Alon USA Energy (ALJ) 10-K 2013 FY Annual report

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	3
ITEM 1A. RISK FACTORS	16
ITEM 1B. UNRESOLVED STAFF COMMENTS	25
ITEM 3. LEGAL PROCEEDINGS	25
ITEM 4. MINE SAFETY DISCLOSURES	25
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	26
ITEM 6. SELECTED FINANCIAL DATA	29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	30
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	58
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	59
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	59
ITEM 9A. CONTROLS AND PROCEDURES	60
ITEM 9B. OTHER INFORMATION	60
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	61
ITEM 11. EXECUTIVE COMPENSATION	61
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	61
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	61
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES	61
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	62

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 600acres 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.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Market Information

Our common stock is traded on the New York Stock Exchange under the symbol “ALJ.”

The following table sets forth the quarterly high and low sales prices of 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.

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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.

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Stockholder Return Performance Graph

The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, each as amended, except to the extent we specifically incorporate it by reference into such filing.

The following performance graph compares the cumulative total stockholder return on Alon common stock as traded on the NYSE with the Standard & Poor’s 500 Stock Index (the “S&P 500”) and our peer group 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

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ITEM 6. SELECTED FINANCIAL DATA.

The following table sets forth selected historical consolidated financial and operating data for our company. The selected historical consolidated statement of operations and consolidated statement of cash flows data for the years ended December 31, 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

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion of our financial condition and results ofoperations is provided as a supplement to, and should be read in conjunctionwith, our consolidated financial statements and the notes thereto includedelsewhere in this Annual Report on Form 10-K and the other sections of thisAnnual 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.”

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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.

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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.

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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.

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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.

_______________________________

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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 EndedDecember 31, 2013 Compared to the Year EndedDecember 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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Interest Expense

Interest expense was $129.6 million for the year ended December 31, 2012, compared to $88.3 million for the year ended December 31, 2011, an increase of $41.3 million, or 46.8%. This increase was primarily due to 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 Alon USA Energy, Inc. term loan credit facilities during the year ended December 31, 2012.

Income Tax Expense

Income tax expense was $49.9 million for the year ended December 31, 2012, compared to $18.9 million for the year ended December 31, 2011, an increase of $31.0 million. This increase resulted from our higher pre-tax income for the year ended December 31, 2012 compared to the year ended December 31, 2011, and an increase in the effective tax rate. Our effective tax rate was 35.5% for the year ended December 31, 2012, compared to an effective tax rate of 30.2% for the year ended December 31, 2011.

Net Income Attributable to Non-controlling Interest

Net income attributable to non-controlling interest for the year ended December 31, 2012 includes the proportional share of the Partnership’s income attributable to the limited partner interests held by the public after completion of the Partnership’s initial public offering in November 2012. 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 $11.5 million for the year ended December 31, 2012, compared to $1.2 million for the year ended December 31, 2011, an increase of $10.3 million.

Net Income Available to Stockholders

Net income available to stockholders was $79.1 million for the year ended December 31, 2012, compared to $42.5 million for the year ended December 31, 2011, an increase of $36.6 million. This increase was attributable to the factors discussed above.

Liquidity and Capital Resources

Our primary sources of liquidity are cash on hand, cash generated from our operating activities, borrowings under our revolving credit facilities, inventory supply and offtake arrangements, other credit lines and advances from affiliates.

We have agreements with J. Aron for the supply of crude oil that will support the operations of all our refineries as well as most of our asphalt terminals. These agreements substantially reduce our physical inventories and our associated need to issue letters of credit to support crude oil and asphalt purchases. In addition, the structure allows us to acquire crude oil and asphalt without the constraints of a maximum facility size during periods of high crude oil prices.

We believe that the aforementioned sources of funds and other sources of capital available to us will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control.

Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or equity securities, or other possible capital markets transactions, the proceeds of which could be used to refinance current indebtedness, extend or replace existing revolving credit facilities or for other corporate purposes.

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Cash Flows

The following table sets forth our consolidated cash flows for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
	2013			2012			2011
	(dollars in thousands)
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
Net increase (decrease) in cash and cash equivalents	$	108,203		$	(40,770	)	$	85,379

Cash Flows Provided by Operating Activities

Net cash provided by operating activities for the year ended December 31, 2013 was $162.2 million, compared to $387.8 million for the year ended December 31, 2012. The reduction in cash provided by operating activities of $225.6 million was primarily due to lower net income after adjusting for non-cash items of $152.2 million, lower cash on a reduction of other non-current liabilities of $116.3 million and lower cash collected on accounts receivable of $65.7 million during the year ended December 31, 2013 compared to 2012, partially offset by lower cash used on reduction of inventories of $91.8 million and lower cash used on prepaid expenses and other current assets of $19.4 million.

Net cash provided by operating activities for the year ended December 31, 2012 was $387.8 million, compared to $69.6 million for the year ended December 31, 2011. The change in cash provided by operating activities of $318.2 million was primarily due to higher net income after adjusting for non-cash items of $184.7 million and increased cash collected on accounts receivable of $122.2 million during the year ended December 31, 2012 compared to 2011.

Cash Flows Used In Investing Activities

Net cash used in investing activities was $51.4 million for the year ended December 31, 2013, compared to $105.0 million for the year ended December 31, 2012. The decrease in net cash used in investing activities of $53.6 million was primarily due to a decrease in capital expenditures of $25.4 million and an increase in proceeds from the sale of assets of $26.7 million during the year ended December 31, 2013 compared to 2012.

Net cash used in investing activities was $105.0 million for the year ended December 31, 2012, compared to $126.5 million for the year ended December 31, 2011. The decrease in net cash used in investing activities of $21.5 million was primarily due to a decrease in capital expenditures of $18.7 million for the year ended December 31, 2012 as well as earnout payments of $6.5 million made during the year ended December 31, 2011 related to the Krotz Springs refinery acquisition.

Cash Flows Provided by (Used In) Financing Activities

Net cash used in financing activities was $2.6 million for the year ended December 31, 2013, compared to $323.6 million for the year ended December 31, 2012. The decrease in net cash used in financing activities of $321.0 million was primarily due to reduced payments on debt, net, of $513.5 million for the year ended December 31, 2013 compared to 2012. These amounts were partially offset by changes in Partnership related transactions of $199.5 million, comprised of payments for Partnership distributions of $31.7 million during the year ended December 31, 2013, compared to proceeds received from the Partnership’s initial public offering, net of fees, of $167.8 million during the year ended December 31, 2012.

Net cash used in financing activities was $323.6 million for the year ended December 31, 2012, compared to net cash provided by financing activities of $142.4 million for the year ended December 31, 2011. The change in net cash provided by (used in) financing activities of $466.0 million was primarily attributable to payments on debt, net, of $481.6 million for the year ended December 31, 2012, compared to borrowings of debt, net, of $139.4 million for the year ended December 31, 2011. These amounts were partially offset by proceeds from the Partnership’s initial public offering, net of fees, of $167.8 million during the year ended December 31, 2012, compared to proceeds from the sale of our common stock of $11.9 million during the year ended December 31, 2011.

Cash and Cash Equivalents

We consider all highly-liquid instruments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value.

As of December 31, 2013, our total cash and cash equivalents were $224.5 million and we had total debt of $612.2 million.

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Indebtedness

Alon USA Energy, Inc. Credit Facilities

Convertible Senior Notes. In September 2013, we completed an offering of 3.00% unsecured convertible senior notes (the “Convertible Notes”) in aggregate principal amount of $150.0 million, which mature in September 2018. Interest on the Convertible Notes is payable semiannually in arrears on March 15 and September 15 of each year, beginning on March 15, 2014. The Convertible Notes are not redeemable at our option prior to maturity. Under the terms of the Convertible Notes, the holders of the Convertible Notes cannot require us to repurchase all or part of the notes except for instances of a fundamental change, as defined in the indenture.

The holders of the Convertible Notes may convert at any time after June 15, 2018 if our common stock is above approximately $14.79 per share. Prior to June 15, 2018 and after December 31, 2013, holders may convert if our common stock is above approximately $19.22 per share, as defined in the indenture. The Convertible Notes may be converted into shares of our common stock, into cash, or into a combination of cash and shares of common stock, at our election. Our current intent is to settle conversions of each $1 (in thousands) principal amount of the Convertible Notes through cash payments, with any excess of this amount to be settled by a combination of cash and shares of our common stock.

The Convertible Notes were issued at an offering price of 100% and we received gross proceeds of $150.0 million (before fees and expenses related to the offering). The Convertible Notes had an initial conversion rate of 67.627 shares of our common stock per each $1 (in thousands) principal amount of the Convertible Notes and is equivalent to an initial conversion price of approximately $14.79 per share, which represents a conversion premium of 32.5% on our last reported common stock price of $11.16 per share on the date of the Convertible Notes offering. The conversion rate is subject to adjustment upon the occurrence of certain events, but will not be adjusted for any accrued and unpaid interest. The Convertible Notes do not contain any maintenance financial covenants.

We used $15.2 million of the proceeds to fund the cost of entering into convertible note hedge transactions (after such cost was partially offset by the proceeds we received from entering into warrant transactions) described below. In October 2013, we used the remaining net 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.

Convertible Note Hedge Transactions

In connection with the Convertible Notes offering, we also entered into convertible note hedge transactions with respect to our common stock (the “Purchased Options”) with the initial purchasers of the Convertible Notes (the “Hedge Counterparties”). We paid an aggregate amount of $28.5 million to the Hedge Counterparties for the Purchased Options. The Purchased Options, with a strike price of $14.79 per share of our common stock, cover 10,144,050 shares of our common stock, subject to customary anti-dilution adjustments, that initially underlie the Convertible Notes sold in the offering. The Purchased Options will expire in September 2018.

The Purchased Options are intended to reduce the potential dilution with respect to our common stock upon conversion of the Convertible Notes as well as offset any potential cash payments we are required to make in excess of the principal amount upon any conversion of the notes.

The Purchased Options are separate transactions and are not part of the terms of the Convertible Notes. Holders of the Convertible Notes do not have any rights with respect to the Purchased Options.

Warrant Transactions

In connection with the Convertible Notes offering, we also entered into warrant transactions (the “Warrants”), whereby we sold to the Hedge Counterparties warrants in an aggregate amount of $13.2 million to acquire, subject to customary anti-dilution adjustments, up to 10,144,050 shares of our common stock at a strike price of approximately $20.09 per share of our common stock. The Warrants will be settled on a net-share basis and will expire in April 2019.

The Warrants are separate transactions and are not part of the terms of the Convertible Notes. Holders of the Convertible Notes do not have any rights with respect to the Warrants.

2006 Term Loan Credit Facility. In June 2006, we entered into a $450.0 million term loan (“2006 Term Loan”). The 2006 Term Loan required principal repayments of $4.5 million per annum paid in quarterly installments until maturity in August 2013. In November 2012, we repaid in full our obligations under the 2006 Term Loan. As a result of the prepayment of the 2006 Term Loan, a write-off of unamortized debt issuance costs of $1.5 million is included in interest expense in the consolidated statements of operations for the year ended December 31, 2012.

Alon USA Term Loan Credit Facility. In November 2012, we entered into a term loan (“Alon USA Term Loan”) with an aggregate principal amount of $450.0 million, issued at an offering price of 95%, that matures in November 2018. Proceeds

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from the Alon USA Term Loan were used to repay in full our obligations under the 2006 Term Loan and for general corporate purposes.

In connection with the closing of the Partnership’s initial public offering in November 2012 (the “Offering”), we assigned $250.0 million of the aggregate principal balance of the Alon USA Term Loan to the Partnership and used proceeds from the Offering to fully repay the remaining outstanding balance of the Alon USA Term Loan.

As a result of the prepayment of the Alon USA Term Loan, write-offs of unamortized original issuance discount and debt issuance costs of $18.8 million and $7.4 million, respectively, are included in interest expense in the consolidated statements of operations for the year ended December 31, 2012.

Letter of Credit Facility. In March 2010, we entered into a credit facility with Israel Discount Bank of New York, as amended from time to time, (the “Alon Energy Letter of Credit Facility”) for the issuance of letters of credit in an amount not to exceed $60.0 million and with a sub-limit for borrowings not to exceed $30.0 million.

In December 2013, the Alon Energy Letter of Credit Facility was amended to extend the maturity to November 2015. The Alon Energy Letter of Credit Facility is for the issuance of standby letters of credit in an amount not to exceed $60.0 million. We are required to pledge $100.0 million of the Partnership’s common units as collateral for the Alon Energy Letter of Credit Facility. Additionally, Alon Assets, Inc. was named as a guarantor, guaranteeing all of our obligations under the Alon Energy Letter of Credit Facility in the event of default. The Alon Energy Letter of Credit Facility contains certain restrictive covenants including maintenance financial covenants.

At December 31, 2013 and 2012, we had outstanding letters of credit under this facility of $56.8 million and $59.5 million, respectively.

Alon USA Partners, LP Credit Facility

Partnership Term Loan Credit Facility. In connection with the Offering, the Partnership was assigned $250.0 million of the aggregate principal balance of the Alon USA Term Loan (the “Partnership Term Loan”). The Partnership Term Loan requires principal payments of $2.5 million per annum paid in quarterly installments until maturity in November 2018.

The Partnership Term Loan bears interest at a rate equal to the sum of (i) the Eurodollar rate (with a floor of 1.25% per annum) plus (ii) a margin of 8.00% per annum for a per annum rate of 9.25%, based on current Eurodollar market rates at December 31, 2013.

The Partnership Term Loan is secured by a first priority lien on all of the Partnership’s fixed assets and other specified property, as well as on the general partner interest in the Partnership held by the General Partner, and a second lien on the Partnership’s cash, accounts receivables, inventories and related assets.

The Partnership Term Loan contains restrictive covenants, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, different businesses, certain lease obligations and certain restricted payments. The Partnership Term Loan does not contain any maintenance financial covenants.

At December 31, 2013 and 2012, the Partnership Term Loan had an outstanding balance (net of unamortized discount) of $244.3 million and $246.3 million, respectively.

Revolving Credit Facility. We have a $240.0 million revolving credit facility (the “Alon USA LP Credit Facility”) that will mature in March 2016. The Alon USA LP Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility amount or the borrowing base amount under the facility.

