunction with the Partnership's initial public offering, we entered into a $450.0 million Alon USA Term Loan. We assigned $250.0 million of the Alon USA Term loan to the Partnership as part of the initial public offering transactions. We primarily used proceeds from the initial public offering to fully repay the remaining outstanding balance of the Alon USA Term Loan.
In February 2012, we paid in full our obligations under the Paramount Petroleum Corporation Credit Facility.
In 2012, we began receiving WTI priced crude oils at the Krotz Springs refinery averaging throughput of 20,111 bpd for the full year of 2012.
In the first quarter of 2012, we entered into a Supply and Offtake Agreement (the “California Supply and Offtake Agreement”), with J. Aron & Company (“J. Aron”). Pursuant to the California 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 California refineries and (ii) we agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced by the California refineries.
Additionally, the Supply and Offtake Agreements for the Big Spring, Krotz Springs and California refineries were amended to extend the initial term until May 2019.
2012 Operational and Financial Highlights
Operating income for 2012 was $269.5 million, compared to $181.5 million in 2011. Our operational and financial highlights for 2012 include the following:
Combined refinery throughput for 2012 averaged 154,700 bpd, consisting of 68,946 bpd at the Big Spring refinery, 17,877 bpd at the California refineries and 67,877 bpd at the Krotz Springs refinery, compared to 146,149 bpd for 2011, 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.
Operating margin at the Big Spring refinery was $23.50 per barrel in 2012, compared to $20.89 per barrel in 2011. This increase is due to higher Gulf Coast 3/2/1 crack spreads and a widening sweet/sour spread.
Operating margin at the California refineries was $2.36 per barrel in 2012, compared to $(1.31) per barrel in 2011. This increase primarily reflects higher West Coast 3/1/1/1 crack spreads.
Operating margin at the Krotz Springs refinery was $8.30 per barrel in 2012, compared to $3.05 per barrel in 2011. This increase reflects the effects of the refinery taking advantage of lower crude oil costs with the addition of WTI priced crude oils and higher Gulf Coast 2/1/1 high sulfur diesel crack spreads.
The average WTI to WTS spread for 2012 was $5.46 per barrel compared to $2.06 per barrel for 2011. The average LLS to WTI spread for 2012 was $16.46 per barrel compared to $16.76 per barrel for 2011. The average WTI to Buena Vista spread for 2012 was $(14.48) per barrel compared to $(13.36) per barrel for 2011.
The average Gulf Coast 3/2/1 crack spread was $27.43 per barrel for 2012 compared to $23.37 per barrel for 2011. The average West Coast 3/1/1/1 crack spread for 2012 was $13.08 per barrel compared to $9.20 per barrel for 2011. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for 2012 was $11.29 per barrel compared to $7.00 per barrel for 2011.
Asphalt margins in 2012 were $42.64 per ton compared to $26.99 per ton in 2011. This increase is due primarily to higher asphalt sales prices in 2012 as compared to 2011. The average blended asphalt sales price increased 8.9% from $541.44 per ton in 2011 to $589.63 per ton in 2012 and the average non-blended asphalt sales price increased $45.67 per ton from $326.69 per ton in 2011 to $372.36 per ton in 2012.
Retail fuel sales volume increased by 9.0% from 156.7 million gallons in 2011 to 170.8 million gallons in 2012.
Cost of goods sold for 2012 was also impacted by losses on commodity swaps of $130.1 million compared to gains on commodity swaps of $30.0 million in 2011. Additionally, other income (loss) in 2012 was impacted by losses of $7.3 million associated with heating oil call option crack spread contracts compared to $36.3 million in 2011.


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Major Influences on Results of Operations
Refining and Marketing. Earnings and cash flow from our refining and marketing segment are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. These prices 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 this 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 hedge positions and certain inventory adjustments). Each refinery is compared to an industry benchmark that is intended to approximate that refinery's crude slate and product yield.
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 value of West Texas Intermediate Cushing, or WTI, a light, sweet crude oil, the market values of Gulf Coast conventional gasoline and ultra-low sulfur diesel.
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 value of Buena Vista crude oil, the market values of West Coast LA CARBOB pipeline gasoline, LA ultra-low sulfur pipeline diesel and LA 380 pipeline CST (fuel 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 value of Light Louisiana Sweet, or LLS, crude oil, the market values of Gulf Coast conventional gasoline and Gulf Coast high sulfur diesel.
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 and 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 and 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 is primarily comprised of LLS crude oil and WTI crude oil. We measure the cost of refining the LLS crude oil by calculating the difference between the average value of LLS crude oil and 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 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 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.


