10-K 1 alj-20131231x10k.htm 10-K ALJ-2013.12.31-10K

 
 
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, 2013
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, 2013, the last day of the registrant’s most recently completed second fiscal quarter was $341,784,224.
The number of shares of the Registrant’s common stock, par value $0.01 per share, outstanding as of March 1, 2014, was 68,807,049.
Documents incorporated by reference: Proxy statement of the registrant relating to the registrant’s 2014 annual meeting of stockholders, which is incorporated into Part III of this Form 10-K.
 
 



TABLE OF CONTENTS

 
 
 
 
 




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 “Alon,” “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 an independent refiner and marketer of petroleum products, operating primarily in the South Central, Southwestern and Western regions of the United States. We own 100% of the general partner and 81.6% of the limited partner interests in Alon USA Partners, LP (NYSE: ALDW), which owns a crude oil refinery in Texas with an aggregate crude oil throughput capacity of approximately 70,000 barrels per day. In addition, we directly own crude oil refineries in Louisiana and California, with an aggregate crude oil throughput capacity of approximately 144,000 barrels per day. We are a leading marketer of asphalt, which we distribute primarily through asphalt terminals located predominately in the Western United States. We are the largest 7-Eleven licensee in the United States and operate approximately 300 convenience stores in Texas and New Mexico.
We were incorporated in 2000 under Delaware law. Our principal executive offices are located at 12700 Park Central Drive, 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. 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 Drive, 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
Our crude oil refineries are located in Texas, California and Louisiana and have a combined throughput capacity of approximately 214,000 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.


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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 Partnership’s initial public offering, the branded marketing operations were combined with the refining and marketing segment and are no longer included with the retail segment. Information for the branded marketing operations for the years ended December 31, 2013 and 2012 is included in the refining and marketing segment. Information for the year ended December 31, 2011 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 214,000 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, 2013, the common units held by the public represent 18.4% of the Partnership’s common units outstanding. We own the remaining 81.6% of the Partnership’s common units and Alon USA Partners GP, LLC (the “General Partner”), our wholly-owned subsidiary, owns 100% of the non-economic general partner interest in the Partnership. 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. All of the crude oil processed at our refinery is West Texas crude oil based on Midland pricing, which has typically traded at a discount to Cushing pricing.
Our Big Spring refinery produces ultra-low sulfur gasoline, ultra-low sulfur diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum-based products. This refinery typically converts approximately 90% of its feedstock into finished products such as gasoline, diesel, jet fuel and petrochemicals, with the remaining 10% primarily converted to asphalt and liquefied petroleum gas.
Big Spring Refinery Raw Material Supply
West Texas crude oil has typically accounted for all of our crude oil input at the Big Spring refinery, of which 67.9% was West Texas Sour (“WTS”) crude oil and 32.1% was West Texas Intermediate (“WTI”) crude oil during 2013. Our Big Spring refinery is located in Howard County, Texas in the Permian Basin. It is the closest refinery to Midland, Texas, which is the largest origination terminal for West Texas crude oil. We believe the location and sour crude processing capability of our Big Spring refinery provide us strategic cost advantages for sourcing our crude oil requirements. Our close proximity to the Midland and Cushing markets allows us to source WTS and WTI crude oils, both of which typically trade at a considerable discount to imported waterborne crude oils, such as Brent. Our ability to purchase these less expensive crude oils provides us a cost advantage compared to refineries located on the U.S. Gulf Coast that utilize more expensive waterborne crude oils to produce the refined products they sell in our market area. In addition, our Big Spring refinery’s ability to process substantial volumes of WTS provides us with a further cost advantage. WTS has historically traded at a discount to WTI due to the cost associated with eliminating sulfur content from sour crude in the refining process. Because our Big Spring refinery is able to process substantial volumes of WTS, our overall feedstock costs are generally lower than those of refineries that are not capable of processing high volumes of WTS and therefore must utilize a greater percentage of sweeter, more expensive crudes such as WTI Cushing.


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In addition to cost advantages resulting from our proximity to domestic crude oil sources and our refinery’s capability to process substantial volumes of WTS, we have been able to capitalize on the oversupply of West Texas crudes in Midland, the largest origination terminal for West Texas crude oil, resulting from increased production in the Permian Basin coupled with infrastructure constraints in Cushing, Oklahoma. Although West Texas crudes are typically transported to Cushing for sale, current logistical and infrastructure constraints at Cushing are limiting the ability of Permian Basin producers to transport their production to Cushing. The resulting oversupply of West Texas crudes at Midland has depressed Midland crude prices and enabled us to access an increased portion of our crude supply at discounted prices to Cushing. Moreover, by sourcing West Texas crude oils at Midland, we are able to eliminate the cost of transporting crude to and from Cushing.
J. Aron and Company (“J. Aron”), through arrangements with various oil companies, currently supplies the majority of the Big Spring refinery’s crude oil input materials.
Crude Oil Pipelines
We receive WTS crude oil and 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 when the economics for processing those crude oils are more favorable than processing locally-sourced crude oils. 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 2013, gasoline accounted for 50.4% 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. Gasoline 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 2013, diesel and jet fuel accounted for 33.5% 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 5.4% of our Big Spring refinery’s production in 2013. 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 processing 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 West and Central 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 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.
Each branded location is required to participate in our Clean Team brand excellence program and utilize our payment card processing services.  Under the Clean Team program, each branded location is graded quarterly by a third-party rating agency that specializes in convenience store assessment and reporting.  Each location is graded on the physical appearance and condition of the store’s interior and exterior.  The inspections also include evaluations of customer service provided by employees.


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For the year ended December 31, 2013, we sold 445.3 million gallons of branded motor fuel for distribution to our retail convenience stores and other retail distribution outlets. In 2013, approximately 94% of Alon’s branded marketing operations, including retail operations, were supplied by our Big Spring refinery. In 2013, the retail segment’s gasoline and diesel sales represented 27.7% and 8.6%, respectively, of our Big Spring refinery’s gasoline and diesel production.
Distribution Network and Distributor Arrangements. We sell motor fuel to our retail locations and to 23 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 and contain incentives and penalties based on the consistency of their purchases.
Brand Licensing. In exchange for licensing fees, we license the Alon brand to distributors supplying geographic areas outside of our physically-integrated system. In addition to use of the Alon brand, we also provide payment card processing services, advertising programs and loyalty and other marketing programs to 30 distributors supplying 93 additional stores. This licensing program allows us to expand the geographic footprint of our brand, thereby increasing its recognition. Each licensee is also required to participate in our Clean Team brand excellence program and utilize our payment card processing services.
Unbranded Marketing. We presently sell a majority of the diesel fuel and 22.8% 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 five product terminals in Big Spring, Abilene, Orla, and Wichita Falls, Texas and Duncan, Oklahoma to market transportation fuels produced at our Big Spring refinery. All five of these terminals are physically integrated with our Big Spring refinery through the product pipelines we utilize. Three of these five terminals, Big Spring, Abilene 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
Our California refineries operate as one integrated refinery with a combined throughput capacity as currently configured of 70,000 bpd. Our California refineries did not process crude oil in 2013 and ran at low throughput rates in 2012 and 2011 due to the high cost of crude oil relative to product yield and low asphalt demand.
Our Paramount refinery 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.
The Long Beach refinery is located on 19 acres in Long Beach, California. 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.


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The Bakersfield refinery is located on approximately 600 acres in Bakersfield, California. 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.  We have not operated the Bakersfield refinery as a traditional coking refinery. In 2012 and 2011, we used the hydrocracker and other hydrotreating units located at the Bakersfield refinery to process untreated vacuum gas oil produced by our other California refineries. This process allowed us to convert untreated vacuum gas oil to lighter products such as CARBOB gasoline, CARB diesel, and other petroleum products.
We have applied for permits to construct a rail facility at the Bakersfield refinery, which would allow us to source cost-advantaged crude oils at the refinery. This rail facility could receive up to two unit trains of crude oil per day. The crude oil received at the rail facility could be for use by third parties or by us upon the restart of the Bakersfield refinery.
Our California refineries have the capability to process substantial volumes of heavy crude oils. The Paramount and Long Beach refineries are connected by pipelines we own.
Our California refineries have the capability to produce CARBOB gasoline, CARB diesel, jet fuel, asphalt and other petroleum products.
California Refineries Raw Material Supply
Historically our California refineries received crude oil primarily from common carrier, private carrier and our owned pipelines. We have the capability to receive crude oil by rail at each of the California refineries’ locations. We are party to an agreement with J. Aron to supply a majority of the California refineries’ crude oil input requirements. Other feedstocks, including butane and gasoline blendstocks, can be delivered by truck and pipeline. This combination of transportation arrangements allows the California refineries to receive and optimize the crude slate of waterborne domestic and foreign crude oil, along with California crude oil.
California Refineries Transportation Fuel Marketing
We sell refined products in both the wholesale rack and bulk markets. Our marketing of gasoline and diesel fuels is focused on the Southern California market.
California Product Pipelines/Terminal
The California refineries utilize product pipelines, truck racks and terminals to distribute refined products.
California Feedstock Pipelines
The California refineries have a feedstock pipeline and terminal system that is capable of supplying untreated vacuum gas oil and other unfinished products to other Los Angeles Basin refineries and third party terminals.
Krotz Springs Refinery
The Krotz Springs refinery located in Krotz Springs, Louisiana, has a throughput capacity of 74,000 bpd. The Krotz Springs refinery is strategically located on approximately 381 acres on the Atchafalaya River in central Louisiana. This location provides access to crude from waterborne barge, pipeline, railcar and truck. The refinery has direct access to the Colonial product pipeline system (“Colonial Pipeline”). This combination of logistical assets provides us with diversified access to locally-sourced, domestic 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.
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 began receiving crude oil sourced from West Texas. This crude is transported through the Amdel pipeline to the Nederland terminal located near the Gulf Coast and from there is transported to the Krotz Springs refinery by barge 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”), rail or truck rack delivery. We are capable of receiving 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.