Borrowings under the Alon USA LP Credit Facility bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%.

The Alon USA LP Credit Facility is secured by a first lien on our cash, accounts receivables, inventories and related assets and a second lien on fixed assets and other specified property, in each case, excluding those of Alon Paramount Holdings, Inc. (“Alon Holdings”) and its subsidiaries other than Alon Pipeline Logistics, LLC (“Alon Logistics”), the subsidiaries established in conjunction with the Krotz Springs refinery acquisition, the subsidiaries established in conjunction with the Bakersfield refinery acquisition and our retail subsidiaries.

The Alon USA LP Credit Facility contains certain restrictive covenants including maintenance financial covenants.

Borrowings of $100.0 million and $49.0 million were outstanding under the Alon USA LP Credit Facility at December 31, 2013 and 2012, respectively. At December 31, 2013 and 2012, outstanding letters of credit under the Alon USA LP Credit Facility were $109.8 million and $58.8 million, respectively.

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Alon Refining Krotz Springs, Inc. Credit Facilities

Senior Secured Notes. In October 2009, Alon Refining Krotz Springs, Inc. (“ARKS”) issued 13.50% senior secured notes (the “Senior Secured Notes”) in aggregate principal amount of $216.5 million in a private offering. In February 2010, ARKS exchanged $216.5 million of Senior Secured Notes for an equivalent amount of Senior Secured Notes (“Exchange Notes”) registered under the Securities Act of 1933. The Exchange Notes will mature in October 2014 and the entire principal amount is due at maturity. Interest is payable semi-annually in arrears on April 15 and October 15. The Exchange Notes are substantially identical to the Senior Secured Notes, except that the Exchange Notes have been registered with the Securities and Exchange Commission and are not subject to transfer restrictions. The Senior Secured Notes were issued at an offering price of 94.857% and ARKS received gross proceeds of $205.4 million (before fees and expenses related to the offering). ARKS used the proceeds to repay in full all outstanding obligations under its term loan at that time. The remaining proceeds from the offering were used for general corporate purposes.

The terms of the Senior Secured Notes are governed by an indenture (the “Indenture”) and the obligations under the Indenture are secured by a first priority lien on ARKS’ property, plant and equipment and a second priority lien on ARKS’ cash, accounts receivable and inventory.

The Indenture contains restrictive covenants such as restrictions on loans, mergers, sales of assets, additional indebtedness and restricted payments. The Indenture does not contain any maintenance financial covenants.

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 Senior Secured Notes.

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 Senior Secured Notes.

At December 31, 2013, the Senior Secured Notes due October 2014 had an outstanding balance (net of unamortized discount) of $73.7 million, included in current portion of long-term debt. At December 31, 2012, the Senior Secured Notes had an outstanding balance (net of unamortized discount) of $211.6 million, included in long-term debt. ARKS is utilizing the effective interest method to amortize the original issuance discount over the life of the Senior Secured Notes.

Retail Credit Facilities

Alon Brands Term Loans. In March 2011, Alon Brands issued $30.0 million five-year unsecured notes (the “Alon Brands Term Loans”) to a group of investors including certain shareholders of Alon Israel and their affiliates. In conjunction with the issuance of the Alon Brands Term Loans, we issued 3,092,783 warrants to purchase shares of our common stock. The allocated fair value of the warrants was $11.0 million and was recorded as additional paid-in capital at the time of issuance.

In March 2012, we issued $30.0 million of 8.5% Series B Convertible Preferred Stock to the holders of the Alon Brands Term Loans and repaid in full our obligations under the Alon Brands Term Loans. Also as part of the transaction, the warrants issued in conjunction with the Alon Brands Term Loans were surrendered to us. As the Alon Brands Term Loans were originally issued at a discount, the remaining $9.6 million of unamortized original issuance discount was charged to interest expense in the consolidated statements of operations for the year ended December 31, 2012.

Term Credit Agreement. Southwest Convenience Stores, LLC (“SCS”) is party to a credit agreement (the “SCS Credit Agreement”) that, as amended, matures in December 2015. In December 2010, SCS entered into an amendment to the SCS Credit Agreement, which increased the amount outstanding from $73.4 million (“SCS Refinancing Term Loan”) by $10.0 million (“SCS Additional Term Loan”) and also included a revolving credit loan (“SCS Revolving Credit Loan”) with a maximum loan amount of the lesser of the borrowing base or $10.0 million.

Borrowings under the SCS Refinancing Term Loan bear interest at a Eurodollar rate plus 2.00% per annum with principal payments made in quarterly installments based on a 15-year amortization schedule. Borrowings under the SCS Additional Term Loan bear interest at a Eurodollar rate plus 2.75% per annum with principal payments made in quarterly installments based on a 5-year amortization schedule. Borrowings under the SCS Revolving Credit Loan bear interest at a Eurodollar rate plus 2.75% per annum.

The obligations under the SCS Credit Agreement are secured by a pledge of substantially all of the assets of SCS and Skinny’s, LLC and each of their subsidiaries, including cash, accounts receivable and inventory. The SCS Credit Agreement contains certain restrictive covenants including maintenance financial covenants.

At December 31, 2013 and 2012, the SCS Credit Agreement had an outstanding balance under the term loans of $62.7 million and $69.6 million, respectively. At December 31, 2013 and 2012, the SCS Revolving Credit Loan had an outstanding balance of $10.0 million and $10.0 million, respectively.

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Other Retail Related Credit Facilities

In 2003, we obtained $1.5 million in mortgage loans to finance the acquisition of new retail locations. The interest rates on these loans ranged between 5.5% and 9.7%, with 5 to 15 year payment terms. At December 31, 2013 and 2012, the outstanding balances were $0.4 million and $0.6 million, respectively.

Financial Covenants. We have certain credit facilities that contain restrictive covenants, including maintenance financial covenants. At December 31, 2013, we were in compliance with these covenants.

Capital Spending

Each year our Board of Directors approves capital projects, including sustaining maintenance, regulatory and planned turnaround projects that our management is authorized to undertake in our annual capital budget. Additionally, at times when conditions warrant or as new opportunities arise, growth and profit improvement projects may be approved. Our total capital expenditure budget, including expenditures for chemical catalyst and turnarounds, for 2014 is $149.1 million.

The following table summarizes our expected capital expenditures for 2014 by operating segment and major category:

	2014
	(dollars in thousands)
Refining and Marketing Segment:
Sustaining maintenance, regulatory and chemical catalyst and turnaround	$	67,481
Growth/profit improvement	44,778
Total	112,259
Asphalt Segment:
Sustaining maintenance	6,526
Growth/profit improvement	36
Total	6,562
Retail Segment:
Sustaining maintenance	4,723
Growth/profit improvement	23,295
Total	28,018
Corporate Segment:
Sustaining	2,269
Total Capital Expenditures	$	149,108

Our estimated capital expenditures are subject to change due to unanticipated increases/decreases in the cost, scope and completion time for our capital projects. For example, we may experience increases/decreases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of our refineries, asphalt terminals and retail locations.

Contractual Obligations and Commercial Commitments

Information regarding our known contractual obligations of the types described below as of December 31, 2013 is set forth in the following table:

	Payments Due by Period
Contractual Obligations	Less than 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years		Total
			(dollars in thousands)
Long-term debt obligations	$	83,174	$	170,953	$	358,050	$	71	$	612,248
Operating lease obligations	25,710		42,716		30,938		45,916		145,280
Pipelines and Terminals Agreement (1)	34,696		71,434		62,099		58,769		226,998
Other commitments (2)	3,741		7,482		7,482		11,280		29,985
Total obligations	$	147,321	$	292,585	$	458,569	$	116,036	$	1,014,511

_____________________

(1) Balances represent the minimum committed volume multiplied by the tariff and terminal rates pursuant to the terms of the Pipelines and Terminals Agreement with HEP, as well as our minimum requirements with Sunoco.

(2) Other commitments include refinery maintenance services costs.

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As of December 31, 2013, we did not have any material capital lease obligations or any agreements to purchase goods or services, other than those included in the table above, that were binding on us.

Off-Balance Sheet Arrangements

We have no material off-balance sheet arrangements.

Critical Accounting Policies

Our accounting policies are described in the notes to our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. We prepare our consolidated financial statements in conformity with GAAP. In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events, some of which we may have little or no control over. Our critical accounting policies, which are discussed below, could materially affect the amounts recorded in our consolidated financial statements.

Inventory. Crude oil, refined products and blendstocks for the refining and marketing segment and asphalt for the asphalt segment are priced at the lower of cost or market value. Cost is determined using the LIFO valuation method. Under the LIFO valuation method, we charge the most recent acquisition costs to cost of sales, and we value inventories at the earliest acquisition costs. We selected this method because we believe it more accurately reflects the cost of our current sales. If the market value of inventory is less than the inventory cost on a LIFO basis, then the inventory is written down to market value. An inventory write-down to market value results in a non-cash accounting adjustment, decreasing the value of our crude oil and refined products inventory and increasing our cost of sales. Reductions of inventory volumes during 2013, 2012 and 2011 resulted in a liquidation of LIFO inventory layers. The liquidation increased cost of sales by $1.5 million during 2013 and decreased cost of sales by $13.6 million and $59.3 million during 2012 and 2011, respectively. Market values of crude oil, refined products, asphalt and blendstock inventories exceeded LIFO costs by $61.2 million and $58.2 million at December 31, 2013 and 2012, respectively.

Pension and Other Postretirement Benefits. Accounting for pensions and other postretirement benefits involves several assumptions and estimates including discount rates, expected rate of return on plan assets, rates of compensation, health care cost trends, inflation, retirement rates and mortality rates.

We must assume a rate of return on funded pension plan assets in order to estimate our obligations under our defined benefit plans. Due to the nature of these calculations, we engage an actuarial firm to assist with these estimates and the calculation of certain employee benefit expenses. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect our periodic financial statements and funding patterns over time. We record an asset for our plans’ overfunded status or a liability if the plans are underfunded. The funded status represents the difference between the fair value of our plans’ assets and its projected benefit obligations. While we believe the assumptions we used are appropriate, significant differences in actual experience or significant changes in assumptions would affect pension and other postretirement benefits costs and obligations. For example, a 0.25 percent change in the assumptions related to the expected return on plan assets and discount rate for the funded qualified employee retirement plan would have the following effects on the projected benefit obligation as of December 31, 2013 and net periodic benefit cost for the year ending December 31, 2014 (in thousands):

	0.25-Percentage Point Change
Expected rate of return:
Effect on net periodic pension expense	$	172
Discount rate:
Effect on net periodic pension expense	453
Effect on projected benefit obligation	4,126

Environmental and Other Loss Contingencies. We expense or capitalize environmental expenditures depending on their future economic benefit. We expense expenditures that relate to an existing condition caused by past operations and that have no future economic benefit. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Environmental liabilities represent the estimated costs to investigate and remediate contamination at our properties. This estimate is based on internal and third-party assessments of the extent of the contaminations, the selected remediation technology and review of applicable environmental regulations. We do not discount environmental liabilities to their present value unless payments are fixed or reliably determinable. At December 31, 2013, for those payments we considered fixed or reliably determinable, payments were

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discounted at a 3.38% rate. We record environmental liabilities without considering potential recoveries from third parties. Recoveries of environmental remediation costs from third parties are recorded as assets when receipt is deemed probable. We update our estimates to reflect changes in factual information, available technology or applicable laws and regulations. Substantially all amounts accrued are expected to be paid out over the next 15 years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

Turnarounds and Chemical Catalyst Costs. We record the cost of planned major refinery maintenance, referred to as turnarounds, and chemical catalyst used in the refinery process units, which are typically replaced in conjunction with planned turnarounds, in “Other assets” in our consolidated financial statements. Turnaround and catalyst costs are deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround. The amortization of deferred turnaround and chemical catalysts costs are presented in depreciation and amortization in our consolidated financial statements.

Impairment of Long-Lived Assets. Our long-lived assets and certain identifiable intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of an asset to future net cash flows expected to be generated by the asset. If the carrying value of an asset exceeds its expected future cash flows, an impairment loss is recognized based on the excess of the carrying value of the impaired asset over its fair value. These future cash flows and fair values are estimates based on our judgment and assumptions. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs of disposition.

Deferred Income Taxes. Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Asset Retirement Obligations. The accounting standards established for asset retirement obligations require companies to recognize the liability for the fair value of a legal obligation to perform asset retirement activities that are conditional on a future event, if the amount can be reasonably estimated.

We have asset retirement obligations with respect to our refineries due to various legal obligations to clean and/or dispose of these assets at the time they are retired. However, the majority of these assets can be used for extended and indeterminate periods of time provided that they are properly maintained and/or upgraded. It is our practice and intent to continue to maintain these assets and make improvements based on technological advances. When a date or range of dates can reasonably be estimated for the retirement of these assets or any component part of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using established present value techniques.

We also have asset retirement obligations with respect to the removal of underground storage tanks and the removal of brand signage at our owned and leased retail sites. The asset retirement obligation for storage tank removal on leased retail sites is accreted over the expected life of the underground storage tank, which approximates the average retail site lease term.

Goodwill and Intangible Assets. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over 1 to 40 years. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. Alon uses December 31 of each year as the valuation date for annual impairment testing purposes.

At December 31, 2013, we had three reporting units with goodwill; California refining, California asphalt, and Retail operations. We compared the carrying values of the assets and liabilities of the three reporting units to their fair values. The fair values of our reporting units in 2013 that contain goodwill were determined based on discounted cash flow models with estimated cash flows based on internal forecasts of revenues and expenses. Each reporting unit was evaluated separately. Cash flows were discounted at rates that approximate a market participants’ weighted average cost of capital; 12.0% for both California refining and California asphalt and 9.5% for Retail operations. We also compared these fair values to market earnings multiples over the internal forecasts of revenues and expenses. We believe this approach is an appropriate valuation technique for the purposes of our impairment testing. As of December 31, 2013, we concluded from our valuations that the fair value of each reporting unit substantially exceeded its carrying value and therefore none of our goodwill was impaired.