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Table of Contents

The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Crude oil and refined products are essentially commodities, and we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value under the LIFO inventory valuation methodology, price fluctuations generally have little effect on our financial results.
Asphalt. 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. Asphalt is transferred to our asphalt segment from our refining and marketing segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. 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. Earnings and cash flows from our retail segment are primarily affected by merchandise and motor fuel sales volumes and margins at our convenience stores. 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 retail sales are seasonal and peak in the second and third quarters of the year, while the first and fourth quarters usually experience lower overall sales.
Factors Affecting Comparability
Our financial condition and operating results over the three-year period ended December 31, 2012 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.
Initial Public Offering of Alon USA Partners, LP
On November 26, 2012, the Partnership completed its initial public offering of 11,500,000 common units representing limited partner interests. As of December 31, 2012, the 11,500,000 common units held by the public represent 18.4% of the Partnership's common units outstanding. Alon owns the remaining 81.6% of the Partnership's common units and Alon USA Partners GP, LLC (the "General Partner"), Alon's wholly-owned subsidiary, owns 100% of the non-economic general partner interest in the Partnership. The Partnership is consolidated within the refining and marketing segment.
The non-controlling interest in the Partnership on the December 31, 2012 consolidated balance sheet represents the investment by partners other than Alon, including those partners’ share of net income, distributions and accumulated other comprehensive income (loss) of the Partnership since the close of its initial public offering on November 26, 2012. Non-controlling interest in net income of the Partnership on Alon's consolidated statements of operations represents those partners’ share of net income of the Partnership.
Costs Associated with Early Repayment of Debt
Interest expense for the year ended December 31, 2012, includes a charge for original issuance discount of $9.6 million associated with the repayment of the Alon Brands Term loan and $18.8 million associated with the repayment of the Alon USA Term Loan Credit Facility. In addition, we recorded a write-off of debt issuance costs of $8.8 million associated with the early repayment of credit facilities. Interest expense for the year ended December 31, 2010 includes a charge of $6.7 million for the write-off of debt issuance costs related to the prepayment of the Alon Refining Krotz Springs, Inc. revolving credit facility.
Certain Derivative Impacts
Included in unrealized (gains) losses on commodity swaps and cost of goods sold in the aggregate for the years ended December 31, 2012 and 2011 are recorded losses of $130.1 million and gains of $30.0 million on commodity swaps, respectively. We had no significant unrealized or realized gains or losses on commodity swaps for the year ended December 31, 2010.
Included in other income (loss), net in the consolidated statements of operations, we had losses on heating oil call option crack spread contracts of $7.3 million, $36.3 million and $4.1 million for the years ended December 31, 2012, 2011 and 2010, respectively.


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Table of Contents

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.
Results of Operations
The period to period comparisons of our results of operations have been prepared using the historical periods included in our consolidated financial statements. We refer to our financial statement line items in the explanation of our period-to-period changes in results of operations. Below are general definitions of what those line items include and represent.
Net Sales. Net sales consist primarily of sales of refined petroleum products through our refining and marketing segment and asphalt segment and sales of merchandise, food products, and motor fuels, through our retail segment.
For the refining and marketing segment, net sales consist of gross sales, net of customer rebates, discounts and excise taxes and includes inter-segment sales to our asphalt and retail segments, which are eliminated through consolidation of our financial statements. Asphalt sales consist of gross sales, net of any discounts and applicable 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. Retail net sales consist of gross merchandise sales, less rebates, commissions and discounts, and gross fuel sales, including motor fuel taxes. Our retail merchandise sales are affected primarily by competition and seasonal influences.
Cost of Sales. Refining and marketing cost of sales includes crude oil and other raw materials, inclusive of transportation costs. Asphalt cost of sales includes costs of purchased asphalt, blending materials and transportation costs. Retail cost of sales includes cost of sales for motor fuels and for merchandise. Motor fuel cost of sales represents the net cost of purchased fuel, including transportation costs and associated motor fuel taxes. Merchandise cost of sales includes the delivered cost of merchandise purchases, net of merchandise rebates and commissions. Cost of sales excludes depreciation and amortization expense.
Direct Operating Expenses. Direct operating expenses, which relate to our refining and marketing and asphalt segments, include costs associated with the actual operations of our refineries 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, 2012, 2011 and 2010. 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,
 
2012
 
2011
 
2010
 
(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
Net sales (1)
$
8,017,741

 
$
7,186,257

 
$
4,030,743

Operating costs and expenses:
 
 
 
 
 
Cost of sales
7,117,449

 
6,494,883

 
3,712,358

Unrealized (gains) losses on commodity swaps
31,936

 
(31,936
)
 