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In 2013, sweet crude oil accounted for all of the crude oil inputs at the Krotz Springs refinery, of which 52.9% was Gulf Coast sweet crude oils and 47.1% was WTI priced crude oil.
J. Aron, through arrangements with various oil companies, supplies the majority of the 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 2013, gasoline accounted for 44.6% of our Krotz Springs refinery’s production.
Distillates. In 2013, diesel, light cycle oil and jet fuel accounted for 40.2% of our Krotz Springs refinery’s production.
Heavy Oils and Other. In 2013, slurry oil, LPG and petrochemical feedstocks accounted for 15.2% 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 Colonial Pipeline has over 5,500 miles of pipelines and transports products to more than 260 marketing terminals located near 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, are transported via barge for sale. Barges originating at the Krotz Springs refinery 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 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
As of December 31, 2013, we owned or operated 11 asphalt terminals located in Texas (Big Spring), Washington (Richmond Beach), California (Paramount, Long Beach, Elk Grove, Mojave and Bakersfield), Oregon (Willbridge) - sold in January 2014, Arizona (Phoenix 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.
In addition to gasoline and distillates, our California and Big Spring refineries are capable of producing significant quantities of vacuum tower bottoms (“VTB”), which can be utilized to produce asphalt. We believe our asphalt production capabilities provide the opportunity to realize higher netbacks than those attainable by processing 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.
As part of our efforts to maximize the return generated by the production of asphalt, we have an exclusive license to use 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 ground tire rubber (“GTR”) asphalt manufacturing process with respect to asphalt sold in California.
Asphalt produced by our Big Spring refinery is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. We sell asphalt produced at our Big Spring refinery or purchased from third parties primarily as paving asphalt to road and materials manufacturers and highway construction/maintenance contractors as GTR, polymer modified or emulsion asphalt. Sales of asphalt, particularly paving asphalts, are seasonal with the majority of our sales occurring between May and October.


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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 2013, Wright obtained approximately 55% 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 have the exclusive right to use the 7-Eleven trade name in substantially all of our existing retail markets and many surrounding areas. As of December 31, 2013, we operated 297 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

 
69

 
82

Other locations in Central and West Texas
 
29

 
19

 
48

Total stores
 
153

 
144

 
297

The merchandise requirements of our convenience stores are serviced at least weekly by over 100 direct-store delivery (“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 Core-Mark 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.
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., ExxonMobil, Chevron and Royal Dutch Shell) and other major independent refining and marketing entities (e.g., Phillips 66, Marathon Petroleum and Valero) 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.
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 West Texas crude oil, which we believe provides us with transportation cost advantages over many of our regional competitors.
The markets 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.


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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, Tesoro, U.S. Oil, Western, San Joaquin Refining, Ergon and HollyFrontier as well as regional and national asphalt marketing companies that have little or no associated refining operations. The principal factors affecting competitiveness in asphalt markets are cost, supply reliability, consistency of product quality, transportation cost and capability to produce the range of high performance products necessary to meet the requirements of customers.
Our major retail competitors include CST Brands, Chevron, 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.
Fuels. The federal 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. In March 2014, the EPA announced final new “Tier 3” motor vehicle emission and fuel standards. Under the final rule, gasoline must contain no more than 10 ppm sulfur on an annual average basis beginning on January 1, 2017; however, approved small refineries have until January 1, 2020 to meet the standard. We believe that the Big Spring and Krotz Springs refineries each satisfy the definition of a small refinery. We estimate that the capital investment associated with upgrades necessary to meet these new required sulfur levels, on a consolidated basis, will be less than $30 million.
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 Big Spring, Krotz Springs and California refineries currently meet the standards established by the EPA.
We are subject to the Renewable Fuel Standards 2 (“RFS2”) which requires refiners to blend renewable fuels (e.g., ethanol, biodiesel) into their finished transportation fuels or purchase renewable identification number credits (“RINs”) in lieu of blending. The EPA establishes new annual renewable fuel percentage standards for each compliance year in the preceding year. In August 2013, the EPA announced the final 2013 renewable fuel percentage standard, which raised the mandate from 9.6% to 9.74%. RINs costs for 2013 were $14.9 million for our Big Spring refinery, the first year we were subject to RFS2. The California refineries did not process crude oil in 2013 and as a result were not subject to the RFS2 requirements. The Krotz Springs refinery received an exemption from the RFS2 for 2013 and as a result recorded no costs associated with RINs. The EPA has published the proposed volume mandates for 2014, which are generally lower than the volumes for 2013 and lower than statutory mandates.
Air Emissions. 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.


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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 December 2010, the EPA reached a settlement agreement with numerous parties under which it agreed to promulgate New Source Performance Standards (“NSPS”) to regulate greenhouse gas emissions from petroleum refineries. Although the EPA has not yet proposed NSPS to regulate GHG for petroleum refineries, the EPA has proposed NSPS to regulate GHG for electric utilities. The timing of the EPA’s proposal for petroleum refineries, as well as the need for or costs of any required controls, are not known at this time.
In October 2006, we were contacted by Region 6 of the EPA and invited to enter into discussions under the EPA’s National Petroleum Refinery Initiative. This initiative addresses what the EPA deems to be the most significant Clean Air Act compliance concerns affecting the petroleum refining industry. To date, at least 32 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 and our Paramount and Long Beach refineries. Based on prior settlements that the EPA has reached with other petroleum refineries under the initiative, we anticipate that we would be required to pay a civil penalty, install air pollution controls, and enhance certain operations 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 civil penalties, but they 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.
In July 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 would have been required to obtain a new, non-flexible permit. In August 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 considerations. We are presently assessing our Big Spring refinery’s air emissions permitting alternatives as a result of this ruling.
In August 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 of their flares. 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. We are also remediating historical soil and groundwater contamination at the Abilene,


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Southlake and Wichita Falls terminals that were in existence at the time they were acquired. We spent $0.7 million in 2013 for remediation costs and we estimate an additional $1.3 million will be spent during 2014.
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 a prior owner of the Paramount refinery and Lakewood Tank Farm. We also have remediation projects at the Long Beach refinery and Pipeline 145 that existed at the time of our acquisitions. A total of $3.1 million was spent for all four remediation projects in 2013 of which our portion was $2.0 million. We estimate that an additional $1.8 million will be spent in 2014 with our portion being $1.3 million.
In conjunction with our acquisition of the Long Beach refinery in September 2006, we acquired a seven-year environmental insurance policy, which was renewed in 2013 for an additional three years. 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.
We are currently remediating historical soil and groundwater contamination at our Richmond Beach, Washington and Willbridge, Oregon terminals. We spent $0.4 million in 2013 for remediation costs and we estimate an additional $0.5 million will be spent during 2014. We sold the Willbridge, Oregon terminal in January 2014 and will have no further remediation obligations.
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. We spent $4.0 million in 2013 for these remediation costs, which were fully covered by the previous owner. We estimate that an additional $9.3 million will be spent during 2014, of which our portion will be $0.2 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.
Environmental Insurance. We have two environmental insurance policies at the Big Spring refinery. One of the policies is commonly referred to as an environmental clean-up cost containment, or “cost cap” policy and provides coverage of remediation costs for pre-existing conditions at the time of our acquisition of the Big Spring refinery in 2000. This policy has an initial retention of $20.0 million during the first ten years after the acquisition with a $1.0 million annual retention increase during the remainder of the term of the policy, currently the retention is $24.0 million. The other policy is known as an environmental response, compensation and liability insurance policy, or ERCLIP, and provides insurance 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 or penalties and a self-insured 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 Indemnity Insurance Company, which is currently in liquidation. However, we are currently unaware of any potential claims against these policies.
Environmental Indemnity to HEP. In connection with our sale of pipelines and terminals to Holly Energy Partners, LP (“HEP”), we entered into an Environmental Agreement pursuant to which we agreed to indemnify HEP against certain costs and liabilities incurred by HEP to the extent resulting from the existence of environmental conditions at levels requiring remediation under applicable environmental laws at the pipelines or terminals prior to the sale or from our violation of environmental laws with respect to the pipelines and terminals occurring prior to the effective closing date of the sale but, in each case, excluding any such increased costs and liabilities to the extent caused by the actions of HEP. Our environmental indemnification obligations under the Environmental Agreement expire after February 2015. In addition, our indemnity obligations under the Environmental Agreement with respect to the sale of these pipelines and terminals are subject to HEP first incurring $100,000 of damages as a result of pre-existing environmental conditions or violations. Further, our environmental indemnity obligations under the Environmental Agreement, together with 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, are also limited to an aggregate liability amount of $20.0 million.


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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 Pipeline, LP (“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.
Occupational Safety and Health Regulation. We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, process safety standards and control of occupational exposure to regulated substances, could subject us to significant fines or cause us to spend significant amounts on compliance, which could have a material adverse effect on our business, financial position, results of operations and the cash flows.
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 (“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, 2013, we had approximately 2,740 employees. Approximately 615 employees worked in our refining and marketing segment, of which approximately 480 were employed at our refineries and approximately 135 were employed at our corporate offices in Dallas, Texas. Approximately 130 employees worked in our asphalt segment and approximately 1,995 employees worked in our retail segment.
Approximately 200 employees worked at our Big Spring refinery, approximately 135 of whom 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, 2013, 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, 2014, and their business experience during at least the past five years are set forth below.
Name
 