If we are unable to achieve these margins for a sustained period in the future, it could result in impairment of goodwill. In addition if, (1) our equity value declines, (2) the fair value of our reporting units decline, or (3) the impact of economic or competitive factors adversely affect beyond what was anticipated, we could conclude in future periods that impairment losses

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are required in order to reduce the carrying value of our goodwill, and, to a lesser extent, long-lived assets. Depending on the severity of the changes in the key factors underlying the valuation of our reporting units, such losses could be significant.

A significant portion of the fair value of our California refining reporting unit is dependent on cash flows expected to be derived pursuant to a permit to begin logistical operations for crude oil delivered by rail. We have filed an application for the permit and expect to receive approval in 2014. If the permit is not obtained, approximately $39 million in goodwill is reasonably likely to be impaired.

Reconciliation of Amounts Reported Under Generally Accepted AccountingPrinciples

Reconciliation of Adjusted EBITDA to amounts reported under generally accepted accounting principles in financial statements.

Adjusted EBITDA represents earnings before net income attributable to non-controlling interest, income tax expense, interest expense, depreciation and amortization and gain (loss) on disposition of assets. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of net income attributable to non-controlling interest, income tax expense, interest expense, gain (loss) on disposition of assets and the accounting effects of capital expenditures and acquisitions, items that may vary for different companies for reasons unrelated to overall operating performance.

Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:

• Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

• Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;

• Adjusted EBITDA does not reflect the prior claim that non-controlling interest have on the income generated by non-wholly-owned subsidiaries;

• Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and

• Our calculation of Adjusted EBITDA may differ from EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.

Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.

The following table reconciles net income available to stockholders to Adjusted EBITDA for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
	2013			2012		2011
	(dollars in thousands)
Net income available to stockholders	$	22,986		$	79,134	$	42,507
Net income attributable to non-controlling interest	25,129			11,463		1,241
Income tax expense	12,151			49,884		18,918
Interest expense	94,694			129,572		88,310
Depreciation and amortization	125,494			121,929		113,730
(Gain) loss on disposition of assets	(9,558		)	2,309		(729		)
Adjusted EBITDA	$	270,896		$	394,291	$	263,977

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

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Changes in commodity prices, purchased fuel prices and interest rates are our primary sources of market risk. Our risk management committee oversees all activities associated with the identification, assessment and management of our market risk exposure.

Commodity Price Risk

We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels and governmental regulatory initiatives. Our risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations.

In order to manage the uncertainty relating to inventory price volatility, we have consistently applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as timing of crude oil cargo deliveries, turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. Upon the review and approval of our risk management committee, we may utilize the commodity futures market to manage these anticipated inventory variances.

We maintain inventories of crude oil, refined products, asphalt and blendstocks, the values of which are subject to wide fluctuations in market prices driven by world economic conditions, regional and global inventory levels and seasonal conditions. As of December 31, 2013, we held 1.3 million barrels of crude oil, refined product and asphalt inventories valued under the LIFO valuation method. Market value exceeded carrying value of LIFO costs by $61.2 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced by $1.3 million.

In accordance with fair value provisions of ASC 825-10, all commodity futures contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section or accumulated other comprehensive income of our consolidated financial statements. “Forwards” represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. “Futures” represent trades which have been executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. A “long” represents an obligation to purchase product and a “short” represents an obligation to sell product.

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The following table provides information about our derivative commodity instruments as of December 31, 2013:

Description of Activity	Contract Volume (in barrels)		Wtd Avg Purchase Price/BBL		Wtd Avg Sales Price/BBL		Contract Value			Market Value			Gain (Loss)
							(in thousands)
Forwards-long (Crude)	270,922		97.43		—		$	26,396		$	26,476		$	80
Forwards-short (Crude)	(2,820	)	—		109.88		(310		)	(311		)	(1		)
Forwards-long (Gasoline)	56,294		111.38		—		6,270			6,421			151
Forwards-short (Gasoline)	(336,665	)	—		110.94		(37,349		)	(38,252		)	(903		)
Forwards-long (Distillate)	101,643		124.86		—		12,691			12,765			74
Forwards-short (Distillate)	(169,198	)	—		120.74		(20,429		)	(20,726		)	(297		)
Forwards-long (Jet)	23,935		126.59		—		3,030			3,082			52
Forwards-short (Jet)	(67,908	)	—		124.14		(8,430		)	(8,578		)	(148		)
Forwards-long (Slurry)	36,779		85.89		—		3,159			3,154			(5		)
Forwards-short (Slurry)	(597	)	—		90.96		(54		)	(58		)	(4		)
Forwards-short (Catfeed)	(61,854	)	—		112.21		(6,941		)	(7,089		)	(148		)
Forwards-long (Slop)	12,171		87.89		—		1,070			1,084			14
Forwards-short (Slop)	(14,656	)	—		92.89		(1,361		)	(1,369		)	(8		)
Forwards-short (Propane)	(21,329	)	—		51.82		(1,105		)	(1,097		)	8
Forwards-long (Asphalt)	32,043		120.03		—		3,846			3,654			(192		)
Forwards-short (Asphalt)	(127,568	)	—		100.55		(12,827		)	(11,983		)	844
Futures-long (Crude)	8,000		98.38		—		787			788			1
Futures-short (Crude)	(178,000	)	—		97.86		(17,419		)	(17,519		)	(100		)
Futures-long (Gasoline)	355,000		114.88		—		40,784			41,538			754
Futures-short (Gasoline)	(53,000	)	—		114.70		(6,079		)	(6,201		)	(122		)
Futures-long (Distillate)	231,000		127.52		—		29,458			29,743			285
Description of Activity	Contract Volume (in barrels)		Wtd Avg Contract Spread		Wtd Avg Market Price		Contract Value			Market Value			Gain (Loss)
							(in thousands)
Futures-swaps	5,760,000		$	21.20	$	25.87	$	(122,116	)	$	(149,013	)	$	(26,897	)

Interest Rate Risk

As of December 31, 2013, $417.0 million of our outstanding debt was at floating interest rates out of which $100.0 million was at the Eurodollar rate plus 3.50%, subject to a minimum interest rate of 4.00%, and $247.5 million, excluding discounts, was at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00%. An increase of 1% in the Eurodollar rate on indebtedness, net of the instruments subject to the minimum interest rates, would result in an increase in our interest expense of approximately $1.4 million per year.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The Consolidated Financial Statements are included as an annex of this Annual Report on Form 10-K. See the Index to Consolidated Financial Statements on page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

59

ITEM 9A. CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures

Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended (the “Exchange Act”)) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or furnish under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or furnish under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate “internal control over financial reporting” (as defined in Rule 13a-15(f) under the Exchange Act) for Alon. Our management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2013. In management’s evaluation, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (1992). Management believes that as of December 31, 2013, our internal control over financial reporting was effective based on those criteria.

The independent registered public accounting firm of KPMG LLP, as auditors of our consolidated financial statements, has issued an attestation report on the effectiveness of our internal control over financial reporting, included with the Consolidated Financial Statements as an annex of this Annual Report on Form 10-K.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

None.

60

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

The information concerning our directors set forth under “Corporate Governance Matters - The Board of Directors” in the proxy statement for our 2014 annual meeting of stockholders (the “Proxy Statement”) is incorporated herein by reference. Certain information concerning our executive officers is set forth under the heading “Business and Properties - Executive Officers of the Registrant” in Items 1 and 2 of this Annual Report on Form 10-K, which is incorporated herein by reference. The information concerning compliance with Section 16(a) of the Exchange Act set forth under “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement is incorporated herein by reference.

The information concerning our audit committee set forth under “Corporate Governance Matters - Committees of the Board and - Audit Committee” in the Proxy Statement is incorporated herein by reference.

The information regarding our Code of Ethics set forth under “Corporate Governance Matters - Corporate Governance Guidelines, Code of Business Conduct and Ethics and Committee Charters” in the Proxy Statement is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION.

The information set forth under “Executive Compensation” in the Proxy Statement is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ANDRELATED STOCKHOLDER MATTERS.

The information set forth under “Security Ownership of Certain Beneficial Holders and Management” in the Proxy Statement is incorporated herein by reference. The information regarding our equity plans under which shares of our common stock are authorized for issuance as set forth under “Equity Compensation Plan Information” in the Proxy Statement is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTORINDEPENDENCE.

The information set forth under “Certain Relationships and Related Transactions” and under “Corporate Governance Matters — Independent Directors” in the Proxy Statement is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The information set forth under “Independent Public Accountants” in the Proxy Statement is incorporated herein by reference.

61

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

The following documents are filed as part of this report:

1. Financial Statements. See “Index to Consolidated Financial Statements” on page F-1.

2. Financial Statement Schedules and Other Financial Information. All financial statement schedules are omitted because either they are not applicable or the required information is included in the consolidated financial statements or notes included herein.

3. Exhibits. Exhibits filed as part of this Form 10-K are as follows:

Exhibit No.	Description of Exhibit
1.1	Underwriting Agreement by and among Alon USA Partners, LP, Alon USA Partners GP, LLC, Alon Assets, Inc., Alon USA GP, LLC and Alon USA Energy, Inc. and Goldman, Sachs & Co., Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc., as representatives of the several underwriters named therein, dated November 19, 2012 (incorporated by reference to Exhibit 1.1 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
1.2	Purchase Agreement, dated September 10, 2013, among Alon USA Energy, Inc., Goldman, Sachs & Co. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 1.1 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
3.1	Second Amended and Restated Certificate of Incorporation of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.1 to Form 10-Q, filed by the Company on May 9, 2012, SEC File No. 001-32567).
3.2	Amended and Restated Bylaws of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.2 to Form S-1/A, filed by the Company on July 14, 2005, SEC File No. 333-124797).
4.1	Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
4.2	Specimen 8.50% Series A Convertible Preferred Stock Certificate. (incorporated by reference to Exhibit 4.4 to Form 10-Q, filed by the Company on November 9, 2010, SEC File No. 001-32567).
4.3	Indenture, dated as of October 22, 2009, by and among Alon Refining Krotz Springs, Inc. and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K, filed by the Company on October 23, 2009, SEC File No. 001-32567).
4.4	Indenture related to the 3.00% Convertible Senior Notes due 2018, dated as of September 16, 2013, among Alon USA Energy, Inc. and U.S. Bank National Association, as trustee (including form of 3.00% Convertible Senior Note due 2018) (incorporated by reference to Exhibit 4.1 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
4.5	Form of Certificate of Designation of the 8.75% Series A Convertible Preferred Stock (incorporated by reference to Exhibit 4.3 to Form 10-Q filed by the Company on November 9, 2010, SEC File No. 001-32567).
4.6	Form of Certificate of Designation of the 8.75% Series B Convertible Preferred Stock (incorporated by reference to Exhibit 4.5 to Form 10-K, filed by the Company on March 13, 2012 SEC File No. 001-32567).
10.1	Pipeline Lease Agreement, dated as of December 12, 2007, between Plains Pipeline, L.P. and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on February 5, 2008, SEC File No. 001-32567).
10.2	Pipeline Lease Agreement, dated as of February 21, 1997, between Navajo Pipeline Company and American Petrofina Pipe Line Company (incorporated by reference to Exhibit 10.6 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.3	Amendment and Supplement to Pipeline Lease Agreement, dated as of August 31, 2007, by and between HEP Pipeline Assets, Limited Partnership and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on November 8, 2007, SEC File No. 001-32567).
10.4	Pipelines and Terminals Agreement, dated as of February 28, 2005, between Alon USA, LP and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.8 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.5	Premises Lease, dated as of May 12, 2003, between Southwest Convenience Stores, LLC and SCS Beverage, Inc. (incorporated by reference to Exhibit 10.35 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).

62

Exhibit No.	Description of Exhibit
10.6	Registration Rights Agreement, dated as of July 6, 2005, between Alon USA Energy, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.22 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
10.7	Registration Rights Agreement, dated October 22, 2009, between Alon Refining Krotz Springs, Inc. and Jefferies & Company, Inc. (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on October 23, 2009, SEC File No. 001-32567).
10.8	Form of Registration Rights Agreement among the Company and Subsidiary Shareholders, dated June 20, 2012 (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on June 26, 2012, SEC File No. 001-32567).
10.9	Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc. and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.5 to Form 10-Q, filed by the Company on August 9, 2010, SEC File No. 001-32567).
10.10	First Amendment, dated as of July 31, 2012, to the Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc. and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.7 to Form 10-Q, filed by the Company on August 9, 2012, SEC File No. 001-32567).
10.11	Second Amendment to Credit Agreement, dated as of July 31, 2013, to the Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc., and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.2 to Form 10-Q Filed by the Company on August 9, 2013, SEC File No. 001-32567).
10.12	Amended and Restated Credit Agreement, dated as of December 30, 2010, among Southwest Convenience Stores, LLC, Skinny’s, LLC, the lenders party thereto and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 6, 2011, SEC File No. 001-32567).
10.13	First Amendment to the Amended and Restated Credit Agreement, dated as of April 20, 2012, by and among Southwest Convenience Stores, LLC, Skinny’s, LLC, the lenders party thereto and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to Form 10-Q Filed by the Company on May 9, 2012, SEC File No. 001-32567).
10.14	Credit and Guaranty Agreement, dated as of November 13, 2012, among Alon USA Energy, Inc., Alon USA Partners, LP, the lenders party thereto and Credit Suisse AG, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on November 19, 2012, SEC File No. 001-32567).
10.15	Credit and Guaranty Agreement, dated as of November 26, 2012, among Alon USA Partners, LP, Alon USA Partners GP, LLC and certain subsidiaries of Alon USA Partners, LP, as Guarantors, the lenders party thereto and Credit Suisse AG, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on November 30, 2012, SEC File No. 001-32567).
10.16	Purchase Agreement, dated October 13, 2009, between Alon Refining Krotz Springs, Inc. and Jefferies & Co. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on October 19, 2009, SEC File No. 001-32567).
10.17	Management and Consulting Agreement, dated as of August 1, 2003, among Alon USA, Inc., Alon Israel Oil Company, Ltd. and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.21 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.18	Amendment, dated as of June 17, 2005, to the Management and Consulting Agreement, dated as of August 1, 2003, among Alon USA, Inc., Alon Israel Oil Company, Ltd. and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.21.1 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.19*	Executive Employment Agreement, dated as of July 31, 2000, between Jeff D. Morris and Alon USA GP, Inc., as amended by the Amendment to Executive/Management Employment Agreement, dated May 1, 2005 (incorporated by reference to Exhibit 10.23 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.20*	Second Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon USA GP, LLC (incorporated by reference to Exhibit 10.9 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
10.21*	Executive Employment Agreement between Jeff Morris and Alon USA Energy, Inc., dated May 3, 2011, (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 6, 2011, SEC File No. 001-32567).
10.22*	Management Employment Agreement, dated as of March 1, 2010, between Paul Eisman and Alon USA GP, LLC (incorporated by reference to Exhibit 10.22 to Form 10-K, filed by the Company on March 15, 2011 SEC File No. 001-32567).