Direct operating expenses
313,242

 
285,666

 
249,933

Selling, general and administrative expenses (2)
161,401

 
143,122

 
128,082

Depreciation and amortization (3)
121,929

 
113,730

 
102,096

Total operating costs and expenses
7,745,957

 
7,005,465

 
4,192,469

Gain (loss) on disposition of assets
(2,309
)
 
729

 
945

Operating income (loss)
269,475

 
181,521

 
(160,781
)
Interest expense (4)
(129,572
)
 
(88,310
)
 
(94,939
)
Equity earnings of investees
7,162

 
5,128

 
5,439

Gain on bargain purchase (5)

 

 
17,480

Other income (loss), net (6)
(6,584
)
 
(35,673
)
 
9,716

Income (loss) before income tax expense (benefit)
140,481

 
62,666

 
(223,085
)
Income tax expense (benefit)
49,884

 
18,918

 
(90,512
)
Net income (loss)
90,597

 
43,748

 
(132,573
)
Net income (loss) attributable to non-controlling interest
11,463

 
1,241

 
(9,641
)
Net income (loss) available to stockholders
$
79,134

 
$
42,507

 
$
(122,932
)
Earnings (loss) per share, basic
$
1.29

 
$
0.77

 
$
(2.27
)
Weighted average shares outstanding, basic (in thousands)
57,501

 
55,431

 
54,186

Earnings (loss) per share, diluted
$
1.24

 
$
0.69

 
$
(2.27
)
Weighted average shares outstanding, diluted (in thousands)
63,917

 
61,401

 
54,186

Cash dividends per share
$
0.16

 
$
0.16

 
$
0.16

CASH FLOW DATA:
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
387,810

 
$
69,560

 
$
21,330

Investing activities
(104,980
)
 
(126,542
)
 
(40,925
)
Financing activities
(323,600
)
 
142,361

 
50,845

OTHER DATA:
 
 
 
 
 
Adjusted EBITDA (7) (A)
$
394,291

 
$
263,977

 
$
(44,475
)
Capital expenditures (8)
93,901

 
112,625

 
46,707

Capital expenditures for turnaround and chemical catalyst
11,460

 
9,734

 
13,131

(A)
Adjusted EBITDA does not exclude unrealized gains (losses) on commodity swaps of $(31,936) and $31,936 for the years ended December 31, 2012 and 2011, respectively. Adjusted EBITDA also does not exclude losses on heating oil call option crack spread contracts of $7,297 and $36,280 for the years ended December 31, 2012 and 2011, respectively. Adjusted EBITDA excluding the impact of these items would be $433,524 and $268,321 for the years ended December 31, 2012 and 2011, respectively.


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Table of Contents

 
As of December 31,
 
2012
 
2011
BALANCE SHEET DATA:
 
 
 
Cash and cash equivalents
$
116,296

 
$
157,066

Working capital
87,242

 
99,452

Total assets
2,223,574

 
2,330,382

Total debt
587,017

 
1,050,196

Total equity
621,186

 
395,784

(1)
Includes excise taxes on sales by the retail segment of $66,563, $60,686 and $54,930 for the years ended December 31, 2012, 2011 and 2010, respectively.
(2)
Includes corporate headquarters selling, general and administrative expenses of $960, $752 and $752 for the years ended December 31, 2012, 2011 and 2010, respectively, which are not allocated to our three operating segments.
(3)
Includes corporate depreciation and amortization of $2,127, $1,925 and $1,380 for the years ended December 31, 2012, 2011 and 2010, respectively, which are not allocated to our three operating segments.
(4)
Interest expense for the year ended December 31, 2012 includes a charge of $9,624 for the write-off of unamortized original issuance discount associated with our repayment of the Alon Brands Term Loan and charges of $18,750 and $8,826 for the write-off of unamortized original issuance discount and the write-off of debt issuance costs associated with the repayment of the Alon USA Energy, Inc. term loans, respectively. Interest expense 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.
(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 years ended December 31, 2012 and 2011, is substantially the loss on heating oil call option 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)
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 stockholders to Adjusted EBITDA for the periods presented.
(8)
Includes corporate capital expenditures of $2,228, $1,540 and $2,335 for the years ended December 31, 2012, 2011 and 2010, respectively, which are not allocated to our three operating segments.