Age
 
Position
David Wiessman
 
59
 
Executive Chairman of the Board of Directors
Jeff D. Morris
 
62
 
Vice Chairman of the Board of Directors
Paul Eisman
 
58
 
Chief Executive Officer and President
Shai Even
 
45
 
Senior Vice President and Chief Financial Officer
Claire A. Hart
 
58
 
Senior Vice President
Alan Moret
 
59
 
Senior Vice President of Supply
Michael Oster
 
42
 
Senior Vice President of Mergers and Acquisitions
Jimmy C. Crosby
 
54
 
Senior Vice President of Refining
James Ranspot
 
43
 
Senior Vice President, General Counsel and Secretary
Jeff Brorman*
 
46
 
Vice President of Refining — Big Spring
Gregg Byers*
 
59
 
Vice President of Refining — Krotz Springs
Glen Clausen*
 
54
 
Vice President of Refining — California Refineries
Kyle McKeen*
 
50
 
President and Chief Executive Officer of Alon Brands
Josef Lipman*
 
68
 
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 30 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 1987, Mr. Wiessman became Chief Executive Officer of, and a stockholder in, Bielsol Investments (1987) Ltd., or (“Bielsol”), which acquired a 50% interest in Alon Israel in 1992. 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 has also been Executive Chairman of the Board of Directors of Alon Holdings Blue Square-Israel, Ltd., which is listed on the NYSE and the Tel Aviv Stock Exchange, or (“TASE”), since 2003; Chairman of Blue Square Real Estate Ltd., which is listed on the TASE, since 2006; and Executive Chairman of the Board and President of Dor-Alon Energy in Israel (1988) Ltd., which is listed on the TASE, since 2005, 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 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.
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 Senior Vice President of Refining since November 2012. Mr. Crosby served as 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.
James Ranspot has served as Senior Vice President, General Counsel and Secretary since March 2013. He served as Alon’s Chief Legal Counsel - Corporate from August 2010 until March 2013, and Assistant General Counsel from June 2006 to August 2010. Prior to joining Alon, Mr. Ranspot practiced corporate and securities law, with a focus on public and private merger and acquisition transactions and public securities offerings.
Jeff Brorman has served as our Vice President of Refining - Big Spring since March 2013. Prior to being appointed to this position, Mr. Brorman has served in the following positions at the Big Spring Refinery: Operations Manager from January 2009 to March 2013, Technical Manager from May 2005 to January 2009 including Refinery Rebuild Manager from February 2008 to October 2008, Capital Projects Manager from May 2004 to May 2005, Southside Operations Superintendent from August 2000 to May 2004. Prior to joining Alon, Mr. Brorman worked with Atofina Petrochemicals, Inc. from August 1996 to August 2000 as a mechanical engineer.
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.
Glenn Clausen has served as our Vice President of Refining - West Coast since November 2012. Prior to being appointed to this position, Mr. Clausen was Director of Operations at various sites on the West Coast since December 2008 (Paramount December 2008-November 2010, Paramount/Long Beach November 2010-April 2012, Paramount/Long Beach/Bakersfield April 2012 to November 2012).  Prior to joining Alon, Mr. Clausen worked with Texaco from 1982 to 1994, Equilon from 1994-2000, and Shell Oil Products from 2000-2008 in various technical and supervisorial positions.
Kyle McKeen has served as President and Chief Executive Officer of Alon Brands, Inc., our subsidiary that manages our retail operations, as well as having responsibility for our wholesale marketing operations, since May 2008. From 2005 to 2008, Mr. McKeen served as President and Chief Operating Officer of Carter Energy, an independent energy marketer supporting over 600 retailers by providing fuel supply, merchandising and marketing support, and consulting services. Prior to joining Carter Energy in 2005, Mr. McKeen was a member of the Board of Managers of Alon Brands, Inc. 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.


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ITEM 1A. RISK FACTORS.
The occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report on Form 10‑K or in any other of our filings with the SEC could have a material adverse effect on our business, financial position, results of operations and cash flows. In evaluating an investment in any of our securities, you should consider carefully, among other things, the factors and the specific risks set forth below. This Annual Report on Form 10-K contains forward-looking statements that involve risks and uncertainties. See “Forward-Looking Statements” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of the factors that could cause actual results to differ materially from those projected.
The price volatility of crude oil, other feedstocks, refined products and fuel and utility services may have a material adverse effect on our earnings, profitability and cash flows.
Our refining and marketing earnings, profitability and cash flows from operations depend primarily on the margin 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 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


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affected by the general level of crude oil prices, and significant increases in crude oil prices could result in substantial working capital requirements to maintain inventory volumes.
In addition, the volatility in costs of natural gas, electricity and other utility services used by our refineries and other operations affect our operating costs. Utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for utility services in both local and regional markets. Future increases in utility prices may have a negative effect on our earnings, profitability and cash flows.
Our profitability depends, in part, on the differential between the cost of crude oils processed by our refineries and those processed by our competitors. Changes in this differential could negatively affect our profitability.
We select grades of crude oil to process based, in part, on each individual refinery’s configuration and operating units. Our profitability is partially derived from our ability to purchase and process crude oil feedstocks that are less expensive than those 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 requirements, 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.


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We are subject to interruptions of supply as a result of our reliance on pipelines for transportation of crude oil and refined products.
Our refineries receive a substantial percentage of their crude oil and deliver a substantial percentage of their refined products through pipelines. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, earthquakes, hurricanes, governmental regulation, terrorism, other third party action or any of the types of events described in the preceding risk factor. Our prolonged inability to use any of the pipelines that we use to transport crude oil or refined products could have a material adverse effect on our business, results of operations and cash flows.
If the price of crude oil increases significantly, it could reduce our margin on our fixed-price asphalt supply contracts.
We enter into fixed-price asphalt supply contracts pursuant to which we agree to deliver asphalt to customers at future dates. We set the pricing terms in these agreements based, in part, upon the price of crude oil at the time we enter into each contract. If the price of crude oil increases from the time we enter into the contract to the time we produce the asphalt, our margins from these sales could be adversely affected.
Our operating results are seasonal and generally lower in the first and fourth quarters of the year.
Demand for gasoline and asphalt products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. Seasonal fluctuations in highway traffic also affect motor fuels and merchandise sales in our retail stores. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. This seasonality is most pronounced in our asphalt business.
If the price of crude oil increases significantly, it could limit our ability to purchase enough crude oil to operate our refineries at full capacity.
We rely in part on borrowings and letters of credit under our 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 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.


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Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.
We compete with a broad range of companies in our refining and marketing operations. Many of these competitors are integrated, multinational oil companies that are substantially larger than we are. Because of their diversity, integration of operations, larger capitalization, larger and more complex refineries and greater resources, these companies may be better able to withstand disruptions in operations and volatile market conditions, to offer more competitive pricing and to obtain crude oil in times of shortage.
We are not engaged in the exploration and production business and therefore do not produce any of our crude oil feedstocks. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production. Competitors that have their own crude production are at times able to offset losses from refining operations with profits from producing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries, such as wind, solar and hydropower, that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual customers. If we are unable to compete effectively with these competitors, both within and outside our industry, there could be a material adverse effect on our business, financial condition, results of operations and cash flows.
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 suspend our operations.
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 (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. To date, at least 32 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


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that the EPA has reached with other petroleum refineries under the Initiative, we believe that we would be required to pay a civil penalty, install air pollution controls, and enhance certain operations and maintenance programs 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 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 had agreed to convert the refinery’s non-flexible permit to a federally enforceable non-flexible permit. In August 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.
We are subject to the RFS2 which requires refiners to blend renewable fuels (e.g., ethanol, biodiesel) into their finished transportation fuels or purchase RINs in lieu of blending. Beginning in 2013, the Big Spring refinery became subject to the RFS2. RINs costs for 2013 were $14.9 million for the Big Spring refinery. The Krotz Springs refinery received an exemption from the RFS2 for 2013 and was not required to purchase RINs or waiver credits for compliance. The California refineries did not process crude oil in 2013 and as a result were not subject to the RFS2 requirements. During 2013, the price of RINs was extremely volatile. The EPA has published the proposed volume mandates for 2014, which are generally lower than the volumes for 2013 and lower than statutory mandates. We cannot predict the future prices of RINs or waiver credits (for cellulosic biofuels from the EPA), but the costs to obtain the necessary number of RINs and waiver credits could be material.
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, in March 2014, the EPA announced final new “Tier 3” motor vehicle emission and fuel standards. Under the final rule, gasoline must contain no more than 10 ppm sulfur on an annual average basis beginning on January 1, 2017; however, approved small refineries have until January 1, 2020 to meet the standard. We believe that the Big Spring and Krotz Springs refineries each satisfy the definition of a small refinery. Although we estimate that the capital investment associated with upgrades necessary to meet these new required sulfur levels will be less than $30 million, we are not able to predict the impact of other 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 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 in June 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


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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.
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 $6.9 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 $37.4 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 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 releases and contamination or any associated third-party proceedings and investigations, or in connection with any of our indemnification obligations to HEP or Sunoco, such costs and payments could be significant and could adversely affect our business, results of operations and cash flows.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
From time to time, we have been sued or investigated for alleged violations of health, safety, environmental and other laws. If a lawsuit or enforcement proceeding were commenced or resolved against us, we could incur significant costs and liabilities. In addition, our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations, cash flows or prospects.
We could encounter significant opposition to operations at our California refineries.
Our Paramount refinery is located in a residential area. The refinery is located near schools, apartment complexes, private homes and shopping establishments. In addition, our Long Beach refinery is 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


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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 are located in areas with a history of earthquakes, some of which have been quite severe. Our Krotz Springs refinery is located less than 100 miles from the Gulf Coast. In the event of an earthquake or hurricane or other weather-related event that causes damage to our refining, pipeline or asphalt terminal assets, or the infrastructure necessary for the operation of these assets, such as the availability of usable roads, electricity, water, or natural gas, we may experience a significant interruption in our refining and/or marketing operations. Such an interruption could have a material adverse effect on our business, results of operations and cash flows.
Terrorist attacks, threats of war or actual war may negatively affect our operations, financial condition, results of operations and prospects.
Terrorist attacks, threats of war or actual war, as well as events occurring in response to or in connection with them, may adversely affect our operations, financial condition, results of operations and prospects. Energy-related assets (which could include refineries, terminals and pipelines such as ours) may be at greater risk of terrorist attacks than other possible targets in the United States. A direct attack on our assets or assets used by us could have a material adverse effect on our operations, financial condition, results of operations and prospects. In addition, any terrorist attack, threats of war or actual war could have an adverse impact on energy prices, including prices for our crude oil and refined products, and an adverse impact on the margins from our refining and marketing operations. In addition, disruption or significant increases in energy prices could result in government-imposed price controls.
Covenants in our credit agreements could limit our ability to undertake certain types of transactions and adversely affect our liquidity.
Our credit agreements contain negative and financial covenants and events of default that may limit our financial flexibility and ability to undertake certain types of transactions. For example, we are subject to negative covenants that restrict our activities, including changes in control of Alon or certain of our subsidiaries, restrictions on creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, entering into certain lease obligations, making certain capital expenditures, and making certain dividend, debt and other restricted payments. Should we desire to undertake a transaction that is prohibited or limited by our credit agreements, we will need to obtain the consent of our lenders or refinance our credit facilities. Such consents or refinancings may not be possible or may not be available on commercially acceptable terms, or at all.
Our insurance policies do not cover all losses, costs or liabilities that we may experience.
We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage does not apply unless a business interruption exceeds a period of 45 to 75 days, depending upon the specific location. We could suffer losses for uninsurable or uninsured risks or insurable events 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 Indemnity Insurance Company (“Kemper”), which has been operating under a run-off plan administered by the Illinois Department of Insurance since 2004 and is now in liquidation. These two policies are 20-year policies that were purchased in 2000 to protect us against expenditures not covered by our indemnification agreement with a prior owner of the Big Spring refinery. Our insurance brokers have advised us that environmental insurance policies with terms in excess of ten years are not generally available and that policies with shorter terms are available only at premiums equal to or in excess of the premiums paid for our policies with Kemper. 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 premium with Kemper. However, we are currently unaware of any potential claims against these policies.