63

Exhibit No.	Description of Exhibit
10.23*	Executive Employment Agreement, dated as of July 31, 2000, between Claire A. Hart and Alon USA GP, Inc., as amended by the Amendment to Executive/Management Employment Agreement, dated May 1, 2005 (incorporated by reference to Exhibit 10.24 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.24*	Second Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Claire A. Hart and Alon USA GP, LLC (incorporated by reference to Exhibit 10.10 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
10.25*	Executive Employment Agreement, dated as of August 1, 2003, between Shai Even and Alon USA GP, LLC (incorporated by reference to Exhibit 10.49 to Form 10-K, filed by the Company on March 15, 2007, SEC File No. 001-32567).
10.26*	Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Shai Even and Alon USA GP, LLC (incorporated by reference to Exhibit 10.14 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
10.27*	Management Employment Agreement, dated as of October 30, 2008, between Michael Oster and Alon USA GP, LLC (incorporated by reference to Exhibit 10.71 to Form 10-K, filed by the Company on April 10, 2009, SEC File No. 001-32567).
10.28*	Agreement of Principles of Employment, dated as of December 22, 2009, between David Wiessman and the Company (incorporated by reference to Exhibit 10.44 to Form 10-K, filed by the Company on March 13, 2012 SEC File No. 001-32567).
10.29*	Amended and Restated Employment Agreement by and between Paramount Petroleum Corporation and Alan P. Moret, dated July 8, 2011 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on July 13, 2011, SEC File No. 001-32567).
10.30*	Management Employment Agreement, dated as of May 1, 2008, between Kyle C. McKeen and Alon USA GP, LLC (incorporated by reference to Exhibit 10.47 to Form 10-K, filed by the Company on March 14, 2013 SEC File No. 001-32567).
10.31*	Description of Annual Bonus Plans (incorporated by reference to Exhibit 10.56 to Form 10-K, filed by the Company on March 15, 2011 SEC File No. 001-32567).
10.32*	Change of Control Incentive Bonus Program (incorporated by reference to Exhibit 10.29 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.33*	Description of Director Compensation (incorporated by reference to Exhibit 10.30 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.34*	Form of Director Indemnification Agreement (incorporated by reference to Exhibit 10.31 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.35*	Form of Officer Indemnification Agreement (incorporated by reference to Exhibit 10.32 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.36*	Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.33 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.37*	Alon Assets, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.36 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.38*	Alon USA Operating, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.37 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.39*	Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.38 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.40*	Second Amendment to Incentive Stock Option Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon Assets, Inc. (incorporated by reference to Exhibit 10.15 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
10.41	Shareholder Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.39 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.42*	Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Jeff D. Morris, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.40 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.43*	Second Amendment to Incentive Stock Option Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon USA Operating, Inc. (incorporated by reference to Exhibit 10.16 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).

64

Exhibit No.	Description of Exhibit
10.44	Shareholder Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Jeff D. Morris, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.41 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.45	Amendment to Shareholder Agreements among the Company, Alon Assets, Inc., Alon Operating, Inc., Jeff Morris and Jeff Morris/IRA, dated June 20, 2012 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on June 26, 2012, SEC File No. 001-32567).
10.46*	Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.42 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.47	Shareholder Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.43 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.48	Amendment to Shareholder Agreements among the Company, Alon Assets, Inc., Alon Operating, Inc., Claire Hart and Claire Hart/IRA, dated June 20, 2012 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on June 26, 2012, SEC File No. 001-32567).
10.49*	Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.44 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.50	Shareholder Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.45 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.51*	Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III, as amended by the Amendment to the Incentive Stock Option Agreement, dated July 25, 2002 (incorporated by reference to Exhibit 10.46 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.52	Shareholder Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.47 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.53*	Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III, as amended by the Amendment to the Incentive Stock Option Agreement, dated July 25, 2002 (incorporated by reference to Exhibit 10.48 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.54	Shareholder Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.49 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.55	Amendment to Shareholder Agreements – Option Shares, between Alon Assets, Inc., Alon Operating, Inc., Alon USA Energy, Inc. and Joseph A. Concienne, dated October 3, 2011 (incorporated by reference to Exhibit 10.68 to Form 10-K Filed by the Company on March13, 2012, SEC File No. 001-32567).
10.56	Agreement, dated as of July 6, 2005, among Alon USA Energy, Inc., Alon USA, Inc., Alon USA Capital, Inc., Alon USA Operating, Inc., Alon Assets, Inc., Jeff D. Morris, Claire A. Hart and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.52 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
10.57*	Alon USA Energy, Inc. Second Amended and Restated 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 9, 2012, SEC File No. 001-32567).
10.58*	Form of Restricted Stock Award Agreement relating to Director Grants pursuant to Section 12 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on August 5, 2005, SEC File No. 001-32567).
10.59*	Form of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on August 23, 2005, SEC File No. 001-32567).
10.60*	Form II of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on November 8, 2005, SEC File No. 001-32567).
10.61*	Form of Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on March 12, 2007, SEC File No. 001-32567).

65

Exhibit No.	Description of Exhibit
10.62*	Form of Amendment to Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on January 27, 2010, SEC File No. 001-32567).
10.63*	Form II of Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 27, 2010, SEC File No. 001-32567).
10.64*	Award Agreement between the Company and Paul Eisman, dated May 5, 2011, (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 9, 2011, SEC File No. 001-32567).
10.65*	Form of Award Agreement relating to Executive Officer Restricted Stock Grants pursuant to the Alon USA Energy, Inc. 2005 Amended and Restated Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on May 9, 2011, SEC File No. 001-32567).
10.66	Stock Purchase Agreement, dated as of April 28, 2006, among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy, III and Mark R. Milano (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 2, 2006, SEC File No. 001-32567).
10.67	First Amendment to Stock Purchase Agreement, dated as of June 30, 2006, among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy III and Mark R. Milano (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on November 14, 2006, SEC File No. 001-32567).
10.68	Second Amendment to Stock Purchase Agreement, dated as of July 31, 2006, among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy III and Mark R. Milano (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on November 14, 2006, SEC File No. 001-32567).
10.69	Stock Purchase Agreement, dated May 7, 2008, between Valero Refining and Marketing Company and Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 13, 2008, SEC File No. 001-32567).
10.70	First Amendment to Stock Purchase Agreement, dated as of July 3, 2008, by and among Valero Refining and Marketing Company, Alon Refining Krotz Springs, Inc. and Valero Refining Company-Louisiana (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
10.71	Series A Preferred Stock Purchase Agreement, dated as of July 3, 2008, by and between Alon Refining Louisiana, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
10.72	Stockholders Agreement, dated as of July 3, 2008, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
10.73	Amended and Restated Stockholders Agreement dated as of March 31, 2009, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.88 to Form 10-K, filed by the Company on April 10, 2009, SEC File No. 001-32567).
10.74	First Amendment to Amended and Restated Stockholders Agreement dated as of December 31, 2009, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 5, 2010, SEC File No. 001-32567).
10.75	Offtake Agreement, dated as of July 3, 2008, by and between Valero Marketing and Supply Company and Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 10.9 to Form 10-Q, filed by the Company on August 8, 2008, SEC File No. 001-32567).
10.76†	Amended and Restated Supply and Offtake Agreement, dated May 26, 2010 by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company.
10.77	First Amendment to the Supply and Offtake Agreement, dated January 20, 2011, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 10, 2011, SEC File No. 001-32567).
10.78	Amended and Restated Second Amendment to the Supply and Offtake Agreement, dated March 1, 2011, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.3 to Form 10-Q, filed by the Company on May 10, 2011, SEC File No. 001-32567).

66

Exhibit No.	Description of Exhibit
10.79	Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on November 7, 2011, SEC File No. 001-32567).
10.80†	Amendment, dated as of July 20, 2012, to the Amended and Restated Supply and Offtake Agreement, dated May 26, 2010, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company.
10.81	Amendment, dated as of February 1, 2013, to the Amended and Restated Supply and Offtake Agreement, dated May 26, 2010, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 10, 2013, SEC File No. 001-32567).
10.82†	Amended and Restated Supply and Offtake Agreement by and between Alon USA, LP and J. Aron & Company, dated March 1, 2011.
10.83	Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon USA, LP and J.Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on November 11, 2011, SEC File No. 001-32567).
10.84†	Amendment, dated as of July 20, 2012, to the Amended and Restated Supply and Offtake Agreement by and between Alon USA, LP, and J. Aron & Company, dated March 1, 2011.
10.85	Amendment to Supply and Offtake Agreement dated as of February 1, 2013 between J. Aron & Company and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on May 10, 2013, SEC File No. 001-32567).
10.86†	Supply and Offtake Agreement by and between J. Aron & Company and Alon Supply, Inc., dated May 30, 2012.
10.87†	Amendment, dated as of July 20, 2012, to the Supply and Offtake Agreement, dated May 30, 2012, by and between Alon Supply, Inc., and J. Aron and Company.
10.88	Amendment, dated as of February 1, 2013, to the Supply and Offtake Agreement between J. Aron & Company and Alon Supply, Inc. (incorporated by reference to Exhibit 10.3 to Form 10-Q, filed by the Company on May 10, 2013, SEC File No. 001-32567).
10.89	Form of Series A Convertible Preferred Stock Purchase Agreement (incorporated by reference to Exhibit 10.105 to Form S-1/A, filed by the Company on October 22, 2010, SEC File No. 333-169583).
10.90	Warrant Agreement, dated March 14, 2011, between the Company and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.106 to Form 10-K, filed by the Company on March 15, 2011 SEC File No. 001-32567).
10.91	Form of Series B Convertible Preferred Stock Purchase Agreement (incorporated by reference to Exhibit 10.106 to Form 10-K, filed by the Company on March 13, 2012 SEC File No. 001-32567).
10.92	Omnibus Agreement by and among Alon USA Partners, LP, Alon USA Partners GP, LLC, Alon Assets, Inc. and Alon Energy, Inc., dated November 26, 2012 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.93	Services Agreement by and among Alon USA Partners, LP, Alon USA Partners GP, LLC by and Alon Energy, Inc., dated November 26, 2012 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.94	Tax Sharing Agreement by and among Alon USA Partners, LP and Alon USA Energy, Inc., dated November 26, 2012 (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.95	Distributor Sales Agreement by and among Alon USA Partners, LP and Southwest Convenience Stores, LLC, dated November 26, 2012 (incorporated by reference to Exhibit 10.4 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.96	Offtake Agreement by and among Alon USA, LP and Paramount Petroleum Corporation, dated November 26, 2012 (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.97	Contribution, Conveyance and Assumption Agreement by and among Alon Assets, Inc., Alon USA Partners GP, LLC, Alon USA Partners, LP, Alon USA Energy, Inc., Alon USA Refining, LLC, Alon USA Operating, Inc., Alon USA, LP and Alon USA GP, LLC, dated November 26, 2012 (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.98	Second Amended Revolving Credit Agreement, dated as of May 23, 2013, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 24, 2013, SEC File No. 001-32567).

67

Exhibit No.	Description of Exhibit
10.99	Base Bond Hedge Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.100	Base Bond Hedge Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.101	Additional Bond Hedge Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.102	Additional Bond Hedge Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.4 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.103	Base Warrant Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.104	Base Warrant Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.105	Additional Warrant Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.7 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.106	Additional Warrant Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.8 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
21.1	Subsidiaries of Alon USA Energy, Inc.
23.1	Consent of KPMG LLP.
31.1	Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2	Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
100	The following financial information from Alon USA Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Balance Sheets, (ii) Statements of Operations, (iii) Statements of Comprehensive Income, (iv) Statement of Stockholders’ Equity, (v) Statements of Cash Flows and (vi) Notes to Financial Statements.

___________

* Identifies management contracts and compensatory plans or arrangements.

† Filed under confidential treatment request.

68

ALON USA ENERGY, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Audited Consolidated Financial Statements:
Reports of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2013 and 2012	F-4
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011	F-5
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012, and 2011	F-6
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2013, 2012 and 2011	F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	F-8
Notes to Consolidated Financial Statements	F-9

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Alon USA Energy, Inc.:

We have audited the accompanying consolidated balance sheets of Alon USA Energy, Inc. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2013. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Alon USA Energy, Inc. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Alon USA Energy, Inc.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 13, 2014 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas

March 13, 2014

F-2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Alon USA Energy, Inc.:

We have audited Alon USA Energy, Inc.’s internal control over financial reporting as of December 31, 2013, based oncriteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Alon USA Energy, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Alon USA Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Alon USA Energy, Inc. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2013, and our report dated March 13, 2014 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Dallas, Texas

March 13, 2014

F-3

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands, except per share data)

	As of December 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	224,499		$	116,296
Accounts and other receivables, net	200,398			183,632
Income tax receivable	16,053			506
Inventories	128,770			183,919
Deferred income tax asset	13,045			5,223
Prepaid expenses and other current assets	18,629			19,322
Total current assets	601,394			508,898
Equity method investments	26,251			21,582
Property, plant and equipment, net	1,429,342			1,492,493
Goodwill	105,943			105,943
Other assets, net	82,210			94,658
Total assets	$	2,245,140		$	2,223,574
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	336,499		$	309,573
Accrued liabilities	120,858			102,579
Current portion of long-term debt	83,174			9,504
Total current liabilities	540,531			421,656
Other non-current liabilities	189,474			254,946
Long-term debt	529,074			577,513
Deferred income tax liability	360,657			348,273
Total liabilities	1,619,736			1,602,388
Commitments and contingencies (Note 20)
Stockholders’ equity:
Preferred stock, par value $0.01, 15,000,000 shares authorized; 68,180 and 4,220,000 shares issued and outstanding at December 31, 2013 and 2012, respectively	682			42,200
Common stock, par value $0.01, 150,000,000 shares authorized; 68,641,428 and 61,272,429 shares issued and outstanding at December 31, 2013 and 2012, respectively	686			613
Additional paid-in capital	509,170			444,022
Accumulated other comprehensive loss, net of income tax	(37,515		)	(30,447		)
Retained earnings	124,936			128,319
Total stockholders’ equity	597,959			584,707
Non-controlling interest in subsidiaries	27,445			36,479
Total equity	625,404			621,186
Total liabilities and equity	$	2,245,140		$	2,223,574

The accompanying notes are an integral part of these consolidated financial statements.