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Table of Contents

REFINING AND MARKETING SEGMENT (A)
 
 
 
 
 
 
Year Ended December 31,
 
2012
 
2011
 
2010
 
(dollars in thousands, except per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
 
 
 
 
 
Net sales (1)
$
7,241,935

 
$
6,558,625

 
$
3,469,921

Operating costs and expenses:
 
 
 
 
 
Cost of sales
6,519,547

 
6,028,709

 
3,311,771

Unrealized (gains) losses on commodity swaps
31,936

 
(31,936
)
 

Direct operating expenses
278,725

 
243,018

 
205,838

Selling, general and administrative expenses
51,215

 
39,190

 
28,888

Depreciation and amortization
103,638

 
90,701

 
82,047

Total operating costs and expenses
6,985,061

 
6,369,682

 
3,628,544

Gain (loss) on disposition of assets
(2,502
)
 
12

 
656

Operating income (loss)
$
254,372

 
$
188,955

 
$
(157,967
)
KEY OPERATING STATISTICS:
 
 
 
 
 
Per barrel of throughput:
 
 
 
 
 
Refinery operating margin – Big Spring (2)
$
23.50

 
$
20.89

 
$
7.64

Refinery operating margin – CA Refineries (2)
2.36

 
(1.31
)
 
1.08

Refinery operating margin – Krotz Springs (2)
8.30

 
3.05

 
2.24

Refinery direct operating expense – Big Spring (3)
4.00

 
4.23

 
5.05

Refinery direct operating expense – CA Refineries (3)
12.59

 
7.32

 
7.73

Refinery direct operating expense – Krotz Springs (3)
3.85

 
3.67

 
4.36

Capital expenditures
$
68,112

 
$
92,022

 
$
39,319

Capital expenditures for turnaround and chemical catalyst
11,460

 
9,734

 
13,131

PRICING STATISTICS:
 
 
 
 
 
WTI crude oil (per barrel)
$
94.14

 
$
95.07

 
$
79.41

WTS crude oil (per barrel)
88.68

 
93.01

 
77.26

Buena Vista crude oil (per barrel)
108.62

 
108.43

 
78.08

LLS crude oil (per barrel)
111.53

 
110.98

 
80.61

Crack spreads (3/2/1) (per barrel):
 
 
 
 
 
Gulf Coast
$
27.43

 
$
23.37

 
$
8.22

Crack spreads (3/1/1/1) (per barrel):
 
 
 
 
 
West Coast
$
13.08

 
$
9.20

 
$
8.34

Crack spreads (2/1/1) (per barrel):
 
 
 
 
 
Gulf Coast high sulfur diesel
$
11.29

 
$
7.00

 
$
5.26

Crude oil differentials (per barrel):
 
 
 
 
 
WTI less WTS
$
5.46

 
$
2.06

 
$
2.15

LLS less WTI
16.46

 
16.76

 
2.49

WTI less Buena Vista
(14.48
)
 
(13.36
)
 
1.33

Product price (dollars per gallon):
 
 
 
 
 
Gulf Coast unleaded gasoline
$
2.82

 
$
2.75

 
$
2.05

Gulf Coast ultra-low sulfur diesel
3.05

 
2.97

 
2.16

Gulf Coast high sulfur diesel
2.99

 
2.91

 
2.10

West Coast LA CARBOB (unleaded gasoline)
3.03

 
2.89

 
2.21

West Coast LA ultra-low sulfur diesel
3.11

 
3.05

 
2.21

Natural gas (per MMBTU)
2.83

 
4.03

 
4.38

(A)
In the fourth quarter of 2012, based on a change in our internal reporting structure as a result of the Partnership's initial public offering, the branded marketing operations have been combined with the refining and marketing segment and are no longer included with the retail segment. Information for the branded marketing operations for the full year of 2012 is included in the refining and marketing segment. Information for the years ended December 31, 2011 and 2010 has been recast to provide a comparison to the current year results.
                                                              


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Table of Contents

THROUGHPUT AND PRODUCTION DATA:
BIG SPRING REFINERY
Year Ended December 31,
2012
 
2011
 
2010
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
WTS crude
52,190

 
75.7

 
51,202

 
80.4

 
39,349

 
80.2

WTI crude
14,396

 
20.9

 
10,023

 
15.8

 
7,288

 
14.9

Blendstocks
2,360

 
3.4

 
2,389

 
3.8

 
2,391

 
4.9

Total refinery throughput (4)
68,946

 
100.0

 
63,614

 
100.0

 
49,028

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline
34,637

 
50.3

 
31,105

 
49.1

 
24,625

 
50.7

Diesel/jet
22,329

 
32.5

 
20,544

 
32.3

 
15,869

 
32.7

Asphalt
4,084

 
5.9

 
4,539

 
7.1

 
2,827

 
5.8

Petrochemicals
4,054

 
5.9

 
3,837

 
6.0

 
2,939

 
6.0

Other
3,706

 
5.4

 
3,488

 
5.5

 
2,341

 
4.8

Total refinery production (5)
68,810

 
100.0

 
63,513

 
100.0

 
48,601

 
100.0

Refinery utilization (6)
 