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If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively affected.
Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel. We do not currently maintain key man life insurance with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel would be unavailable to us for any reason, we would be required to hire other personnel to manage and operate our company and to develop our products and technology. We cannot assure you that we would be able to locate or employ such qualified personnel on acceptable terms or at all.
A substantial portion of our Big Spring refinery’s workforce is unionized, and we may face labor disruptions that would interfere with our operations.
As of December 31, 2013, we employed approximately 200 people at our Big Spring refinery, approximately 135 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 us. 7-Eleven may terminate the agreement if we default on our obligations under the agreement. This termination would result in our convenience stores losing the use of the 7-Eleven brand name, the accompanying 7-Eleven advertising and certain other brand names 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


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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. Two of our current and former executive officers, Messrs. Morris and Hart, are parties to stockholders’ agreements with Alon Assets, Inc. 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, 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 and Related Stockholder Matters.” Additionally, we own 81.6% of the Partnership’s common units and 100% of Alon USA 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


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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 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.
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.


25


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 and dividends declared on our common stock for each quarterly period within the two most recently completed fiscal years:
 
 
Sales Prices of our Common Stock
 
Dividends per Common Share
Quarterly Period
 
High
 
Low
 
 
 
 
 
 
 
 
2013
 
 
 
 
 
 
Fourth Quarter
 
$
16.64

 
$
8.55

 
$
0.06

Third Quarter
 
14.70

 
10.12

 
0.06

Second Quarter (1) (2)
 
19.05

 
14.35

 
0.22

First Quarter
 
21.24

 
17.10

 
0.04

2012
 
 
 
 
 
 
Fourth Quarter
 
$
18.37

 
$
12.06

 
$
0.04

Third Quarter
 
14.60

 
8.29

 
0.04

Second Quarter
 
9.40

 
7.52

 
0.04

First Quarter
 
11.94

 
8.61

 
0.04

_______________________
(1)
Beginning in the second quarter of 2013, our board of directors increased the regular quarterly cash dividend from $0.04 per common share to $0.06 per common share.
(2)
Dividends declared on our common stock during the second quarter of 2013 include a special non-recurring dividend of $0.16 per common share.
On February 6, 2014, our board of directors approved the regular quarterly cash dividend of $0.06 per share on our common stock, payable on March 14, 2014, to holders of record at the close of business on February 28, 2014.
We intend to continue to pay quarterly cash dividends on our common stock at an annual rate of $0.24 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.
Holders
As of March 1, 2014, there were 42 common stockholders of record.
Recent Sales of Unregistered Securities
In October 2011, Alon entered into amendments to shareholder agreements among Alon, Joseph Concienne, a former executive, and two of our subsidiaries Alon Assets, Inc. (“Alon Assets”) and Alon Operating, Inc. (“Alon Operating”), pursuant to which the non-voting shares of Alon Assets and Alon Operating held by Mr. Concienne could be exchanged for shares of our common stock over a three-year period. In June 2012, Alon entered into similar amendments to shareholder agreements among Alon, Jeff Morris and Claire Hart, two of our current executives, Alon Assets and Alon Operating, pursuant to which the non-voting shares of Alon Assets and Alon Operating held by Messrs. Morris and Hart could be exchanged for shares of our common stock in quarterly installments over periods of five and three years, respectively. In November 2012, Alon Assets and Alon Operating were merged, with Alon Assets being the surviving entity.


26


The following issuances of shares of our common stock occurred during the 2013 fiscal year pursuant to the agreements described above:
 
 
Exchange Date
 
Number of Shares Issued
Jeff D. Morris
 
January 11, 2013
 
116,347

 
 
April 12, 2013
 
116,347

 
 
July 11, 2013
 
116,347

 
 
October 11, 2013
 
116,347

 
 
 
 
 
Claire A. Hart
 
January 11, 2013
 
48,475

 
 
April 12, 2013
 
48,475

 
 
July 11, 2013
 
48,475

 
 
October 11, 2013
 
48,475

 
 
 
 
 
Joseph A Concienne
 
October 11, 2013
 
116,338

The issuances of the shares of common stock to Messrs. Morris, Hart and Concienne reflected above 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.


27


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 as selected by management for the cumulative five-year period from December 31, 2008 to December 31, 2013, assuming an initial investment of $100 dollars and the reinvestment of all dividends, if any. The peer group is comprised of HollyFrontier Corporation (NYSE: HFC), Tesoro Corporation (NYSE: TSO), Valero Energy Corporation (NYSE: VLO), Delek US Holdings, Inc. (NYSE:DK), Western Refining, Inc. (NYSE:WNR) and CVR Energy, Inc. (NYSE:CVI). The stock performance shown on the graph below is historical and not necessarily indicative of future price performance.
 
12/2008
 
12/2009
 
12/2010
 
12/2011
 
12/2012
 
12/2013
Alon
$
100.00

 
$
75.95

 
$
68.11

 
$
100.79

 
$
212.43

 
$
198.80

S&P 500
100.00

 
126.46

 
145.51

 
148.59

 
172.37

 
228.19

Peer Group
100.00

 
89.09

 
130.63

 
133.50

 
255.23

 
363.03



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, 2010 and 2009, and the selected consolidated balance sheet data as of December 31, 2011, 2010 and 2009 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, 2013, 2012 and 2011, and the selected consolidated balance sheet data as of December 31, 2013 and 2012, 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,
 
 
2013
 
2012
 
2011
 
2010
 
2009
 
 
(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
 
 
 
 
 
Net sales
 
$
7,046,381

 
$
8,017,741

 
$
7,186,257

 
$
4,030,743

 
$
3,915,732

Operating income (loss)
 
149,433

 
269,475

 
181,521

 
(160,781
)
 
(80,836
)
Net income (loss) available to stockholders
 
22,986

 
79,134

 
42,507

 
(122,932
)
 
(115,156
)
Earnings (loss) per share, basic
 
$
0.33

 
$
1.29

 
$
0.77

 
$
(2.27
)
 
$
(2.46
)
Weighted average shares outstanding, basic
 
63,538

 
57,501

 
55,431

 
54,186

 
46,829

Earnings (loss) per share, diluted
 
$
0.32

 
$
1.24

 
$
0.69

 
$
(2.27
)
 
$
(2.46
)
Weighted average shares outstanding, diluted
 
64,852

 
63,917

 
61,401

 
54,186

 
46,829

Cash dividends per common share
 
$
0.38

 
$
0.16

 
$
0.16

 
$
0.16

 
$
0.16

BALANCE SHEET DATA:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
224,499

 
$
116,296

 
$
157,066

 
$
71,687

 
$
40,437

Working capital
 
60,863

 
87,242

 
99,452

 
990

 
84,257

Total assets
 
2,245,140

 
2,223,574

 
2,330,382

 
2,088,521

 
2,132,789

Total debt
 
612,248

 
587,017

 
1,050,196

 
916,305

 
937,024

Total debt less cash and cash equivalents
 
387,749

 
470,721

 
893,130

 
844,618

 
896,587

Total equity
 
625,404

 
621,186

 
395,784

 
341,767

 
431,918




29


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”) Cushing crude oil and West Texas Sour (“WTS”) crude oil or WTI Midland crude oil;
changes in the spread between Brent crude oil and WTI Cushing crude oil;
changes in the spread between Brent crude oil and Light Louisiana Sweet (“LLS”) crude oil;
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 most of our asphalt terminals, of 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 our Supply and Offtake Agreements;
changes in fuel and utility costs incurred by our facilities;
disruptions due to equipment interruption, pipeline disruptions or failures at our or third-party facilities;
the execution of planned capital projects;
adverse changes in the credit ratings assigned to our debt instruments;
the effects of and cost of compliance with the Renewable Fuel Standards 2 (“RFS2”) requirements, including the availability, cost and price volatility of Renewable Identification Numbers (“RINs”);
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 effect of any national or international financial crisis on our business and financial condition; and
the other factors discussed in this Annual Report on Form 10-K under the caption “Risk Factors.”


30


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.
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 and Louisiana and have a combined throughput capacity of approximately 214,000 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.” These refineries have a combined throughput capacity of approximately 214,000 bpd. At our refineries, we refine crude oil into petroleum products, including gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks, asphalts and other petroleum-based products, which are marketed primarily in the South Central, Southwestern and Western United States. In 2013, we did not process crude oil at our California refineries.
Alon owns the Big Spring refinery and wholesale marketing operations through Alon USA Partners, LP (the “Partnership”) (NYSE: ALDW). Alon markets transportation fuels produced at the Big Spring refinery in West and Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in these regions as our “physically integrated system” because it supplies our Alon branded and unbranded distributors in these regions with motor fuels produced at our Big Spring refinery and distributed through a network of pipelines and terminals which we either own or have access to through leases or long-term throughput agreements.
We supply gasoline and diesel to 640 Alon branded retail sites, including our retail segment convenience stores. In 2013, approximately 60% of the gasoline and 28% of the diesel motor fuel produced at the Big Spring refinery was transferred to our branded marketing business 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 93 licensed locations that are not under fuel supply agreements.
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.
Asphalt Segment. As of December 31, 2013, we owned or operated 11 asphalt terminals located in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge) - sold in January 2014, 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”), which specializes in patented ground tire rubber modified asphalt products.
As part of our efforts to maximize the return generated by the production of asphalt, we have an exclusive license to use 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 ground tire rubber (“GTR”) asphalt manufacturing process with respect to asphalt sold in California.
Asphalt produced by our Big Spring refinery is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. We sell asphalt produced at our Big Spring refinery or purchased from third parties primarily as paving asphalt to road and materials manufacturers and highway construction/maintenance contractors as GTR, polymer modified or emulsion asphalt.
Retail Segment. Our retail segment operates 297 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.