F-4

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands, except per share data)

	Year Ended December 31,
	2013			2012			2011
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	168,172			161,401			143,122
Depreciation and amortization	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	(94,694		)	(129,572		)	(88,310		)
Equity earnings of investees	5,309			7,162			5,128
Other income (loss), net	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

___________________________________

(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.

The accompanying notes are an integral part of these consolidated financial statements.

F-5

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

	Year Ended December 31,
	2013			2012			2011
Net income	$	48,115		$	90,597		$	43,748
Other comprehensive income (loss):
Postretirement benefit plans:
Unrealized gain (loss) arising during the year related to:
Net actuarial gain (loss)	15,610			(15,183		)	(13,699		)
Curtailment	126			—			—
(Gain) loss reclassified to earnings
Net actuarial loss (1)	4,071			2,633			1,849
Prior service credit (1)	(51		)	(51		)	(58		)
Net gain (loss), before tax	19,756			(12,601		)	(11,908		)
Income tax expense (benefit)	7,224			(4,602		)	(4,792		)
Net gain (loss), net of tax	12,532			(7,999		)	(7,116		)
Interest rate derivatives designated as cash flow hedges:
Unrealized holding gain (loss) arising during period	—			132			(770		)
(Gain) loss reclassified to earnings - interest expense	—			4,065			4,074
Net gain, before tax	—			4,197			3,304
Income tax expense	—			1,469			1,157
Net gain, net of tax	—			2,728			2,147
Commodity contracts designated as cash flow hedges:
Unrealized holding loss arising during period	(9,475		)	(74,583		)	—
(Gain) loss reclassified to earnings - cost of sales	(22,021		)	76,097			—
Net gain (loss), before tax	(31,496		)	1,514			—
Income tax expense (benefit)	(11,644		)	546			—
Net gain (loss), net of tax	(19,852		)	968			—
Total other comprehensive loss, net of tax	(7,320		)	(4,303		)	(4,969		)
Comprehensive income	40,795			86,294			38,779
Comprehensive income attributable to non-controlling interest	24,877			11,124			838
Comprehensive income attributable to stockholders	$	15,918		$	75,170		$	37,941

_________________

(1) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost, as further discussed in Note 13. Net periodic benefit cost is reflected in direct operating expenses and selling, general and administrative expenses in the consolidated statements of operations.

The accompanying notes are an integral part of these consolidated financial statements.

F-6

ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (dollars in thousands)
	Preferred Stock			Common Stock		Additional Paid-In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total Stockholders’ Equity			Non-controlling Interest			Total Equity
Balance at December 31, 2010	$	40,000		$	543	$	290,809		$	(21,917	)	$	33,052		$	342,487		$	(720	)	$	341,767
Stock compensation expense	—			—		2,388			—			—			2,388			541			2,929
Dividends	—			—		—			—			(8,886		)	(8,886		)	(704		)	(9,590		)
Dividends of common stock on preferred stock	—			4		2,950			—			(3,400		)	(446		)	—			(446		)
Common stock issuance	—			14		12,067			—			—			12,081			(181		)	11,900
Stock issuance costs	—			—		(543		)	—			—			(543		)	—			(543		)
Warrants on debt issuance	—			—		10,988			—			—			10,988			—			10,988
Net income	—			—		—			—			42,507			42,507			1,241			43,748
Postretirement benefit plans, net of tax of $4,792	—			—		—			(6,713		)	—			(6,713		)	(403		)	(7,116		)
Fair value of interest rate swaps, net of tax of $1,157	—			—		—			2,147			—			2,147			—			2,147
Balance at December 31, 2011	40,000			561		318,659			(26,483		)	63,273			396,010			(226		)	395,784
Stock compensation expense	—			4		4,629			—			—			4,633			(503		)	4,130
Dividends	—			—		—			—			(9,196		)	(9,196		)	(524		)	(9,720		)
Dividends of common stock on preferred stock	—			7		4,127			—			(4,892		)	(758		)	—			(758		)
Preferred stock issuance	30,000			—		9,270			—			—			39,270			—			39,270
Stock issuance costs	—			—		(10		)	—			—			(10		)	—			(10		)
Warrants retired	—			—		(10,988		)	—			—			(10,988		)	—			(10,988		)
Preferred stock conversion	(27,800		)	41		27,759			—			—			—			—			—
Alon USA Partners, LP initial public offering	—			—		90,576			—			—			90,576			26,608			117,184
Net income	—			—		—			—			79,134			79,134			11,463			90,597
Postretirement benefit plans, net of tax of $4,602	—			—		—			(7,613		)	—			(7,613		)	(386		)	(7,999		)
Fair value of interest rate swaps, net of tax of $1,469	—			—		—			2,728			—			2,728			—			2,728
Fair value of commodity swaps, net of tax of $546	—			—		—			921			—			921			47			968
Balance at December 31, 2012	42,200			613		444,022			(30,447		)	128,319			584,707			36,479			621,186
Stock compensation expense	—			9		8,285			—			—			8,294			(1,279		)	7,015
Dividends	—			—		—			—			(24,081		)	(24,081		)	(886		)	(24,967		)
Dividends of common stock on preferred stock	—			—		1,984			—			(2,288		)	(304		)	—			(304		)
Equity issuance costs	—			—		(1,012		)	—			—			(1,012		)	—			(1,012		)
Equity component related to issuance of convertible notes, net of tax of $11,171	—			—		19,194			—			—			19,194			—			19,194
Convertible note hedge transactions, net of tax of $10,468	—			—		(17,987		)	—			—			(17,987		)	—			(17,987		)
Warrant transactions	—			—		13,230			—			—			13,230			—			13,230
Preferred stock conversion	(41,518		)	64		41,454			—			—			—			—			—
Distributions to non-controlling interest in the Partnership	—			—		—			—			—			—			(31,746		)	(31,746		)
Net income	—			—		—			—			22,986			22,986			25,129			48,115
Postretirement benefit plans, net of tax of $7,224	—			—		—			12,101			—			12,101			431			12,532
Fair value of commodity swaps, net of tax of $11,644	—			—		—			(19,169		)	—			(19,169		)	(683		)	(19,852		)
Balance at December 31, 2013	$	682		$	686	$	509,170		$	(37,515	)	$	124,936		$	597,959		$	27,445		$	625,404

The accompanying notes are an integral part of these consolidated financial statements.

F-7

ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands)
	Year Ended December 31,
	2013			2012			2011
Cash flows from operating activities:
Net income	$	48,115		$	90,597		$	43,748
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	125,494			121,929			113,730
Stock compensation	7,015			4,130			2,929
Deferred income tax expense	8,278			42,022			17,416
Equity earnings of investees (net of dividends)	(3,266		)	(1,240		)	(1,678		)
Amortization of debt issuance costs	4,496			6,296			6,493
Amortization of original issuance discount	4,300			2,570			3,050
Write-off of unamortized original issuance discount	1,871			28,374			—
Write-off of unamortized debt issuance costs	1,871			8,826			—
(Gain) loss on disposition of assets	(9,558		)	2,309			(729		)
Unrealized (gain) loss on commodity swaps	(3,085		)	31,936			(31,936		)
Changes in operating assets and liabilities:
Accounts and other receivables, net	(19,053		)	28,624			(96,717		)
Income tax receivable	(15,547		)	2,516			5,622
Inventories	55,149			(36,647		)	(7,387		)
Prepaid expenses and other current assets	8,410			(10,946		)	(501		)
Other assets, net	6,042			(9,260		)	(21,806		)
Accounts payable	1,726			10,977			5,605
Accrued liabilities	(2,794		)	5,718			9,178
Other non-current liabilities	(57,231		)	59,079			22,543
Net cash provided by operating activities	162,233			387,810			69,560
Cash flows from investing activities:
Capital expenditures	(68,513		)	(93,901		)	(112,625		)
Capital expenditures for turnarounds and catalysts	(8,617		)	(11,460		)	(9,734		)
Contribution to equity method investment	(1,403		)	—			—
Proceeds from disposition of assets	27,092			381			2,379
Earnout payments related to Krotz Springs refinery acquisition	—			—			(6,562		)
Net cash used in investing activities	(51,441		)	(104,980		)	(126,542		)
Cash flows from financing activities:
Dividends paid to stockholders	(24,081		)	(9,196		)	(8,886		)
Dividends paid to non-controlling interest	(886		)	(524		)	(704		)
Distributions paid to non-controlling interest in the Partnership	(31,746		)	—			—
Proceeds from issuance of common stock	—			—			11,900
Contributions from non-controlling interest in Alon USA Partners, LP	—			167,765			—
Equity issuance costs	(1,012		)	(10		)	(543		)
Inventory agreement transactions	25,200			—			1,165
Deferred debt issuance costs	(4,264		)	(17,512		)	(2,400		)
Revolving credit facilities, net	51,000			(259,341		)	123,222
Additions to long-term debt	150,000			427,500			30,136
Payments on long-term debt	(151,575		)	(632,282		)	(11,529		)
Proceeds from issuance of warrants	13,230			—			—
Payments for purchases of hedges on convertible debt	(28,455		)	—			—
Net cash provided by (used in) financing activities	(2,589		)	(323,600		)	142,361
Net increase (decrease) in cash and cash equivalents	108,203			(40,770		)	85,379
Cash and cash equivalents, beginning of period	116,296			157,066			71,687
Cash and cash equivalents, end of period	$	224,499		$	116,296		$	157,066
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$	85,329		$	84,492		$	77,626
Cash paid (received) for income tax, net of refunds	$	18,184		$	5,498		$	(4,087	)
Non-cash activities:
Capital expenditures included in accrued liabilities	$	6,161		$	—		$	—
Financing activity — payment on long-term debt from issuance of preferred stock	$	—		$	(30,000	)	$	—

The accompanying notes are an integral part of these consolidated financial statements.

F-8

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands, except as noted)

(1) Description and Nature of Business

As used in this report, unless otherwise specified, the terms “Alon,” “we,” “us” or “our” refer to Alon USA Energy, Inc. and its consolidated subsidiaries or to Alon USA Energy, Inc. or an individual subsidiary. The “Partnership,” as used in this report, refers to Alon USA Partners, LP and its subsidiaries.

We are engaged in the business of refining and marketing of petroleum products, primarily in the South Central, Southwestern and Western regions of the United States. Our business consists of three operating segments: (i) refining and marketing, (ii) asphalt and (iii) retail.

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 (the “California refineries”); and a light sweet crude oil refinery located in Krotz Springs, Louisiana. Our refineries have a combined throughput capacity of approximately 214,000 barrels per day (“bpd”). At these refineries, we refine crude oil into products including gasoline, diesel, jet fuel, petrochemicals, feedstocks, asphalts and other petroleum products, which are marketed primarily in the South Central, Southwestern and Western regions of the United States. In 2013, we did not process crude oil at our California refineries.

We own the Big Spring refinery and wholesale marketing operations through the Partnership. We market 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 produced at our 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), 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, 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.

(2) Basis of Presentation and Certain Significant Accounting Policies

(a) Basis of Presentation

The consolidated financial statements include the accounts of Alon USA Energy, Inc. and its subsidiaries. All significant intercompany balances and transactions have been eliminated.

F-9

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(b) Use of Estimates

These consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”), which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(c) Revenue Recognition

Revenues from sales of refined products are earned and realized upon transfer of title to the customer based on the contractual terms of delivery (including payment terms and prices). Generally, title transfers at the refinery or terminal when the refined product is loaded into the common carrier pipelines, trucks or railcars (free on board origin). In some situations, title transfers at the customer’s destination (free on board destination).

We occasionally enter into refined product buy/sell arrangements, which involve linked purchases and sales related to refined product sales contracts entered into to address location, quality or grade requirements. These buy/sell transactions are included on a net basis in sales in the consolidated statements of operations and profits are recognized when the exchanged product is sold.

Revenues from our inventory financing agreements (Note 9) are reported on a gross basis as we are considered a principal in these agreements.

In the ordinary course of business, logistical and refinery production schedules necessitate the occasional sale of crude oil to third parties. All purchases and sales of crude oil are recorded net, in cost of sales in the consolidated statements of operations.

Excise taxes on sales by our retail segment are presented on a gross basis. Supplemental information regarding the amount of such taxes included in revenues are provided in a footnote on the face of the consolidated statements of operations. All other excise taxes are presented on a net basis in the consolidated statements of operations.

(d) Cost Classifications

Refining and marketing cost of sales includes crude oil and other raw materials, inclusive of transportation costs. Asphalt cost of sales includes costs of purchased asphalt, blending materials and transportation costs. Retail cost of sales includes 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, which is presented separately in the consolidated statements of operations.

Direct operating expenses, which relate to our refining and marketing and asphalt segments, include costs associated with the actual operations of our refineries and terminals, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs. Operating costs associated with our crude oil and product pipelines are considered to be transportation costs and are reflected in cost of sales in the consolidated statements of operations.

Selling, general and administrative expenses consist primarily of costs relating to the operations of the convenience stores, including labor, utilities, maintenance and retail corporate overhead costs. Refining and marketing and asphalt segments corporate overhead and marketing expenses are also included in selling, general and administrative expenses.

Interest expense includes interest expense, letters of credit, financing costs associated with crude oil purchases, financing fees, and both the amortization and write-off of original issuance discount and deferred debt issuance costs but excludes capitalized interest.