 
97.3
%
 
 
 
90.8
%
 
 
 
68.2
%
THROUGHPUT AND PRODUCTION DATA:
CALIFORNIA REFINERIES
Year Ended December 31,
2012
 
2011
 
2010
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
Medium sour crude
9,071

 
50.7

 
5,677

 
24.9

 
3,502

 
19.9

Heavy crude
8,038

 
45.0

 
14,962

 
65.6

 
13,688

 
77.8

Blendstocks
768

 
4.3

 
2,176

 
9.5

 
406

 
2.3

Total refinery throughput (4)
17,877

 
100.0

 
22,815

 
100.0

 
17,596

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline
3,716

 
20.8

 
4,969

 
22.0

 
2,629

 
15.4

Diesel/jet
6,503

 
36.4

 
7,938

 
35.1

 
3,704

 
21.6

Asphalt
4,580

 
25.6

 
6,632

 
29.4

 
5,919

 
34.6

Heavy unfinished
2,603

 
14.6

 
2,292

 
10.2

 
4,483

 
26.2

Other
462

 
2.6

 
735

 
3.3

 
372

 
2.2

Total refinery production (5)
17,864

 
100.0

 
22,566

 
100.0

 
17,107

 
100.0

Refinery utilization (6)
 
 
23.6
%
 
 
 
28.5
%
 
 
 
25.9
%
THROUGHPUT AND PRODUCTION DATA:
KROTZ SPRINGS REFINERY
Year Ended December 31,
2012
 
2011
 
2010
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
WTI crude
20,111

 
29.6

 

 

 

 

Gulf Coast sweet crude
46,924

 
69.2

 
58,979

 
98.8

 
38,345

 
97.7

Blendstocks
842

 
1.2

 
741

 
1.2

 
899

 
2.3

Total refinery throughput (4)
67,877

 
100.0

 
59,720

 
100.0

 
39,244

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline
29,081

 
42.4

 
24,852

 
41.4

 
15,812

 
40.1

Diesel/jet
28,466

 
41.4

 
27,436

 
45.6

 
18,986

 
48.2

Heavy Oils
2,709

 
3.9

 
2,904

 
4.8

 
1,515

 
3.8

Other
8,464

 
12.3

 
4,914

 
8.2

 
3,107

 
7.9

Total refinery production (5)
68,720

 
100.0

 
60,106

 
100.0

 
39,420

 
100.0

Refinery utilization (6)
 
 
80.7
%
 
 
 
77.9
%
 
 
 
46.1
%


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Table of Contents

(1)
Net sales include intersegment sales to our asphalt and retail 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 hedge positions and certain inventory adjustments) 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 excludes realized losses on commodity swaps of $84,084 for the year ended December 31, 2012. The refinery operating margins for the year ended December 31, 2012 also excludes approximately $8,000 primarily from negative inventory effects.
The refinery operating margin for the year ended December 31, 2011 excludes approximately $10,000 primarily from negative inventory effects.
The refinery operating margin for the year ended December 31, 2010 excludes an unrealized loss associated with consignment inventory of $8,134, a benefit of $4,515 to cost of sales for inventory adjustments related to the Bakersfield refinery acquisition and approximately $14,000 primarily from negative inventory effects.
(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 by the applicable refinery’s total throughput volumes. Direct operating expenses of $3,356 and $3,373 for the years ended December 31, 2011 and 2010, respectively, related to the period prior to the start-up of the Bakersfield refinery 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 years ended December 31, 2012 and 2011, reflects substantially eight months of throughput data as the California refineries were not in operation for the first quarter of 2012 and 2011 or December 2012 and 2011. 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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ASPHALT SEGMENT
 
 
 
 
 
 
 
 
Year Ended December 31,
 
 
2012
 
2011
 
2010
 
(dollars in thousands, except per ton data)
STATEMENTS OF OPERATIONS DATA:
 
 
 
 
 
 
Net sales
 
$
603,896

 
$
554,549

 
$
399,334

Operating costs and expenses:
 

 

 
 
Cost of sales (1)
 
563,516

 
524,964

 
355,272

Direct operating expenses
 
34,517

 
42,648

 
44,095

Selling, general and administrative expenses
 
4,230

 
5,080

 
5,542

Depreciation and amortization
 
5,866

 
6,376

 
6,875

Total operating costs and expenses
 
608,129

 
579,068

 
411,784

Gain on disposition of assets
 
505

 

 

Operating loss
 
$
(3,728
)
 
$
(24,519
)
 
$
(12,450
)
KEY OPERATING STATISTICS:
 
 
 
 
 
 
Blended asphalt sales volume (tons in thousands) (2)
 