31


Summary of 2013 Developments
In September 2013, we issued 3.00% unsecured convertible senior notes in aggregate principal amount of $150.0 million, which mature in September 2018.
In October 2013, we used proceeds from the convertible notes offering, along with cash on hand, to redeem $140.0 million of the outstanding principal balance on the 13.50% Alon Refining Krotz Springs senior secured notes.
In 2013, we have increased the amount of Midland priced WTI crude oil received at the Big Spring refinery, averaging throughput of 20,706 bpd for the full year 2013, a 43.8% increase from 2012.
In 2013, we continued to increase the amount of WTI priced crude oil received at the Krotz Springs refinery, averaging throughput of 29,580 bpd for the full year 2013, a 47.1% increase from 2012.
In 2013, our board of directors increased the regular quarterly cash dividend amount from $0.04 per common share to $0.06 per common share.
Beginning in 2013, we became subject to the RFS2 requirement to begin blending biofuels in the products we produce and to the degree we are unable to blend at percentages required under these various governmental and regulatory programs, we must purchase biofuel credits to comply with these programs. RINs costs for 2013 were $14.9 million at the Big Spring refinery. The Krotz Springs refinery was exempt from the RFS2 requirements in 2013. The California refineries did not process crude oil in 2013 and as a result were not subject to the RFS2 requirements.
2013 Operational and Financial Highlights
Operating income for 2013 was $149.4 million, compared to $269.5 million in 2012. Our operational and financial highlights for 2013 include the following:
Combined refinery average throughput for 2013 was 131,808 bpd, consisting of 67,103 bpd at the Big Spring refinery and 64,705 bpd at the Krotz Springs refinery, compared to a combined refinery average throughput of 154,700 bpd in 2012, consisting of 68,946 bpd at the Big Spring refinery, 67,877 bpd at the Krotz Springs refinery and 17,877 bpd at the California refineries. The lower combined throughput rates were primarily due to our California refineries not processing crude oil for all of 2013 and the Krotz Springs refinery unplanned shut down and repair of the reformer unit for approximately one month during 2013.
Operating margin at the Big Spring refinery was $14.59 per barrel in 2013, compared to $23.50 per barrel in 2012. This decrease is primarily due to lower Gulf Coast 3/2/1 crack spreads and a narrowing WTI Cushing to WTS spread.
Operating margin at the Krotz Springs refinery was $6.16 per barrel for 2013 compared to $8.30 per barrel for 2012. This decrease was mainly due to lower Gulf Coast 2/1/1 high sulfur diesel crack spreads and a narrowing of the LLS to WTI Cushing spread.
The average Gulf Coast 3/2/1 crack spread was $19.16 per barrel for 2013 compared to $27.43 per barrel for 2012. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for 2013 was $7.89 per barrel compared to $11.29 per barrel for 2012.
The average WTI Cushing to WTS spread for 2013 was $3.72 per barrel compared to $4.09 per barrel for 2012. The average LLS to WTI Cushing spread for 2013 was $11.06 per barrel compared to $16.46 per barrel for 2012.
Asphalt margins in 2013 were $68.67 per ton compared to $42.64 per ton in 2012. This increase is primarily due to lower costs of purchased asphalt sold during 2013 compared to 2012. The average blended asphalt sales price decreased 2.7% from $589.63 per ton in 2012 to $573.87 per ton in 2013 and the average non-blended asphalt sales price decreased 0.1% from $372.36 per ton in 2012 to $372.00 per ton in 2013.
Retail fuel sales volume increased by 10.4% to 188.5 million gallons in 2013 from 170.8 million gallons in 2012.
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.


32


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 operating margin to the Gulf Coast 3/2/1 crack spread. A Gulf Coast 3/2/1 crack spread is calculated assuming that three barrels of WTI Cushing crude oil are converted, or cracked, into two barrels of Gulf Coast conventional gasoline and one barrel of Gulf Coast ultra-low sulfur diesel.
We compare our California refineries’ operating margin to the West Coast 3/1/1/1 crack spread. A West Coast 3/1/1/1 crack spread is calculated assuming that three barrels of Buena Vista crude oil are converted into one barrel of West Coast LA CARBOB pipeline gasoline, one barrel of LA ultra-low sulfur pipeline diesel and one barrel of LA 380 pipeline CST fuel oil.
We compare our Krotz Springs refinery’s operating margin to the Gulf Coast 2/1/1 crack spread. A Gulf Coast 2/1/1 crack spread is calculated assuming that two barrels of LLS crude oil are converted into one barrel of Gulf Coast conventional gasoline and one barrel of Gulf Coast high sulfur diesel.
Our Big Spring refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. We measure the cost advantage of refining sour crude oil by calculating the difference between the value of WTI Cushing crude oil and the value of WTS, a medium, sour crude oil. We refer to this differential as the WTI Cushing/WTS, or sweet/sour, spread. A widening of the sweet/sour spread can favorably influence the operating margin for our Big Spring refinery. The Big Spring refinery’s crude oil input is primarily comprised of WTS and WTI Midland priced crude oil.
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 Midland priced crude oil.
In addition, we have been able to capitalize on the oversupply of West Texas crudes in Midland, the largest origination terminal for West Texas crude oil, resulting from increased production in the Permian Basin coupled with infrastructure constraints in Cushing, Oklahoma. Although West Texas crudes are typically transported to Cushing for sale, current logistical and infrastructure constraints at Cushing are limiting the ability of Permian Basin producers to transport their production to Cushing. The resulting oversupply of West Texas crudes at Midland has depressed Midland crude prices and enabled us to access an increased portion of our crude supply at discounted prices to Cushing. Moreover, by sourcing West Texas crude oils at Midland, we are able to eliminate the cost of transporting crude to and from Cushing. The WTI Cushing less WTI Midland spread represents the differential between the average value per barrel of WTI Cushing crude oil and the average value per barrel of WTI Midland crude oil. A widening of the WTI Cushing less WTI Midland spread can favorably influence the operating margin for both our Big Spring and Krotz Springs refineries.
Global product prices are influenced by the price of Brent crude which is a global benchmark crude. Global product prices set product prices in the U.S. As a result, both our Big Spring and Krotz Springs refineries are influenced by the spread between Brent crude and WTI Cushing. For both our Big Spring and Krotz Springs refineries, the Brent less WTI Cushing spread represents the differential between the average value per barrel of Brent crude oil and the average value per barrel of WTI Cushing crude oil. A widening of the spread between Brent and WTI Cushing can favorably influence both refineries operating margins. Also, the Krotz Springs refinery is influenced by the spread between Brent crude and LLS. For our Krotz Springs refinery, the Brent less LLS spread represents the differential between the average value per barrel of Brent crude oil and the average value per barrel of LLS crude oil. A widening of the spread between Brent and LLS can favorably influence the Krotz Springs refinery operating margins.
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.


33


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 or asphalt purchased from third parties. 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. A portion of our asphalt sales are made using fixed price contracts for delivery at future dates. Because these contracts are priced using 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 retail 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. Retail fuel margin is equal to retail fuel sales less the delivered cost of fuel and excise taxes, measured on a cents per gallon (“cpg”) basis. Our retail 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, 2013 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.
Maintenance and Reduced Crude Oil Throughput
During the year ended December 31, 2013, the Krotz Springs refinery was impacted by the unplanned shut down and repair of the reformer unit for approximately one month. Crude throughput was reduced at the Krotz Springs refinery during the second quarter of 2011 due to flooding in Louisiana and its impact on crude oil supply to the refinery.
During the year ended December 31, 2013, we did not process crude oil at our California refineries and therefore, no throughput data has been presented for the year ended December 31, 2013. The throughput data of the California refineries for the years ended December 31, 2012 and 2011 reflects, on average, approximately eight months of throughput data as the California refineries did not process crude oil during the first quarter of 2012 and 2011 or December 2012 and 2011.
Certain Derivative Impacts
Included in cost of goods sold for the years ended December 31, 2013, 2012 and 2011 are gains of $23.9 million, losses of $130.1 million and gains of $30.0 million on commodity swaps, respectively.
Included in other income (loss), net in the consolidated statements of operations, are losses on heating oil call option crack spread contracts of $7.3 million and $36.3 million for the years ended December 31, 2012 and 2011, respectively.
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, 2013, the 11,502,467 common units held by the public represent 18.4% of the Partnership’s common units outstanding. We own the remaining 81.6% of the Partnership’s common units and Alon USA Partners GP, LLC (the “General Partner”), our 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 subsidiaries on the consolidated balance sheets includes the investment by partners other than us, including those partners’ share of net income and distributions of the Partnership since the close of its initial public offering on November 26, 2012. Net income attributable to non-controlling interest on our consolidated statements of operations includes those partners’ share of net income of the Partnership.


34


Renewable Fuel Standard
Beginning in 2013, we became subject to the RFS2 requirement to begin blending biofuels in the products we produce and to the degree we are unable to blend at percentages required under these various governmental regulatory programs, we must purchase biofuel credits to comply with these programs. Our RINs liability represents an obligation to purchase biofuels credits needed to satisfy our obligation to blend biofuels into the products we have produced to date. RINs costs for the year ended December 31, 2013 were $14.9 million. We were not subject to the RFS2 requirements in 2012 or 2011.
Debt Related Transactions
In September 2013, we issued 3.00% unsecured convertible senior notes in aggregate principal amount of $150.0 million, which mature on September 15, 2018. In October 2013, proceeds from the convertible notes offering, along with cash on hand, were used to redeem $140.0 million of the outstanding principal balance on the 13.50% Alon Refining Krotz Springs senior secured notes due October 2014.
Interest expense for the year ended December 31, 2013 includes $8.5 million for a prepayment premium and write-offs of unamortized original issuance discount and debt issuance costs recognized for prepayment of a portion of the Alon Refining Krotz Springs senior secured notes.
Interest expense for the year ended December 31, 2012 includes a charge of $9.6 million for the write-off of unamortized original issuance discount associated with our repayment of the Alon Brands Term Loan and charges of $27.6 million for the write-offs of unamortized original issuance discount and debt issuance costs associated with the repayment of the Alon USA Energy, Inc. term loan credit facilities.


35


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 intersegment 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 excise taxes. Our retail merchandise sales are affected primarily by competition and seasonal influences.
Cost of Sales. Refining and marketing cost of sales includes principally crude oil, blending materials, other raw materials and transportation costs. Asphalt cost of sales includes costs of purchased asphalt, blending materials and transportation costs. Retail cost of sales includes motor fuels and merchandise. Retail fuel cost of sales represents the cost of purchased fuel, including transportation costs and associated excise 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, which is presented separately in the consolidated statements of operations.
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. All operating costs associated with our crude oil and product pipelines are considered to be transportation costs and are reflected as cost of sales in the consolidated statements of operations.
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. Corporate overhead and marketing expenses are also included in SG&A expenses for the refining and marketing and asphalt segments.