(e) Cash and Cash Equivalents

All highly-liquid instruments with a maturity of three months or less at the time of purchase are considered to be cash equivalents. Cash equivalents are stated at cost, which approximates market value.

(f) Accounts Receivable

Financial instruments that potentially subject us to concentration of credit risk consist primarily of trade accounts receivables. Credit is extended based on evaluation of the customer’s financial condition and in certain circumstances, collateral, such as letters of credit, prepayments or guarantees, are required, as management deems appropriate. Credit losses are charged to allowance for doubtful accounts when deemed uncollectible. Reserve for bad debts is based on a combination of current sales and specific identification methods.

F-10

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(g) Inventories

Crude oil, refined products and blendstocks for the refining and marketing segment and asphalt for the asphalt segment (including crude oil inventory consigned to others) are stated at the lower of cost or market. Cost is determined under the last-in, first-out (“LIFO”) valuation method. Cost of crude oil, refined products, asphalt and blendstock inventories in excess of market value are charged to cost of sales. Such charges are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. Materials and supplies are stated at average cost. Cost for the retail segment merchandise inventories is determined under the retail inventory method and cost for retail segment fuel inventories is determined under the first-in, first-out (“FIFO”) method.

Crude oil inventory consigned to others represents inventory that was sold to third parties, which we are obligated to repurchase at the end of the respective agreements (Note 9). As a result of this requirement to repurchase inventory, no revenue was recorded on these transactions and the inventory volumes remain valued under the LIFO method.

(h) Hedging Activity

All derivative instruments are recorded in the consolidated balance sheets as either assets or liabilities measured at their fair value. We consider all commodity forwards, futures, swaps and option contracts to be part of our risk management strategy. For commodity derivative contracts not designated as cash flow hedges, the net unrealized gains and losses for changes in fair value are recognized in cost of sales or in other income (loss), net on the consolidated statement of operations.

We selectively designate certain commodity derivative contracts and interest rate derivatives as cash flow hedges. The effective portion of the gains or losses associated with these derivative contracts designated and qualifying as cash flow hedges are initially recorded in accumulated other comprehensive income in the consolidated balance sheet and reclassified into the statement of operations in the period in which the underlying hedged forecasted transaction affects income. The amounts recorded into the consolidated statement of operations for commodity derivative contracts are recognized as cost of sales and the amounts recorded for interest rate derivatives are recognized as interest expense. The ineffective portion of the gains or losses on the derivative contracts, if any, is recognized in the consolidated statement of operations as it is incurred.

Derivative transactions related to our inventory financing agreements have been designated as fair value hedges of inventory. The gain or loss on the derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk, is recognized in earnings in the same period.

(i) Property, Plant and Equipment

The carrying value of property, plant and equipment includes the fair value of the asset retirement obligation and has been reflected in the consolidated balance sheets at cost, net of accumulated depreciation.

Property, plant and equipment, net of salvage value, are depreciated using the straight-line method at rates based on the estimated useful lives for the assets or groups of assets, beginning in the first month of operation following acquisition or completion. We capitalize interest costs associated with major construction projects based on the effective interest rate on aggregate borrowings.

Leasehold improvements are depreciated on the straight-line method over the shorter of the contractual lease terms or the estimated useful lives.

Expenditures for major replacements and additions are capitalized. Refining and marketing segment and asphalt segment expenditures for routine repairs and maintenance costs are charged to direct operating expense as incurred. Retail segment routine repairs and maintenance costs are charged to selling, general and administrative expense as incurred. The applicable costs and accumulated depreciation of assets that are sold, retired, or otherwise disposed of are removed from the accounts and the resulting gain or loss is recognized as a gain or loss on disposition of assets in the consolidated statements of operations.

(j) Impairment of Long-Lived Assets and Assets to be Disposed Of

We review long-lived assets and certain identifiable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of an asset to future net cash flows expected to be generated by the asset. If the carrying value of an asset exceeds its expected future cash flows, an impairment loss is recognized based on the excess of the carrying value of the impaired asset over its fair value. These future cash flows and fair values are estimates based on management’s judgment and assumptions. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs of disposition.

F-11

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(k) Asset Retirement Obligations

The accounting standards established for asset retirement obligations require companies to recognize the liability for the fair value of a legal obligation to perform asset retirement activities that are conditional on a future event, if the amount can be reasonably estimated (Note 12).

We have asset retirement obligations with respect to our refineries due to various legal obligations to clean and/or dispose of these assets at the time they are retired. However, the majority of these assets can be used for extended and indeterminate periods of time provided that they are properly maintained and/or upgraded. It is our practice and intent to continue to maintain these assets and make improvements based on technological advances. When a date or range of dates can reasonably be estimated for the retirement of these assets or any component part of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using established present value techniques.

We also have asset retirement obligations with respect to the removal of underground storage tanks and the removal of brand signage at our owned and leased retail sites. The asset retirement obligation for storage tank removal on leased retail sites is accreted over the expected life of the underground storage tank, which approximates the average retail site lease term.

(l) Turnarounds and Chemical Catalysts Costs

We record the cost of planned major refinery maintenance, referred to as turnarounds, and chemical catalyst used in the refinery process units, which are typically replaced in conjunction with planned turnarounds, in “Other assets” in the consolidated balance sheets. Turnaround and catalyst costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround. The amortization of deferred turnaround and chemical catalyst costs are presented in depreciation and amortization in the consolidated statements of operations.

(m) Income Taxes

We account for income taxes under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

(n) Stock-Based Compensation

Our stock-based compensation plan includes granting of awards in the form of options to purchase common stock, Stock Appreciation Rights (“SARs”), restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses to our directors, officers and key employees. We use the grant date fair value based method for calculating and accounting for stock-based compensation. Expenses related to stock-based compensation are included in selling, general and administrative expenses in our consolidated statements of operations (Note 16).

(o) Environmental Expenditures

Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Environmental liabilities represent the estimated costs to investigate and remediate contamination at our properties. This estimate is based on internal and third-party assessments of the extent of the contaminations, the selected remediation technology and review of applicable environmental regulations.

Costs of future expenditures for environmental remediation obligations are not discounted to their present value unless payments are fixed or reliably determinable. Recoveries of environmental remediation costs from other parties are recorded as assets when the receipt is deemed probable (Note 20). Estimates are updated to reflect changes in factual information, available technology or applicable laws and regulations.

Substantially all amounts accrued are expected to be paid out over the next 15 years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

F-12

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(p) Earnings Per Share

We compute basic earnings per share by dividing net income available to common stockholders by the weighted average number of participating common shares outstanding during the reporting period. Diluted earnings per share are calculated to give effect to all potentially dilutive common shares that were outstanding during the period (Note 18).

(q) Other Comprehensive Income

Comprehensive income consists of net income and other gains and losses affecting stockholders’ equity that, under U.S. GAAP, are excluded from net income, such as defined postretirement benefit plan adjustments and gains and losses related to certain derivative instruments designated in qualifying hedging relationships. The balance in accumulated other comprehensive loss, net of tax reported in the consolidated balance sheets consists of defined postretirement benefit plans and the fair value of commodity derivative contract adjustments.

(r) Postretirement Benefits

We recognize the underfunded status of our defined pension and postretirement plans as a liability. Changes in the funded status of our defined pension and postretirement plans are recognized in other comprehensive income in the period the changes occur. The funded status represents the difference between the projected benefit obligation and the fair value of the plan assets. The projected benefit obligation is the present value of benefits earned to date by plan participants, including the effect of assumed future salary increases. Plan assets are measured at fair value. We use a December 31 measurement date for plan assets and obligations for all of our plans.

(s) Commitments and Contingencies

Liabilities for loss contingencies, arising from claims, assessments, litigation, fines and penalties and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recorded as assets, and are not offset against the related environmental liability.

(t) Goodwill and Intangibles

Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over 1 to 40 years. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. We use December 31 of each year as the valuation date for annual impairment testing purposes.

(3) Alon USA Partners, LP

The Partnership is a publicly traded limited partnership that was formed to own the assets and operations of the Big Spring refinery and associated wholesale marketing operations. On November 26, 2012, the Partnership completed its initial public offering (NYSE: ALDW) 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 limited partner interests in the Partnership not owned by us are reflected in the results of operations in net income attributable to non-controlling interest and in our balance sheet in non-controlling interest in subsidiaries. The Partnership is consolidated within the refining and marketing segment.

We have agreements with the Partnership which establish fees for certain administrative and operational services provided by us and our subsidiaries to the Partnership, provide certain indemnification obligations and other matters and establish terms for the supply of products by the Partnership to us.

Partnership Distributions

The Partnership has adopted a policy pursuant to which it will distribute all of the available cash it generates each quarter, as defined in the partnership agreement and subject to the approval of the board of directors of the General Partner. The per unit amount of available cash to be distributed each quarter, if any, will be distributed within 60 days following the end of such quarter.

F-13

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

During the year ended December 31, 2013, the Partnership paid cash distributions of $172,506, or $2.76 per unit. The total cash distribution paid to non-affiliated common unitholders was $31,746. As the Partnership was formed in November 2012, cash distributions were not paid during the years ended December 31, 2012 and 2011.

(4) Segment Data

Our revenues are derived from three operating segments: (i) refining and marketing, (ii) asphalt and (iii) retail. The reportable operating segments are strategic business units that offer different products and services. The segments are managed separately as each segment requires unique technology, marketing strategies and distinct operational emphasis. Each operating segment’s performance is evaluated primarily based on operating income.

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

Operating income (loss) for each segment consists of net sales less cost of sales, direct operating expenses, selling, general and administrative expenses, depreciation and amortization and gain (loss) on disposition of assets. Intersegment sales are intended to approximate wholesale market prices. Consolidated totals presented are after intersegment eliminations.

Operations that are not included in any of the three segments are included in the corporate category. These operations consist primarily of corporate headquarters operating and depreciation expenses.

Total assets of each segment consist of net property, plant and equipment, inventories, cash and cash equivalents, accounts and other receivables and other assets directly associated with the segment’s operations. Corporate assets consist primarily of corporate headquarters information technology and administrative equipment.

Segment data as of and for the years ended December 31, 2013, 2012 and 2011 are presented below:

	Refining and Marketing		Asphalt			Retail			Corporate			Consolidated Total
Year Ended December 31, 2013
Net sales to external customers	$	5,489,745	$	612,443		$	944,193		$	—		$	7,046,381
Intersegment sales/purchases	600,943		(86,089		)	(514,854		)	—			—
Depreciation and amortization	105,597		6,398			10,826			2,673			125,494
Operating income (loss)	133,020		(4,097		)	23,904			(3,394		)	149,433
Total assets	1,887,981		137,417			197,966			21,776			2,245,140
Turnaround, chemical catalyst and capital expenditures	48,889		9,425			17,935			881			77,130

	Refining and Marketing		Asphalt			Retail			Corporate			Consolidated Total
Year Ended December 31, 2012
Net sales to external customers	$	6,505,927	$	603,896		$	907,918		$	—		$	8,017,741
Intersegment sales/purchases	736,008		(244,010		)	(491,998		)	—			—
Depreciation and amortization	103,638		5,866			10,298			2,127			121,929
Operating income (loss)	254,372		(3,728		)	21,918			(3,087		)	269,475
Total assets	1,876,326		123,165			202,033			22,050			2,223,574
Turnaround, chemical catalyst and capital expenditures	79,572		9,420			14,141			2,228			105,361

F-14

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

	Refining and Marketing		Asphalt			Retail			Corporate			Consolidated Total
Year Ended December 31, 2011
Net sales to external customers	$	5,798,238	$	554,549		$	833,470		$	—		$	7,186,257
Intersegment sales/purchases	760,387		(314,294		)	(446,093		)	—			—
Depreciation and amortization	90,701		6,376			14,728			1,925			113,730
Operating income (loss)	188,955		(24,519		)	19,762			(2,677		)	181,521
Total assets	2,010,309		116,936			188,925			14,212			2,330,382
Turnaround, chemical catalyst and capital expenditures	101,756		3,225			15,838			1,540			122,359

(5) Fair Value

We determine fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We classify financial assets and financial liabilities into the following fair value hierarchy:

• Level 1 -     valued based on quoted prices in active markets for identical assets and liabilities;

• Level 2 -     valued based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability; and

• Level 3 -     valued based on unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

As required, we utilize valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy. We generally apply the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

The carrying amounts of our cash and cash equivalents, receivables, payables and accrued liabilities approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of long-term debt approximate fair value. Derivative instruments are carried at fair value, which are based on quoted market prices. Derivative instruments and the Renewable Identification Numbers (“RINs”) obligation are our only assets and liabilities measured at fair value on a recurring basis.

The RINs obligation represents the period-end deficit for the purchase of RINs to satisfy the requirement to blend biofuels into the products we have produced. Our RINs obligation is based on the RINs deficit and the market price of those RINs as of the balance sheet date. The RINs obligation is categorized as Level 2 of the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.

F-15

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the consolidated balance sheets as of December 31, 2013 and 2012:

	Level 1		Level 2		Level 3		Consolidated Total
As of December 31, 2013
Assets:
Commodity contracts (futures and forwards)	$	335	$	—	$	—	$	335
Liabilities:
Commodity contracts (swaps)	—		15,328		11,569		26,897
Fair value hedges	—		3,339		—		3,339
RINs obligation	—		334		—		334
As of December 31, 2012
Assets:
Commodity contracts (futures and forwards)	$	2,072	$	—	$	—	$	2,072
Commodity contracts (swaps)	—		1,514		—		1,514
Liabilities:
Fair value hedges	—		1,720		—		1,720

Level 3 Financial Instruments

We have commodity price swap contracts that relate to forecasted sales of jet fuel and forecasted purchases of crude oil for which quoted forward market prices are not readily available. The forward rate used to value these price swaps was derived using a projected forward rate using quoted market rates for similar products, adjusted for product grade differentials, a Level 3 input.

The following table presents the changes in fair value of our Level 3 assets and liabilities (all related to commodity price swap contracts) for the year ended December 31, 2013:

	Year Ended
	December 31, 2013
Balance at beginning of period	$	—
Change in fair value of Level 3 trades open at the beginning of the period	—
Fair value of trades entered into during the period - Recognized in other comprehensive income	(11,569		)
Fair value of reclassification from Level 3 to Level 2	—
Settlement value of contractual maturities - Recognized in cost of sales	—
Balance at end of period	$	(11,569	)

A hypothetical change of 10% to the estimated future cash flows attributable to our Level 3 commodity price swaps would result in an estimated fair value change of $1,157.