842

 
915

 
780

Non-blended asphalt sales volume (tons in thousands) (3)
 
105

 
181

 
83

Blended asphalt sales price per ton (2)
 
$
589.63

 
$
541.44

 
$
477.26

Non-blended asphalt sales price per ton (3)
 
372.36

 
326.69

 
326.16

Asphalt margin per ton (4)
 
42.64

 
26.99

 
51.06

Capital expenditures
 
9,420

 
3,225

 
1,557

(1)
Cost of sales includes intersegment purchases of asphalt blends from our refining and marketing segment at prices which approximate wholesale market prices. These intersegment purchases are eliminated through consolidation of our financial statements.
(2)
Blended asphalt represents base asphalt that has been blended with other materials necessary to sell the asphalt as a finished product.
(3)
Non-blended asphalt represents base material asphalt and other components that require additional blending before being sold as a finished product.
(4)
Asphalt margin is a per ton measurement calculated by dividing the margin between net sales and cost of sales by the total sales volume. Asphalt margins are used in the asphalt industry to measure operating results related to asphalt sales.


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RETAIL SEGMENT (A)
 
 
 
 
 
 
 
 
Year Ended December 31,
 
 
2012
 
2011
 
2010
 
(dollars in thousands, except per gallon data)
STATEMENTS OF OPERATIONS DATA:
 
 
 
 
 
 
Net sales (1)
 
$
907,918


$
833,470

 
$
666,398

Operating costs and expenses:
 



 
 
Cost of sales (2)
 
770,394


701,597

 
550,225

Selling, general and administrative expenses
 
104,996


98,100

 
92,900

Depreciation and amortization
 
10,298


14,728

 
11,794

Total operating costs and expenses
 
885,688

 
814,425

 
654,919

Gain (loss) on disposition of assets
 
(312
)

717

 
289

Operating income
 
$
21,918

 
$
19,762

 
$
11,768

KEY OPERATING STATISTICS:
 
 
 
 
 
 
Number of stores (end of period)
 
298

 
302

 
304

Retail fuel sales (thousands of gallons)
 
170,848

 
156,662

 
142,155

Retail fuel sales (thousands of gallons per site per month) (4)
 
50

 
45

 
39

Retail fuel margin (cents per gallon) (5)
 
20.2

 
21.4

 
18.2

Retail fuel sales price (dollars per gallon) (6)
 
$
3.47

 
$
3.41

 
$
2.70

Merchandise sales
 
$
315,082

 
$
298,233

 
$
281,674

Merchandise sales (per site per month) (4)
 
$
88

 
$
82

 
$
77

Merchandise margin (7)
 
32.5
%
 
32.8
%
 
31.9
%
Capital expenditures
 
$
14,141

 
$
15,838

 
$
3,496

(A)
In the fourth quarter of 2012, based on a change in our internal reporting structure as a result of the Partnership's initial public offering, the branded marketing operations have been combined with the refining and marketing segment and are no longer included with the retail segment. Information for the branded marketing operations for the full year of 2012 is included in the refining and marketing segment. Information for the years ended December 31, 2011 and 2010 has been recast to provide a comparison to the current year results.
                                                              