36


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, 2013, 2012 and 2011. 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,
 
2013
 
2012
 
2011
 
(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
Net sales (1)
$
7,046,381

 
$
8,017,741

 
$
7,186,257

Operating costs and expenses:
 
 
 
 
 
Cost of sales
6,325,088

 
7,149,385

 
6,462,947

Direct operating expenses
287,752

 
313,242

 
285,666

Selling, general and administrative expenses (2)
168,172

 
161,401

 
143,122

Depreciation and amortization (3)
125,494

 
121,929

 
113,730

Total operating costs and expenses
6,906,506

 
7,745,957

 
7,005,465

Gain (loss) on disposition of assets
9,558

 
(2,309
)
 
729

Operating income
149,433

 
269,475

 
181,521

Interest expense (4)
(94,694
)
 
(129,572
)
 
(88,310
)
Equity earnings of investees
5,309

 
7,162

 
5,128

Other income (loss), net (5)
218

 
(6,584
)
 
(35,673
)
Income before income tax expense
60,266

 
140,481

 
62,666

Income tax expense
12,151

 
49,884

 
18,918

Net income
48,115

 
90,597

 
43,748

Net income attributable to non-controlling interest
25,129

 
11,463

 
1,241

Net income available to stockholders
$
22,986

 
$
79,134

 
$
42,507

Earnings per share, basic
$
0.33

 
$
1.29

 
$
0.77

Weighted average shares outstanding, basic (in thousands)
63,538

 
57,501

 
55,431

Earnings per share, diluted
$
0.32

 
$
1.24

 
$
0.69

Weighted average shares outstanding, diluted (in thousands)
64,852

 
63,917

 
61,401

Cash dividends per share
$
0.38

 
$
0.16

 
$
0.16

CASH FLOW DATA:
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
162,233

 
$
387,810

 
$
69,560

Investing activities
(51,441
)
 
(104,980
)
 
(126,542
)
Financing activities
(2,589
)
 
(323,600
)
 
142,361

OTHER DATA:
 
 
 
 
 
Adjusted EBITDA (6)
$
270,896

 
$
394,291

 
$
263,977

Capital expenditures (7)
68,513

 
93,901

 
112,625

Capital expenditures for turnarounds and catalysts
8,617

 
11,460

 
9,734




37


 
As of December 31,
 
2013
 
2012
BALANCE SHEET DATA:
(dollars in thousands)
Cash and cash equivalents
$
224,499

 
$
116,296

Working capital
60,863

 
87,242

Total assets
2,245,140

 
2,223,574

Total debt
612,248

 
587,017

Total debt less cash and cash equivalents
387,749

 
470,721

Total equity
625,404

 
621,186

(1)
Includes excise taxes on sales by the retail segment of $73,597, $66,563 and $60,686 for the years ended December 31, 2013, 2012 and 2011, respectively.
(2)
Includes corporate headquarters selling, general and administrative expenses of $721, $960 and $752 for the years ended December 31, 2013, 2012 and 2011, respectively, which are not allocated to our three operating segments.
(3)
Includes corporate depreciation and amortization of $2,673, $2,127 and $1,925 for the years ended December 31, 2013, 2012 and 2011, respectively, which are not allocated to our three operating segments.
(4)
Interest expense for the year ended December 31, 2013 includes $8,467 for a prepayment premium and write-offs of unamortized original issuance discount and debt issuance costs recognized for prepayment of a portion of the Alon Refining Krotz Springs senior secured notes.
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 $27,576 for the write-offs of unamortized original issuance discount and debt issuance costs recognized for the repayment of the Alon USA Energy, Inc. term loan credit facilities.
(5)
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.
(6)
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 available to stockholders to Adjusted EBITDA for the periods presented.
(7)
Includes corporate capital expenditures of $881, $2,228 and $1,540 for the years ended December 31, 2013, 2012 and 2011, respectively, which are not allocated to our three operating segments.


38


REFINING AND MARKETING SEGMENT (A)
 
 
 
 
 
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
(dollars in thousands, except per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
 
 
 
 
 
Net sales (1)
$
6,090,688

 
$
7,241,935

 
$
6,558,625

Operating costs and expenses:
 
 
 
 
 
Cost of sales
5,561,825

 
6,551,483

 
5,996,773

Direct operating expenses
244,759

 
278,725

 
243,018

Selling, general and administrative expenses
52,846

 
51,215

 
39,190

Depreciation and amortization
105,597

 
103,638

 
90,701

Total operating costs and expenses
5,965,027

 
6,985,061

 
6,369,682

Gain (loss) on disposition of assets
7,359

 
(2,502
)
 
12

Operating income
$
133,020

 
$
254,372

 
$
188,955

KEY OPERATING STATISTICS:
 
 
 
 
 
Per barrel of throughput:
 
 
 
 
 
Refinery operating margin – Big Spring (2)
$
14.59

 
$
23.50

 
$
20.89

Refinery operating margin – CA Refineries (2)
N/A

 
2.36

 
(1.31
)
Refinery operating margin – Krotz Springs (2)
6.16

 
8.30

 
3.05

Refinery direct operating expense – Big Spring (3)
4.53

 
4.00

 
4.23

Refinery direct operating expense – CA Refineries (3)
N/A

 
12.59

 
7.32

Refinery direct operating expense – Krotz Springs (3)
4.09

 
3.85

 
3.67

Capital expenditures
$
40,272

 
$
68,112

 
$
92,022

Capital expenditures for turnaround and chemical catalyst
8,617

 
11,460

 
9,734

PRICING STATISTICS:
 
 
 
 
 
Crack spreads (3/2/1) (per barrel):
 
 
 
 
 
Gulf Coast
$
19.16

 
$
27.43

 
$
23.37

Crack spreads (3/1/1/1) (per barrel):
 
 
 
 
 
West Coast
$
9.91

 
$
13.08

 
$
9.20

Crack spreads (2/1/1) (per barrel):
 
 
 
 
 
Gulf Coast high sulfur diesel
$
7.89

 
$
11.29

 
$
7.00

WTI Cushing crude oil (per barrel)
$
97.97

 
$
94.14

 
$
95.07

Crude oil differentials (per barrel):
 
 
 
 
 
WTI Cushing less WTI Midland
$
2.59

 
$
2.88

 
$
0.53

WTI Cushing less WTS
3.72

 
4.09

 
2.19

LLS less WTI Cushing
11.06

 
16.46

 
16.76

Brent less LLS
2.22

 
0.79

 
(0.12
)
Brent less WTI Cushing
11.63

 
18.35

 
17.10

Product price (dollars per gallon):
 
 
 
 
 
Gulf Coast unleaded gasoline
$
2.70

 
$
2.82

 
$
2.75

Gulf Coast ultra-low sulfur diesel
2.97

 
3.05

 
2.97

Gulf Coast high sulfur diesel
2.87

 
2.99

 
2.91

West Coast LA CARBOB (unleaded gasoline)
2.93

 
3.03

 
2.89

West Coast LA ultra-low sulfur diesel
3.01

 
3.11

 
3.05

Natural gas (per MMBtu)
3.73

 
2.83

 
4.03

(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 were combined with the refining and marketing segment and are no longer included with the retail segment. Information for the branded marketing operations for the years ended December 31, 2013 and 2012 is included in the refining and marketing segment. Information for the year ended December 31, 2011 has been recast to provide a comparison to the current year results.
_______________________________


39


THROUGHPUT AND PRODUCTION DATA:
BIG SPRING REFINERY
Year Ended December 31,
2013
 
2012
 
2011
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
WTS crude
43,705

 
65.1

 
52,190

 
75.7

 
51,202

 
80.4

WTI crude
20,706

 
30.9

 
14,396

 
20.9

 
10,023

 
15.8

Blendstocks
2,692

 
4.0

 
2,360

 
3.4

 
2,389

 
3.8

Total refinery throughput (4)
67,103

 
100.0

 
68,946

 
100.0

 
63,614

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline
33,736

 
50.4

 
34,637

 
50.3

 
31,105

 
49.1

Diesel/jet
22,404

 
33.5

 
22,329

 
32.5

 
20,544

 
32.3

Asphalt
3,640

 
5.4

 
4,084

 
5.9

 
4,539

 
7.1

Petrochemicals
4,152

 
6.2

 
4,054

 
5.9

 
3,837

 
6.0

Other
3,033

 
4.5

 
3,706

 
5.4

 
3,488

 
5.5

Total refinery production (5)
66,965

 
100.0

 
68,810

 
100.0

 
63,513

 
100.0

Refinery utilization (6)
 
 
94.9
%
 
 
 
97.3
%
 
 
 
90.8
%
THROUGHPUT AND PRODUCTION DATA:
CALIFORNIA REFINERIES
Year Ended December 31,
2013
 
2012
 
2011
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
Medium sour crude

 

 
9,071

 
50.7

 
5,677

 
24.9

Heavy crude

 

 
8,038

 
45.0

 
14,962

 
65.6

Blendstocks

 

 
768

 
4.3

 
2,176

 
9.5

Total refinery throughput (4)

 

 
17,877

 
100.0

 
22,815

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline

 

 
3,716

 
20.8

 
4,969

 
22.0

Diesel/jet

 

 
6,503

 
36.4

 
7,938

 
35.1

Asphalt

 

 
4,580

 
25.6

 
6,632

 
29.4

Heavy unfinished

 

 
2,603

 
14.6

 
2,292

 
10.2

Other

 

 
462

 
2.6

 
735

 
3.3

Total refinery production (5)

 

 
17,864

 
100.0

 
22,566

 
100.0

Refinery utilization (6)
 
 
%
 
 
 
23.6
%
 
 
 
28.5
%
THROUGHPUT AND PRODUCTION DATA:
KROTZ SPRINGS REFINERY
Year Ended December 31,
2013
 
2012
 
2011
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
WTI crude
29,580

 
45.7

 
20,111

 
29.6

 

 