(6) Derivative Financial Instruments

Mark to Market

Commodity Derivatives. We selectively utilize crude oil and refined product commodity derivative contracts to reduce the risk associated with potential price changes on committed obligations. We do not speculate using derivative instruments. Credit risk on our derivative instruments is mitigated by transacting with counterparties meeting established collateral and credit criteria.

Fair Value Hedges

Fair value hedges are used to hedge price volatility of certain refining inventories and firm commitments to purchase inventories. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk, is recognized in earnings in the same period.

F-16

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

As of December 31, 2013, we have accounted for certain commodity contracts as fair value hedges with contract purchase volumes of 703 thousand barrels of crude oil with remaining contract terms through May 2019.

Cash Flow Hedges

To designate a derivative as a cash flow hedge, we document at the inception of the hedge the assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. If, during the term of the derivative, the hedge is determined to be no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings when the underlying transactions occur.

Commodity Derivatives. As of December 31, 2013, we have accounted for certain commodity swap contracts as cash flow hedges with contract purchase volumes of 5,760 thousand barrels of crude and contract sales volumes of 5,760 thousand barrels of refined products with the longest remaining contract term of twenty-four months. Related to these transactions in Other Comprehensive Income (“OCI”), we recognized unrealized losses of $31,496 and unrealized gains of $1,514 for the years ended December 31, 2013 and 2012, respectively. There were no amounts reclassified from OCI into cost of sales as a result of the discontinuance of cash flow hedge accounting.

In November 2013, we elected to de-designate certain commodity swap contracts that were previously designated as cash flow hedges. Consequently, hedge accounting was discontinued prospectively for the commodity swap contracts and all changes in fair value were recorded in cost of sales in the consolidated statements of operations. As of December 31, 2013, we had unrealized losses of $29,982 classified in OCI that related to the application of hedge accounting prior to de-designation that will be recorded into earnings as the forecasted transactions occur during the year ended December 31, 2014. The commodity derivative contracts were subsequently re-designated as cash flow hedges as of December 31, 2013 on a product basis.

For the year ended December 31, 2013, there was $1,879 of hedge ineffectiveness recognized in cost of sales. For the year ended December 31, 2012, there was no hedge ineffectiveness recognized in income. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.

Interest Rate Derivatives. We selectively utilize interest rate related derivative instruments to manage our exposure to floating-rate debt instruments. We periodically use interest rate swap agreements to manage our floating to fixed rate position by converting certain floating-rate debt to fixed-rate debt. As of December 31, 2013 and 2012, we did not have any outstanding interest rate swap agreements.

For cash flow hedges, gains and losses reported in equity are reclassified into interest expense when the forecasted transaction affects income. During the years ended December 31, 2012 and 2011, we recognized in OCI unrealized gains of $4,197 and $3,304, respectively, for the fair value measurement of the interest rate swap agreements. During the year ended December 31, 2012, the remaining unrealized balance was reclassified from equity into interest expense.

F-17

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

The following table presents the effect of derivative instruments on the consolidated statements of financial position:

	As of December 31, 2013
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	1,533	Accrued liabilities	$	(1,198	)
Total derivatives not designated as hedging instruments		$	1,533		$	(1,198	)
Derivatives designated as hedging instruments:
Commodity contracts (swaps)	Accounts receivable	$	—	Accrued liabilities	$	(15,328	)
Commodity contracts (swaps)		—		Other non-current liabilities	(11,569		)
Fair value hedges		—		Other non-current liabilities	(3,339		)
Total derivatives designated as hedging instruments		—			(30,236		)
Total derivatives		$	1,533		$	(31,434	)

	As of December 31, 2012
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	2,743	Accrued liabilities	$	(671	)
Total derivatives not designated as hedging instruments		$	2,743		$	(671	)
Derivatives designated as hedging instruments:
Commodity contracts (swaps)	Accounts receivable	$	2,287	Accrued liabilities	$	(773	)
Fair value hedges		—		Other non-current liabilities	(1,720		)
Total derivatives designated as hedging instruments		2,287			(2,493		)
Total derivatives		$	5,030		$	(3,164	)

F-18

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

The following tables present the effect of derivative instruments on the consolidated statements of operations and accumulated other comprehensive income:

Derivatives designated as hedging instruments:

Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				Gain (Loss) Reclassified from Accumulated OCI into Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
				Location	Amount			Location	Amount
For the Year Ended December 31, 2013
Commodity contracts (swaps)	$	(31,496	)	Cost of sales	$	23,900		Cost of sales	$	(1,879	)
Total derivatives	$	(31,496	)		$	23,900			$	(1,879	)
For the Year Ended December 31, 2012
Commodity contracts (swaps)	$	1,514		Cost of sales	$	(76,097	)		$	—
Interest rate swap	4,197			Interest expense	(4,065		)		—
Total derivatives	$	5,711			$	(80,162	)		$	—
For the Year Ended December 31, 2011
Interest rate swap	$	3,304		Interest expense	$	(4,074	)		$	—
Total derivatives	$	3,304			$	(4,074	)		$	—

Derivatives in fair value hedging relationships:

		Gain (Loss) Recognized in Income
		Year Ended December 31,
	Location	2013			2012			2011
Fair value hedges	Cost of sales	$	(1,619	)	$	(1,720	)	$	—
Total derivatives		$	(1,619	)	$	(1,720	)	$	—

Derivatives not designated as hedging instruments:

		Gain (Loss) Recognized in Income
		Year Ended December 31,
	Location	2013		2012			2011
Commodity contracts (futures & forwards)	Cost of sales	$	8,359	$	15,640		$	3,032
Commodity contracts (swaps)	Cost of sales	4,964		(54,011		)	30,040
Commodity contracts (call options)	Other income (loss), net	—		(7,297		)	(36,280		)
Total derivatives		$	13,323	$	(45,668	)	$	(3,208	)

F-19

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

Offsetting Assets and Liabilities

Our derivative financial instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives and we offset the fair value amounts recorded for derivative instruments to the extent possible under these agreements on our consolidated balance sheets.

The following table presents offsetting information regarding our derivatives by type of transaction as of December 31, 2013 and 2012:

	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset in the Statement of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Statement of Financial Position			Gross Amounts Not offset in the Statement of Financial Position					Net Amount
										Financial Instruments			Cash Collateral Pledged
As of December 31, 2013
Commodity Derivative Assets:
Futures & forwards	$	2,287		$	(754	)	$	1,533		$	(1,198	)	$	—	$	335
Commodity Derivative Liabilities:
Futures & forwards	$	(1,952	)	$	754		$	(1,198	)	$	1,198		$	—	$	—
Swaps	(26,897		)	—			(26,897		)	—			—		(26,897		)
Fair value hedges	(3,339		)	—			(3,339		)	—			—		(3,339		)
As of December 31, 2012
Commodity Derivative Assets:
Futures & forwards	$	7,907		$	(5,164	)	$	2,743		$	(671	)	$	—	$	2,072
Swaps	4,756			(2,469		)	2,287			(773		)	—		1,514
Commodity Derivative Liabilities:
Futures & forwards	$	(5,835	)	$	5,164		$	(671	)	$	671		$	—	$	—
Swaps	(3,242		)	2,469			(773		)	773			—		—
Fair value hedges	(1,720		)	—			(1,720		)	—			—		(1,720		)

Compliance Program Market Risk

We are obligated by government regulations to blend a certain percentage of biofuels into the products we produce that are consumed in the U.S. We purchase biofuels from third parties and blend those biofuels into our products, and each gallon of biofuel purchased includes a RIN. To the degree we are unable to blend biofuels at the required percentage, a RINs deficit is generated and we must acquire that number of RINs by the annual reporting deadline in order to remain in compliance with applicable regulations.

We are exposed to market risk related to the volatility in the price of credits needed to comply with these governmental and regulatory programs. We manage this risk by purchasing biofuel credits when prices are deemed favorable utilizing fixed price purchase contracts. Some of these contracts are derivative instruments; however, we elect the normal purchase and sale exception and do not record these contracts at their fair values.

The cost of meeting our obligations under these compliance programs was $14,917 for the year ended December 31, 2013. These amounts are reflected in cost of sales. We were not subject to the Renewable Fuel Standards 2 requirements for the years ended December 31, 2012 and 2011.

(7) Accounts and Other Receivables

Financial instruments that potentially subject us to concentration of credit risk consist primarily of trade accounts receivables. Credit risk is minimized as a result of the ongoing credit assessment of our customers and a lack of concentration in our customer base. We perform ongoing credit evaluations of our customers and require letters of credit, prepayments or other collateral or guarantees as management deems appropriate. J. Aron & Company (“J. Aron”) accounted for more than 10% of our net sales for the year ended December 31, 2013. Valero Energy Corporation (“Valero”) and J. Aron each accounted for more than 10% of our net sales for the years ended December 31, 2012 and 2011. The allowance for doubtful accounts is reflected as a reduction of accounts and other receivables in the consolidated balance sheets.

F-20

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

Accounts and other receivables consisted of the following:

	As of December 31,
	2013		2012
Trade accounts receivable	$	182,190	$	162,424
Other receivables	18,669		21,791
Total accounts and other receivables	$	200,859	$	184,215

The following table sets forth the allowance for doubtful accounts for the years ended December 31, 2013, 2012 and 2011:

	Balance at Beginning of Period		Additions Charged to Expense	Deductions (1)		Balance at End of Period
2013	$	583	175	(297	)	$	461
2012	$	437	146	—		$	583
2011	$	22,321	—	(21,884	)	$	437

________

(1) Amounts written off are net of recoveries. The 2011 deduction is related to the write-off of the SEMGroup, LP bankruptcy amounts charged to expense in 2009 and 2008.

(8) Inventories

Carrying value of inventories consisted of the following:

	As of December 31,
	2013		2012
Crude oil, refined products, asphalt and blendstocks	$	34,326	$	40,068
Crude oil inventory consigned to others	44,081		91,876
Materials and supplies	21,685		21,919
Store merchandise	20,526		22,139
Store fuel	8,152		7,917
Total inventories	$	128,770	$	183,919

Reductions of inventory volumes during 2013, 2012 and 2011 resulted in a liquidation of LIFO inventory layers. The liquidation increased cost of sales by $1,455 during 2013 and decreased cost of sales by $13,572 and $59,332 during 2012 and 2011, respectively.

Market values of crude oil, refined products, asphalt and blendstock inventories exceeded LIFO costs by $61,199 and $58,213 at December 31, 2013 and 2012, respectively.

(9) Inventory Financing Agreements

Alon has entered into Supply and Offtake Agreements and other associated agreements (together the “Supply and Offtake Agreements”) with J. Aron to support the operations of our Big Spring, Krotz Springs and California refineries and most of our asphalt terminals. Pursuant to the Supply and Offtake Agreements, (i) J. Aron agreed to sell to us, and we agreed to buy from J. Aron, at market prices, crude oil for processing at the refineries and (ii) we agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at the refineries.

The Supply and Offtake Agreements also provided for the sale, at market prices, of our crude oil and certain refined product inventories to J. Aron, the lease to J. Aron of crude oil and refined product storage facilities, and to identify prospective purchasers of refined products on J. Aron’s behalf. The Supply and Offtake Agreements were amended in February 2013 and have initial terms that expire in May 2019. J. Aron may elect to terminate the Supply and Offtake Agreements prior to the expiration of the initial term in May 2016 and upon each anniversary thereof, on six months prior notice. We may elect to terminate in May 2018 on six months prior notice.

Following expiration or termination of the Supply and Offtake Agreements, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the leased storage facilities at market prices at that time.

F-21

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

In association with the Supply and Offtake Agreement at the Krotz Springs refinery, we entered into a secured Credit Agreement (the “Krotz Springs Standby LC Facility”) by and between Alon, as Borrower, and Goldman Sachs Bank USA, as Issuing Bank. The Krotz Springs Standby LC Facility provides for up to $200,000 of letters of credit to be issued to J. Aron. Obligations under the Krotz Springs Standby LC Facility are secured by a first priority lien on the existing and future accounts receivable and inventory of Alon Refining Krotz Springs, Inc. and its subsidiaries (“ARKS”), our wholly owned subsidiary. The Krotz Springs Standby LC Facility includes customary events of default and restrictions on the activities of ARKS. The Krotz Springs Standby LC Facility contains no maintenance financial covenants. At this time there is no further availability under the Standby LC Facility. In August 2013, we amended the Krotz Springs Standby LC Facility to extend the maturity date to July 2016.

At December 31, 2013 and 2012, we had net current payables to J. Aron for purchases of $16,917 and $58,501, respectively, non-current liabilities related to the original financing of $67,889 and $115,955, respectively, and a consignment inventory receivable representing a deposit paid to J. Aron of $26,179 and $26,179, respectively.

Additionally, we had net current payables of $539 and net current receivables of $5,878 at December 31, 2013 and 2012, respectively, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.

(10) Property, Plant and Equipment, Net

Property, plant and equipment, net consisted of the following:

	As of December 31,
	2013			2012
Refining facilities	$	1,804,445		$	1,781,701
Pipelines and terminals	43,445			43,445
Retail	184,858			164,998
Other	15,326			14,296
Property, plant and equipment, gross	2,048,074			2,004,440
Accumulated depreciation	(618,732		)	(511,947		)
Property, plant and equipment, net	$	1,429,342		$	1,492,493

The useful lives of depreciable assets used to determine depreciation expense were as follows:

Refining facilities	3 – 20 years; average 18 years
Pipelines and terminals	5 – 25 years; average 23 years
Retail	5 – 40 years; average 8 years
Other	3 – 15 years; average 5 years

Capitalized interest for the years ended December 31, 2013, 2012 and 2011 was $4,321, $2,640 and $2,273, respectively. Depreciation expense for the years ended December 31, 2013, 2012 and 2011 was $107,845, $103,134 and $94,567, respectively.