(1)
Includes excise taxes on sales of $66,563, $60,686 and $54,930 for the years ended December 31, 2012, 2011 and 2010, respectively.
(2)
Cost of sales includes intersegment purchases of motor fuels from our refining and marketing segment at prices which approximate wholesale market prices. These intersegment purchases are eliminated through consolidation of our financial statements.
(3)
At December 31, 2012, we had 298 retail convenience stores of which 286 sold fuel. At December 31, 2011, we had 302 retail convenience stores of which 290 sold fuel.
(4)
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.
(5)
Retail fuel sales price per gallon represents the average sales price for motor fuels sold through our retail convenience stores.
(6)
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, 2012 Compared to the Year Ended December 31, 2011
Net Sales
Consolidated. Net sales for the year ended December 31, 2012 were $8,017.7 million, compared to $7,186.3 million for the year ended December 31, 2011, an increase of $831.4 million. This increase was primarily due to higher refinery throughput volumes in our refining and marketing segment, increased sales volumes in our retail segment and higher refined product prices.
Refining and Marketing Segment. Net sales for our refining and marketing segment were $7,241.9 million for the year ended December 31, 2012, compared to $6,558.6 million for the year ended December 31, 2011, an increase of $683.3 million. This increase was due to higher refined product prices and higher refinery throughput in the year ended December 31, 2012 compared to the year ended December 31, 2011.
Combined refinery throughput for the year ended December 31, 2012, averaged 154,700 bpd, consisting of 68,946 bpd at the Big Spring refinery, 17,877 bpd at the California refineries and 67,877 bpd at the Krotz Springs refinery, compared to a combined average throughput of 146,149 bpd for the year ended December 31, 2011, 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.
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, 2012, increased $0.07, or 2.5%, to $2.82, compared to $2.75 for the year ended December 31, 2011. The average per gallon price of Gulf Coast ultra low-sulfur diesel for the year ended December 31, 2012, increased $0.08, or 2.7%, to $3.05, compared to $2.97 for the year ended December 31, 2011. The average per gallon price for Gulf Coast high-sulfur diesel for the year ended December 31, 2012, increased $0.08, or 2.7%, to $2.99, compared to $2.91 for the year ended December 31, 2011. The average per gallon price of West Coast LA CARBOB gasoline for the year ended December 31, 2012, increased $0.14, or 4.8%, to $3.03, compared to $2.89 for the year ended December 31, 2011. The average price per gallon of West Coast LA ultra low-sulfur diesel for the year ended December 31, 2012, increased $0.06, or 2.0%, to $3.11, compared to $3.05 for the year ended December 31, 2011.
Asphalt Segment. Net sales for our asphalt segment were $603.9 million for the year ended December 31, 2012, compared to $554.5 million for the year ended December 31, 2011, an increase of $49.4 million or 8.9%. This increase was due primarily to higher asphalt sales price for our asphalt products, partially offset by a decrease in asphalt sales volumes for the year ended December 31, 2012. The average blended asphalt sales price increased 8.9% from $541.44 per ton for the year ended December 31, 2011, to $589.63 per ton for the year ended December 31, 2012, and the average non-blended asphalt sales price increased 14.0% from $326.69 per ton for the year ended December 31, 2011, to $372.36 per ton for the year ended December 31, 2012. The asphalt sales volume decreased 13.6% from 1,096 thousand tons for the year ended December 31, 2011, to 947 thousand tons for the year ended December 31, 2012.
Retail Segment. Net sales for our retail segment were $907.9 million for the year ended December 31, 2012, compared to $833.5 million for the year ended December 31, 2011, an increase of $74.4 million or 8.9%. This increase was primarily attributable to increases in retail fuel sales prices and volumes and merchandise sales.
Cost of Sales
Consolidated. Cost of sales were $7,117.4 million for the year ended December 31, 2012, compared to $6,494.9 million for the year ended December 31, 2011, an increase of $622.5 million. This increase was primarily due to higher refinery throughput volumes in our refining and marketing segment and increased sales volumes in our retail segment.
Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $6,519.5 million for the year ended December 31, 2012, compared to $6,028.7 million for the year ended December 31, 2011, an increase of $490.8 million. This increase was primarily due to increased refinery throughput with the cost of crude oil used by our refineries staying relatively flat. The average price of WTI decreased 1.0% from $95.07 per barrel for the year ended December 31, 2011, to $94.14 per barrel for the year ended December 31, 2012. The average price of Buena Vista crude increased 0.2% from $108.43 per barrel for the year ended December 31, 2011, to $108.62 per barrel for the year ended December 31, 2012. The average price of LLS crude increased 0.5% from $110.98 per barrel for the year ended December 31, 2011, to $111.53 per barrel for the year ended December 31, 2012.
Asphalt Segment. Cost of sales for our asphalt segment were $563.5 million for the year ended December 31, 2012, compared to $525.0 million for the year ended December 31, 2011, an increase of $38.5 million or 7.3%. The increase was primarily due to higher crude oil costs and transportation costs for the year ended December 31, 2012 compared to the year ended December 31, 2011.