Gulf Coast sweet crude
33,233

 
51.4

 
46,924

 
69.2

 
58,979

 
98.8

Blendstocks
1,892

 
2.9

 
842

 
1.2

 
741

 
1.2

Total refinery throughput (4)
64,705

 
100.0

 
67,877

 
100.0

 
59,720

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline
29,432

 
44.6

 
29,081

 
42.4

 
24,852

 
41.4

Diesel/jet
26,508

 
40.2

 
28,466

 
41.4

 
27,436

 
45.6

Heavy Oils
1,175

 
1.8

 
2,709

 
3.9

 
2,904

 
4.8

Other
8,857

 
13.4

 
8,464

 
12.3

 
4,914

 
8.2

Total refinery production (5)
65,972

 
100.0

 
68,720

 
100.0

 
60,106

 
100.0

Refinery utilization (6)
 
 
85.9
%
 
 
 
90.6
%
 
 
 
84.8
%


40


(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 margins exclude gains on commodity swaps of $23,900 for the year ended December 31, 2013. The refinery operating margins for the year ended December 31, 2013 exclude $3,828 of positive inventory effects.
The refinery operating margins exclude losses on commodity swaps of $116,020 for the year ended December 31, 2012. The refinery operating margins for the year ended December 31, 2012 also exclude approximately $8,000 primarily from negative inventory effects.
The refinery operating margins exclude gains on commodity swaps of $32,742 for the year ended December 31, 2011. The refinery operating margins for the year ended December 31, 2011 also exclude approximately $10,000 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 for the year ended December 31, 2011 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. In 2013, we did not process crude oil at our California refineries and therefore, no throughput data has been presented for the year ended December 31, 2013. The throughput data of the California refineries for the years ended December 31, 2012 and 2011 reflects, on average, approximately eight months of throughput data as the California refineries did not process crude oil during the first quarter of 2012 and 2011 or December 2012 and 2011.
During the year ended December 31, 2013, crude oil throughput at the Krotz Springs refinery was impacted by the unplanned shut down and repair of the reformer unit for approximately one month. Crude oil throughput was reduced at the Krotz Springs refinery during the second quarter of 2011 due to flooding in Louisiana and its impact on crude oil supply to the refinery.
(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.


41


ASPHALT SEGMENT
 
 
 
 
 
 
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(dollars in thousands, except per ton data)
STATEMENTS OF OPERATIONS DATA:
 
 
 
 
 
 
Net sales (1)
 
$
612,443

 
$
603,896

 
$
554,549

Operating costs and expenses:
 

 

 
 
Cost of sales (1) (2)
 
558,263

 
563,516

 
524,964

Direct operating expenses
 
42,993

 
34,517

 
42,648

Selling, general and administrative expenses
 
8,886

 
4,230

 
5,080

Depreciation and amortization
 
6,398

 
5,866

 
6,376

Total operating costs and expenses
 
616,540

 
608,129

 
579,068

Gain on disposition of assets
 

 
505

 

Operating loss
 
$
(4,097
)
 
$
(3,728
)
 
$
(24,519
)
KEY OPERATING STATISTICS:
 
 
 
 
 
 
Blended asphalt sales volume (tons in thousands) (3)
 
701

 
842

 
915

Non-blended asphalt sales volume (tons in thousands) (4)
 
88

 
105

 
181

Blended asphalt sales price per ton (3)
 
$
573.87

 
$
589.63

 
$
541.44

Non-blended asphalt sales price per ton (4)
 
372.00

 
372.36

 
326.69

Asphalt margin per ton (5)
 
68.67

 
42.64

 
26.99

Capital expenditures
 
$
9,425

 
$
9,420

 
$
3,225

(1)
Net sales and cost of sales for the years ended December 31, 2013 and 2012 include approximately $177,000 and $68,000, respectively, of asphalt purchases sold as part of a supply and offtake arrangement. The volumes associated with these sales are excluded from the Key Operating Statistics.
(2)
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.
(3)
Blended asphalt represents base asphalt that has been blended with other materials necessary to sell the asphalt as a finished product.
(4)
Non-blended asphalt represents base material asphalt and other components that require additional blending before being sold as a finished product.
(5)
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.


42


RETAIL SEGMENT (A)
 
 
 
 
 
 
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
(dollars in thousands, except per gallon data)
STATEMENTS OF OPERATIONS DATA:
 
 
 
 
 
 
Net sales (1)
 
$
944,193


$
907,918

 
$
833,470

Operating costs and expenses:
 



 
 
Cost of sales (2)
 
805,943


770,394

 
701,597

Selling, general and administrative expenses
 
105,719


104,996

 
98,100

Depreciation and amortization
 
10,826


10,298

 
14,728

Total operating costs and expenses
 
922,488

 
885,688

 
814,425

Gain (loss) on disposition of assets
 
2,199


(312
)
 
717

Operating income
 
$
23,904

 
$
21,918

 
$
19,762

KEY OPERATING STATISTICS:
 
 
 
 
 
 
Number of stores (end of period) (3)
 
297

 
298

 
302

Retail fuel sales (thousands of gallons)
 
188,493

 
170,848

 
156,662

Retail fuel sales (thousands of gallons per site per month) (3)
 
55

 
50

 
45

Retail fuel margin (cents per gallon) (4)
 
19.3

 
20.2

 
21.4

Retail fuel sales price (dollars per gallon) (5)
 
$
3.33

 
$
3.47

 
$
3.41

Merchandise sales
 
$
316,432

 
$
315,082

 
$
298,233

Merchandise sales (per site per month) (3)
 
$
89

 
$
88

 
$
82

Merchandise margin (6)
 
32.1
%
 
32.5
%
 
32.8
%
Capital expenditures
 
$
17,935

 
$
14,141

 
$
15,838

(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 were combined with the refining and marketing segment and are no longer included with the retail segment. Information for the branded marketing operations for the years ended December 31, 2013 and 2012 is included in the refining and marketing segment. Information for the year ended December 31, 2011 has been recast to provide a comparison to the current year results.
__________________________
(1)
Includes excise taxes on sales of $73,597, $66,563 and $60,686 for the years ended December 31, 2013, 2012 and 2011, 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, 2013, we had 297 retail convenience stores of which 285 sold fuel. 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 retail fuel sales revenue and the net cost of purchased retail fuel, including transportation costs and associated excise taxes, expressed on a cents-per-gallon basis. Retail fuel margins are frequently used in the retail industry to measure operating results related to retail fuel sales.
(5)
Retail fuel sales price per gallon represents the average sales price for retail 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.


43


Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012
Net Sales
Consolidated. Net sales for the year ended December 31, 2013 were $7,046.4 million, compared to $8,017.7 million for the year ended December 31, 2012, a decrease of $971.3 million. This decrease was primarily due to lower refinery throughput volumes and lower refined product prices.
Refining and Marketing Segment. Net sales for our refining and marketing segment were $6,090.7 million for the year ended December 31, 2013, compared to $7,241.9 million for the year ended December 31, 2012, a decrease of $1,151.2 million. This decrease was due to lower refinery throughput volumes and lower refined product prices for the year ended December 31, 2013 compared to the year ended December 31, 2012.
Combined refinery average throughput for the year ended December 31, 2013 was 131,808 bpd, consisting of 67,103 bpd at the Big Spring refinery and 64,705 bpd at the Krotz Springs refinery, compared to a combined refinery average throughput of 154,700 bpd for the year ended December 31, 2012, consisting of 68,946 bpd at the Big Spring refinery, 67,877 bpd at the Krotz Springs refinery and 17,877 bpd at the California refineries. The lower throughput rates for the year ended December 31, 2013 were primarily due to our California refineries not processing crude oil during the year ended December 31, 2013, which processed crude oil for approximately eight months during 2012. The reduced refinery throughput for the Krotz Springs refinery reflects the impact of the unplanned shut down and repair of the reformer unit for approximately one month during 2013.
Refined product prices decreased for all of our products during the year ended December 31, 2013 compared to the year ended December 31, 2012. The average per gallon price of Gulf Coast gasoline for the year ended December 31, 2013 decreased $0.12, or 4.3%, to $2.70, compared to $2.82 for the year ended December 31, 2012. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the year ended December 31, 2013 decreased $0.08, or 2.6%, to $2.97, compared to $3.05 for the year ended December 31, 2012. The average per gallon price for Gulf Coast high sulfur diesel for the year ended December 31, 2013 decreased $0.12, or 4.0%, to $2.87, compared to $2.99 for the year ended December 31, 2012.
Asphalt Segment. Net sales for our asphalt segment were $612.4 million for the year ended December 31, 2013, compared to $603.9 million for the year ended December 31, 2012, an increase of $8.5 million or 1.4%. This increase was primarily higher asphalt sales as part of a supply and offtake arrangement of approximately $109.0 million, partially offset by decreased sales volumes and lower blended asphalt sales prices in 2013. The asphalt sales volume decreased 16.7% from 947 thousand tons for the year ended December 31, 2012, to 789 thousand tons for the year ended December 31, 2013. The average blended asphalt sales price decreased 2.7% from $589.63 per ton for the year ended December 31, 2012, to $573.87 per ton for the year ended December 31, 2013 and the average non-blended asphalt sales price decreased 0.1% from $372.36 per ton for the year ended December 31, 2012 to $372.00 per ton for the year ended December 31, 2013.
Retail Segment. Net sales for our retail segment were $944.2 million for the year ended December 31, 2013, compared to $907.9 million for the year ended December 31, 2012, an increase of $36.3 million or 4.0%. This increase was primarily attributable to increases in retail fuel sales volumes and merchandise sales, partially offset by lower retail fuel sales prices.
Cost of Sales
Consolidated. Cost of sales for the year ended December 31, 2013 were $6,325.1 million, compared to $7,149.4 million for the year ended December 31, 2012, a decrease of $824.3 million, or 11.5%. This decrease was primarily due to lower refinery throughput, partially offset by higher crude oil prices.
Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $5,561.8 million for the year ended December 31, 2013, compared to $6,551.5 million for the year ended December 31, 2012, a decrease of $989.7 million, or 15.1%. This decrease was primarily due to lower refinery throughput, partially offset by higher crude oil prices. The average price of WTI Cushing increased 4.1% to $97.97 per barrel for the year ended December 31, 2013 from $94.14 per barrel for the year ended December 31, 2012.
Asphalt Segment. Cost of sales for our asphalt segment were $558.3 million for the year ended December 31, 2013, compared to $563.5 million for the year ended December 31, 2012, a decrease of $5.2 million or 0.9%. The decrease was primarily due to decreased sales volumes, partially offset by the impact of the higher inventory asphalt purchases sold as part of a supply and offtake arrangement for the year ended December 31, 2013 compared to the year ended December 31, 2012.
Retail Segment. Cost of sales for our retail segment were $805.9 million for the year ended December 31, 2013, compared to $770.4 million for the year ended December 31, 2012, an increase of $35.5 million, or 4.6%. This increase was primarily attributable to increases in retail fuel sales volumes and merchandise costs, partially offset by lower retail fuel prices.


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Direct Operating Expenses
Consolidated. Direct operating expenses were $287.8 million for the year ended December 31, 2013, compared to $313.2 million for the year ended December 31, 2012, a decrease of $25.4 million, or 8.1%.
Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the year ended December 31, 2013 were $244.8 million, compared to $278.7 million for the year ended December 31, 2012, a decrease of $33.9 million, or 12.2%. This decrease was primarily due to the California refineries not processing crude oil during the year ended December 31, 2013, partially offset by higher natural gas costs.
Asphalt Segment. Direct operating expenses for our asphalt segment for the year ended December 31, 2013 were $43.0 million, compared to $34.5 million for the year ended December 31, 2012, an increase of $8.5 million, or 24.6%. This increase was primarily due to higher natural gas costs and higher facilities maintenance costs.
Selling, General and Administrative Expenses
Consolidated. SG&A expenses for the year ended December 31, 2013 were $168.2 million, compared to $161.4 million for the year ended December 31, 2012, an increase of $6.8 million, or 4.2%. This increase was primarily due to higher employee incentive related costs.
Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the year ended December 31, 2013 were $52.8 million, compared to $51.2 million for the year ended December 31, 2012, an increase of $1.6 million, or 3.1%. This increase was primarily due to higher employee related costs.
Asphalt Segment. SG&A expenses for our asphalt segment for the year ended December 31, 2013 were $8.9 million, compared to $4.2 million for the year ended December 31, 2012, an increase of $4.7 million, or 111.9%. This increase was primarily due to higher corporate expense allocated to the asphalt segment.
Retail Segment. SG&A expenses for our retail segment for the year ended December 31, 2013 were $105.7 million, compared to $105.0 million for the year ended December 31, 2012, an increase of $0.7 million, or 0.7%.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2013 was $125.5 million, compared to $121.9 million for the year ended December 31, 2012, an increase of $3.6 million, or 3.0%.
Operating Income
Consolidated. Operating income for the year ended December 31, 2013 was $149.4 million, compared to $269.5 million for the year ended December 31, 2012, a decrease of $120.1 million. This decrease was primarily due to reduced refinery operating margins, partially offset by lower direct operating expenses and gains on commodity swaps during the year ended December 31, 2013 of $23.9 million compared to losses on commodity swaps during the year ended December 31, 2012 of $130.1 million.
Refining and Marketing Segment. Operating income for our refining and marketing segment was $133.0 million for the year ended December 31, 2013, compared to $254.4 million for the year ended December 31, 2012, a decrease of $121.4 million. This decrease was primarily due to reduced refinery operating margins, partially offset by lower direct operating expenses and gains on commodity swaps during the year ended December 31, 2013 of $23.9 million compared to losses on commodity swaps during the year ended December 31, 2012 of $130.1 million.
Refinery operating margin at the Big Spring refinery was $14.59 per barrel for the year ended December 31, 2013, compared to $23.50 per barrel for the year ended December 31, 2012. This decrease was primarily due to lower Gulf Coast 3/2/1 crack spreads, a narrowing WTI Cushing to WTS spread as well as an unfavorable reduction in the location differential between WTI Cushing and WTI Midland. The average Gulf Coast 3/2/1 crack spread decreased 30.1% to $19.16 per barrel for the year ended December 31, 2013, compared to $27.43 per barrel for the year ended December 31, 2012. The WTI Cushing to WTS spread decreased 9.0% to $3.72 per barrel for the year ended December 31, 2013, compared to $4.09 per barrel for the year ended December 31, 2012. The WTI Cushing to WTI Midland spread narrowed 10.1% to $2.59 per barrel for the year ended December 31, 2013, compared to $2.88 per barrel for the year ended December 31, 2012. Operating income and refinery operating margin at the Big Spring refinery for the year ended December 31, 2013 were also impacted by $14.9 million of costs for the purchase of RINs credits needed to satisfy our obligation to blend biofuels into the products we produce, which we were not subject to in 2012.
Refinery operating margin at the Krotz Springs refinery was $6.16 per barrel for the year ended December 31, 2013, compared to $8.30 per barrel for the year ended December 31, 2012. This decrease was primarily due to lower Gulf Coast 2/1/1 high sulfur diesel crack spreads and a narrowing LLS to WTI Cushing spread during the year ended December 31, 2013. The


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average Gulf Coast 2/1/1 high sulfur diesel crack spread for the year ended December 31, 2013 was $7.89 per barrel, compared to $11.29 per barrel for the year ended December 31, 2012. The LLS to WTI Cushing spread decreased $5.40 per barrel to $11.06 per barrel for the year ended December 31, 2013, compared to $16.46 per barrel for the year ended December 31, 2012.
Asphalt Segment. Operating loss for our asphalt segment was $4.1 million for the year ended December 31, 2013, compared to $3.7 million for the year ended December 31, 2012, an increase in loss of $0.4 million, or 10.8%. This increase in loss was primarily due to higher direct operating and SG&A expenses, partially offset by increases in asphalt margins. Asphalt margins for the year ended December 31, 2013 were $68.67 per ton compared to $42.64 per ton for the year ended December 31, 2012.
Retail Segment. Operating income for our retail segment was $23.9 million for the year ended December 31, 2013, compared to $21.9 million for the year ended December 31, 2012, an increase of $2.0 million. This increase was primarily due to higher retail fuel sales volumes and higher merchandise sales, partially offset by lower retail fuel margins and merchandise margins.
Interest Expense
Interest expense was $94.7 million for the year ended December 31, 2013, compared to $129.6 million for the year ended December 31, 2012, a decrease of $34.9 million, or 26.9%. This decrease was primarily due to lower costs included in interest expense related to prepayments of our long-term debt obligations during the year ended December 31, 2013 compared to the year ended December 31, 2012. Interest expense for the year ended December 31, 2013 includes a charge of $8.5 million for a prepayment premium and write-offs of unamortized original issuance discount and debt issuance costs recognized for prepayment of a portion of the Alon Refining Krotz Springs senior secured notes. Interest expense for the year ended December 31, 2012, includes a charge of $9.6 million for the write-off of unamortized original issuance discount associated with our repayment of the Alon Brands Term Loan and charges of $27.6 million for the write-offs of unamortized original issuance discount and debt issuance costs associated with the repayment of the Alon USA Energy, Inc. term loan credit facilities.
Income Tax Expense
Income tax expense was $12.2 million for the year ended December 31, 2013, compared to $49.9 million for the year ended December 31, 2012. This decrease resulted from our lower pre-tax income for the year ended December 31, 2013, compared to the year ended December 31, 2012, and a decrease in the effective tax rate. Our effective tax rate was 20.2% for the year ended December 31, 2013, compared to an effective tax rate of 35.5% for the year ended December 31, 2012. This lower effective tax rate compared to the prior period is due to the impact of the non-controlling interest’s share of Partnership income as a result of the Partnership’s initial public offering in November 2012.
Net Income Attributable to Non-controlling Interest
Net income attributable to non-controlling interest includes the proportional share of the Partnership’s income attributable to the limited partner interests held by the public. Additionally, net income attributable to non-controlling interest represents the proportional share of net income related to non-voting common stock owned by non-controlling interest shareholders in our subsidiary, Alon Assets, Inc. Net income attributable to non-controlling interest was $25.1 million for the year ended December 31, 2013, compared to $11.5 million for the year ended December 31, 2012, an increase of $13.6 million. This increase is due to the impact of the non-controlling interest’s share of Partnership income as a result of the Partnership’s initial public offering in November 2012.
Net Income Available to Stockholders
Net income available to stockholders was $23.0 million for the year ended December 31, 2013, compared to $79.1 million for the year ended December 31, 2012, a decrease of $56.1 million. This decrease was attributable to the factors discussed above.
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.


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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 primarily due to higher refined product prices and higher refinery throughput for the year ended December 31, 2012 compared to the year ended December 31, 2011.
Combined refinery average throughput for the year ended December 31, 2012 was 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 refinery 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 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 primarily due to higher asphalt sales prices 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 $7,149.4 million for the year ended December 31, 2012, compared to $6,462.9 million for the year ended December 31, 2011, an increase of $686.5 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 $6,551.5 million for the year ended December 31, 2012, compared to $5,996.8 million for the year ended December 31, 2011, an increase of $554.7 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 Cushing 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.
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%. This 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.
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 was primarily due to increased refinery throughput.


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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 was primarily due to lower natural gas costs.
Selling, General and Administrative Expenses
Consolidated. SG&A expenses were $161.4 million for the year ended December 31, 2012, compared to $143.1 million for the year ended December 31, 2011, an increase of $18.3 million, or 12.8%. This increase was 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 were $51.2 million for the year ended December 31, 2012, 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 were $4.2 million for the year ended December 31, 2012, compared to $5.1 million for the year ended December 31, 2011, a decrease of $0.9 million, or 17.6%. This decrease was primarily due to lower employee-related costs for the year ended December 31, 2012.
Retail Segment. SG&A expenses for our retail segment were $105.0 million for the year ended December 31, 2012, 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 was $121.9 million for the year ended December 31, 2012, compared to $113.7 million for the year ended December 31, 2011, an increase of $8.2 million, or 7.2%. This increase was primarily due 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
Consolidated. Operating income was $269.5 million for the year ended December 31, 2012, 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 was primarily due to higher Gulf Coast 3/2/1 crack spreads, an improved WTI Cushing to WTS spread as well as an improved location differential between WTI Cushing and WTI Midland. 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. The WTI Cushing to WTS spread widened to $4.09 per barrel for the year ended December 31, 2012, compared to $2.19 per barrel for the year ended December 31, 2011. The WTI Cushing to WTI Midland spread widened to $2.88 per barrel for the year ended December 31, 2012, compared to $0.53 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 was 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 was $8.30 per barrel for the year ended December 31, 2012, 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 was $11.29 per barrel for the year ended December 31, 2012, 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 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.


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