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Retail Segment. Cost of sales for our retail segment were $770.4 million for the year ended December 31, 2012, compared to $701.6 million for the year ended December 31, 2011, an increase of $68.8 million or 9.8%. This increase was primarily attributable to increases in retail fuel sales prices and volumes and merchandise costs.
Direct Operating Expenses
Consolidated. Direct operating expenses were $313.2 million for the year ended December 31, 2012, compared to $285.7 million for the year ended December 31, 2011, an increase of $27.5 million or 9.6%.
Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the year ended December 31, 2012 were $278.7 million, compared to $243.0 million for the year ended December 31, 2011, an increase of $35.7 million or 14.7%. This increase is due primarily to increased refinery throughput.
Asphalt Segment. Direct operating expenses for our asphalt segment for the year ended December 31, 2012, were $34.5 million, compared to $42.6 million for the year ended December 31, 2011, a decrease of $8.1 million or 19.0%. 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, 2012, were $161.4 million, compared to $143.1 million for the year ended December 31, 2011, an increase of $18.3 million or 12.8%, primarily due to higher employee-related costs and higher advertising and marketing costs for the year ended December 31, 2012.
Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the year ended December 31, 2012, were $51.2 million, compared to $39.2 million for the year ended December 31, 2011, an increase of $12.0 million or 30.6%. This increase was primarily due to higher employee-related costs in the year ended December 31, 2012.
Asphalt Segment. SG&A expenses for our asphalt segment for the year ended December 31, 2012, were $4.2 million, compared to $5.1 million for the year ended December 31, 2011, a decrease of $0.9 million or 17.6%. This decrease is due primarily to lower employee-related costs for the year ended December 31, 2012.
Retail Segment. SG&A expenses for our retail segment for the year ended December 31, 2012, were $105.0 million, compared to $98.1 million for the year ended December 31, 2011, an increase of $6.9 million or 7.0%. This increase was primarily attributable to higher advertising and marketing costs.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2012, was $121.9 million, compared to $113.7 million for the year ended December 31, 2011, an increase of $8.2 million or 7.2%, due primarily to a full year of depreciation related to capital expenditures for the acquisition and integration of the Bakersfield refining assets which began operations in June 2011.
Operating Income (loss)
Consolidated. Operating income for the year ended December 31, 2012, was $269.5 million, compared to $181.5 million for the year ended December 31, 2011, an increase of $88.0 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 Marketing Segment. Operating income for our refining and marketing segment was $254.4 million for the year ended December 31, 2012, compared to $189.0 million for the year ended December 31, 2011, an increase of $65.4 million. This increase was primarily due to overall higher refining margins and increased refinery throughput.
Refinery operating margin at the Big Spring refinery was $23.50 per barrel for the year ended December 31, 2012, compared to $20.89 per barrel for the year ended December 31, 2011. This increase is primarily due to higher Gulf Coast 3/2/1 crack spreads. The average Gulf Coast 3/2/1 crack spread increased 17.4% to $27.43 per barrel for the year ended December 31, 2012, compared to $23.37 per barrel for the year ended December 31, 2011. Refinery operating margin at the California refineries was $2.36 per barrel for the year ended December 31, 2012, compared to $(1.31) per barrel for the year ended December 31, 2011. This increase is primarily due to higher West Coast 3/1/1/1 crack spreads. The average West Coast 3/1/1/1 crack spreads increased 42.2% to $13.08 per barrel for the year ended December 31, 2012, compared to $9.20 per barrel for the year ended December 31, 2011. The Krotz Springs refinery operating margin for the year ended December 31, 2012, was $8.30 per barrel, compared to $3.05 per barrel for the year ended December 31, 2011. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the year ended December 31, 2012 was $11.29 per barrel, compared to $7.00 per barrel for the year ended December 31, 2011.
Asphalt Segment. Operating loss for our asphalt segment was $3.7 million for the year ended December 31, 2012, compared to $24.5 million for the year ended December 31, 2011, a decrease of $20.8 million or 84.9%. This decrease in loss


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was primarily due to the increase in asphalt sales margins resulting from the greater increase in asphalt sales prices relative to the change in crude oil prices.
Retail Segment. Operating income for our retail segment was $21.9 million for the year ended December 31, 2012, compared to $19.8 million for the year ended December 31, 2011, an increase of $2.1 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 $129.6 million for the year ended December 31, 2012, compared to $88.3 million for the year ended December 31, 2011, an increase of $41.3 million, or 46.8%. This increase is primarily due to a charge of $9,624 for the write-off of unamortized original issuance discount associated with our repayment of the Alon Brands Term Loan and charges of $18,750 and $8,826 for the write-off of unamortized original issuance discount and unamortized debt issuance costs associated with the repayment of the Alon USA Energy, Inc. term loans, respectively, for the year ended December 31, 2012.
Income Tax Expense
Income tax expense was $49.9 million for the year ended December 31, 2012, compared to $18.9 million for the year ended December 31, 2011. This increase resulted from our higher pre-tax income for the year ended December 31, 2012, compared to the year ended December 31, 2011, and an increase in the effective tax rate. Our effective tax rate was 35.5% for the year ended December 31, 2012, compared to an effective tax rate of 30.2% for the year ended December 31, 2011.
Net Income Attributable to Non-controlling Interest
Net income attributable to non-controlling interest was $11.5 million for the year ended December 31, 2012, compared to $1.2 million for the year ended December 31, 2011, an increase of $10.3 million primarily due to its proportional share of the higher after-tax income in 2012. Net income attributable to non-controlling interest for the year ended December 31, 2012 reflects the increase in ownership of outside entities as a result of the 11,500,000 limited partnership units sold in conjunction with the Partnership's initial public offering.
Net Income Available to Stockholders
Net income available to stockholders was $79.1 million for the