F-22

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(11) Other Assets, Net

Other assets, net consisted of the following:

	As of December 31,
	2013		2012
Deferred turnaround and chemical catalyst cost	$	12,271	$	15,978
Environmental receivables	4,273		13,563
Deferred debt issuance costs	12,602		14,705
Intangible assets, net	7,497		9,384
Receivable from supply agreements	26,179		26,179
Other, net	19,388		14,849
Total other assets	$	82,210	$	94,658

Debt issuance costs are amortized over the term of the related debt using the effective interest method. Amortization of debt issuance costs was $4,496, $6,296, and $6,493 for the years ended December 31, 2013, 2012 and 2011, respectively, and is recorded as interest expense in the consolidated statements of operations. Additionally, we wrote off unamortized debt issuance costs of $1,871 and $8,826 for the years ended December 31, 2013 and 2012, respectively, related to the prepayment of debt (Note 14).

(12) Accrued Liabilities and Other Non-Current Liabilities

Accrued liabilities and other non-current liabilities consisted of the following:

	As of December 31,
	2013		2012
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes	$	37,645	$	37,888
Employee costs	13,793		18,995
Commodity contracts	16,526		1,444
Accrued finance charges	8,733		11,633
Environmental accrual (Note 20)	12,898		6,730
Other	31,263		25,889
Total accrued liabilities	$	120,858	$	102,579
Other Non-Current Liabilities:
Pension and other postemployment benefit liabilities, net	$	40,351	$	58,270
Environmental accrual (Note 20)	45,484		54,672
Asset retirement obligations	12,468		11,867
Consignment inventory obligations	67,889		115,955
Commodity contracts	11,569		—
Other	11,713		14,182
Total other non-current liabilities	$	189,474	$	254,946

The following table summarizes the activity relating to the asset retirement obligations for the years ended December 31, 2013 and 2012:

	As of December 31,
	2013		2012
Balance at beginning of year	$	11,867	$	11,442
Accretion expense	592		501
Retirements	—		(98		)
Additions	9		22
Balance at end of year	$	12,468	$	11,867

F-23

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(13) Postretirement Benefits

(a) Retirement Plans

We have four defined benefit pension plans covering substantially all of our employees, excluding employees of our retail segment. The benefits are based on years of service and the employee’s final average monthly compensation. Our funding policy is to contribute annually no less than the minimum required nor more than the maximum amount that can be deducted for federal income tax purposes. Contributions are intended to provide not only for benefits attributed to service to date but also for those benefits expected to be earned in the future.

Financial information related to our pension plans is presented below.

	Pension Benefits
	2013			2012
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	111,531		$	88,244
Service cost	3,962			3,577
Interest cost	4,408			4,128
Actuarial (gain) loss	(10,890		)	18,018
Benefits paid	(2,857		)	(2,436		)
Curtailment	(126		)	—
Projected benefit obligations at end of year	$	106,028		$	111,531
Change in plan assets:
Fair value of plan assets at beginning of year	$	57,630		$	46,142
Actual gain on plan assets	12,978			7,128
Employer contribution	6,167			6,796
Benefits paid	(2,857		)	(2,436		)
Fair value of plan assets at end of year	$	73,918		$	57,630
Reconciliation of funded status:
Fair value of plan assets at end of year	$	73,918		$	57,630
Less projected benefit obligations at end of year	106,028			111,531
Under-funded status at end of year	$	(32,110	)	$	(53,901	)

The pre-tax amounts related to the defined benefit plans recognized in the consolidated balance sheets as of December 31, 2013 and 2012 were as follows:

	Pension Benefits
	2013			2012
Amounts recognized in the consolidated balance sheets:
Pension benefit liability	$	(32,110	)	$	(53,901	)

The pre-tax amounts in accumulated other comprehensive income (loss) as of December 31, 2013 and 2012 that have not yet been recognized as components of net periodic benefit cost were as follows:

	Pension Benefits
	2013			2012
Net actuarial loss	$	(31,719	)	$	(55,156	)
Prior service credit	327			378
Total	$	(31,392	)	$	(54,778	)

F-24

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

The following amounts included in accumulated other comprehensive income (loss) as of December 31, 2013 are expected to be recognized as components of net periodic benefit cost during the year ending December 31, 2014:

	Pension Benefits
Amortization of prior service credit	$	(51	)
Amortization of loss	2,432
Total	$	2,381

As of December 31, 2013 and 2012, the accumulated benefit obligation for each of our pension plans was in excess of the fair value of plan assets. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans were as follows:

	As of December 31,
	2013		2012
Projected benefit obligation	$	106,028	$	111,531
Accumulated benefit obligation	96,130		99,114
Fair value of plan assets	73,918		57,630

The weighted-average assumptions used to determine benefit obligations at December 31, 2013, 2012 and 2011 were as follows:

	Pension Benefits
	2013		2012		2011
Discount rate	4.75	%	4.00	%	4.75	%
Rate of compensation increase	3.00	%	3.00	%	1.50	%

The discount rate used reflects the expected future cash flow based on our funding valuation assumptions and participant data as of the beginning of the plan year. The expected future cash flow is discounted by the Principal Pension Discount Yield Curve for the fiscal year end because it has been specifically designed to help pension funds comply with statutory funding guidelines.

The weighted-average assumptions used to determine net periodic benefit costs for the years ended December 31, 2013, 2012 and 2011 were as follows:

	Pension Benefits
	2013		2012		2011
Discount rate	4.00	%	4.75	%	5.75	%
Expected return on plan assets	8.60	%	8.60	%	8.25	%
Rate of compensation increase	3.00	%	1.50	%	2.50	%

Our overall expected long-term rate of return on assets is 8.6%. The expected long-term rate of return is based on the portfolio as a whole and not on the sum of the returns on individual asset categories. The components of net periodic benefit cost for the years and periods were as follows:

	Pension Benefits
	Year Ended December 31,
	2013			2012			2011
Components of net periodic benefit cost:
Service cost	$	3,962		$	3,577		$	4,007
Interest cost	4,408			4,128			4,139
Amortization of prior service credit	(51		)	(51		)	(58		)
Expected return on plan assets	(4,628		)	(4,305		)	(3,731		)
Recognized net actuarial loss	4,071			2,633			1,849
Net periodic benefit cost	$	7,762		$	5,982		$	6,206

F-25

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

Plan Assets

The weighted-average asset allocation of our pension benefits at December 31, 2013 and 2012 was as follows:

	Pension Benefits
	Plan Assets
	2013		2012
Asset Category:
Equity securities	81.0	%	78.9	%
Debt securities	9.7	%	10.6	%
Real estate investment trust	9.3	%	10.5	%
Total	100.0	%	100.0	%

The fair value of our pension assets by category as of December 31, 2013 and 2012 were as follows:

	Quoted Prices in Active Markets For Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Consolidated Total
Year Ended December 31, 2013
Equity securities:
U.S companies	$	48,530	$	—	$	—	$	48,530
International companies	11,346		—		—		11,346
Debt securities:
Preferred securities	3,136		—		—		3,136
Bond & mortgage backed securities	—		4,049		—		4,049
Real estate securities	6,857		—		—		6,857
Total	$	69,869	$	4,049	$	—	$	73,918
Year Ended December 31, 2012
Equity securities:
U.S companies	$	36,292	$	—	$	—	$	36,292
International companies	9,157		—		—		9,157
Debt securities:
Preferred securities	3,085		—		—		3,085
Bond & mortgage backed securities	—		3,073		—		3,073
Real estate securities	6,023		—		—		6,023
Total	$	54,557	$	3,073	$	—	$	57,630

The investment policies and strategies for the assets of our pension benefits is to, over a five year period, provide returns in excess of the benchmark. The portfolio is expected to earn long-term returns from capital appreciation and a stable stream of current income. This approach recognizes that assets are exposed to price risk and the market value of the plans’ assets may fluctuate from year to year. Risk tolerance is determined based on our specific risk management policies. In line with the investment return objective and risk parameters, the plans’ mix of assets includes a diversified portfolio of equity, fixed-income and real estate investments. Equity investments include domestic and international stocks of various sizes of capitalization. The asset allocation of the plan is reviewed on at least an annual basis.

Cash Flows

We contributed $6,167 and $6,796 to the pension plan for the years ended December 31, 2013 and 2012, respectively, and expect to contribute $7,326 to the pension plan in 2014. There were no employee contributions to the plans.

The benefits expected to be paid in each year 2014 – 2018 are $3,556; $4,355; $4,216; $4,490 and $4,750, respectively. The aggregate benefits expected to be paid in the five years from 2019 – 2023 are $29,240. The expected benefits are based on the same assumptions used to measure our benefit obligation at December 31, 2013 and include estimated future employee service.

F-26

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

401(k) Savings Plans

We sponsor a 401(k) savings plan that is available to all employees, excluding employees of our retail segment. We match 100% of individual participant contributions up to 3% of compensation. In 2012, we revised our 401(k) savings plan that is available to certain employees represented by a union at our Big Spring refinery, in which we match individual participant contributions up to 8% of compensation. For the years ended December 31, 2013 and 2012, our contributions were $2,840 and $2,289, respectively.

We also sponsor a 401(k) savings plan that is available to the employees of our retail segment. Retail employees may contribute up to 50% of their pay after completing three months of service. We match from 1% to 4.5% of employee compensation. For the years ended December 31, 2013 and 2012, our contributions were $959 and $819, respectively.

(b) Postretirement Medical Plan

In addition to providing pension benefits, we adopted an unfunded postretirement medical plan covering certain health care and life insurance benefits (other benefits) for active and certain retired employees who meet eligibility requirements in the plan documents. The health care benefits in excess of certain limits are insured. The accrued benefit liability related to this plan reflected in the consolidated balance sheets was $8,941 and $5,068 at December 31, 2013 and 2012, respectively.

As of December 31, 2013, the total accumulated postretirement benefit obligation under the postretirement medical plan was $8,941.

(14) Indebtedness

Debt consisted of the following:

	As of December 31,
	2013		2012
Term loan credit facility	$	244,322	$	246,311
Revolving credit facility	100,000		49,000
Senior secured notes	73,706		211,573
Convertible senior notes	121,090		—
Retail credit facilities	73,130		80,133
Total debt	612,248		587,017
Less: Current portion	83,174		9,504
Total long-term debt	$	529,074	$	577,513

(a) Alon USA Energy, Inc. Credit Facilities

Convertible Senior Notes (share values in dollars).In September 2013, we completed an offering of 3.00% unsecured convertible senior notes (the “Convertible Notes”) in aggregate principal amount of $150,000, which mature in September 2018. Interest on the Convertible Notes is payable semiannually in arrears on March 15 and September 15 of each year, beginning on March 15, 2014. The Convertible Notes are not redeemable at our option prior to maturity. Under the terms of the Convertible Notes, the holders of the Convertible Notes cannot require us to repurchase all or part of the notes except for instances of a fundamental change, as defined in the indenture.

The holders of the Convertible Notes may convert at any time after June 15, 2018 if our common stock is above approximately $14.79 per share. Prior to June 15, 2018 and after December 31, 2013, holders may convert if our common stock is above approximately $19.22 per share, as defined in the indenture. The Convertible Notes may be converted into shares of our common stock, into cash, or into a combination of cash and shares of common stock, at our election. Our current intent is to settle conversions of each $1 (in thousands) principal amount of the Convertible Notes through cash payments, with any excess of this amount to be settled by a combination of cash and shares of our common stock.

F-27

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

The Convertible Notes were issued at an offering price of 100% and we received gross proceeds of $150,000 (before fees and expenses related to the offering). The Convertible Notes had an initial conversion rate of 67.627 shares of our common stock per each $1 (in thousands) principal amount of the Convertible Notes and is equivalent to an initial conversion price of approximately $14.79 per share, which represents a conversion premium of 32.5% on our last reported common stock price of $11.16 per share on the date of the Convertible Notes offering. The conversion rate is subject to adjustment upon the occurrence of certain events, but will not be adjusted for any accrued and unpaid interest. The Convertible Notes do not contain any maintenance financial covenants.

We used $15,225 of the proceeds to fund the cost of entering into convertible note hedge transactions (after such cost was partially offset by the proceeds we received from entering into warrant transactions) described below. In October 2013, we used the remaining net proceeds from the Convertible Notes offering, along with cash on hand, to redeem $140,000 of the outstanding principal balance on the 13.50% ARKS senior secured notes.

In accordance with ASC 470-20, Debt - Debt with Conversion and Other Options, we separated the $150,000 principal amount of the Convertible Notes between the liability component and the equity component (i.e. the embedded conversion feature). The fair value of the liability component was calculated using a discount rate of an identical unsecured instrument without a conversion feature. Based on this borrowing rate, the fair value of the liability component of the Convertible Notes on the issuance date was $119,635, with a corresponding debt discount of $30,365, to be amortized at an effective interest rate of 8.15% over the term of the Convertible Notes. The carrying amount of the embedded conversion feature was determined to be $30,365, by deducting the fair value of the liability component from the $150,000 principal amount of the Convertible Notes. The embedded conversion feature was recorded to additional paid-in capital because this financial instrument could be settled in our common stock and does not meet the definition of a derivative instrument. Additionally, $4,933 of transaction costs were allocated on a proportionate basis between other assets and additional paid-in capital in the consolidated balance sheets.

Interest expense on the Convertible Notes’ contractual coupon rates for the year ended December 31, 2013 was $1,313. The amount charged to interest expense for amortization of the original issuance discount on the Convertible Notes for the year ended December 31, 2013 was $1,455.

As of December 31, 2013, the if-converted value of the Convertible Notes exceeded the outstanding principal by $17,783.

The principal balance, unamortized discount and net carrying amount of the liability and equity components of the Convertible Notes as of December 31, 2013 are as follows:

	As of December 31,
	2013
Equity component, pretax (1)	$	30,365
Convertible Notes:
Principal balance	150,000
Less: Unamortized discount	28,910
Convertible Notes, net	$	121,090

_______________________

(1)A deferred tax liability of $11,171 was recognized related to the issuance of the Convertible Notes.

Convertible Note Hedge Transactions

In connection with the Convertible Notes offering, we also entered into convertible note hedge transactions with respect to our common stock (the “Purchased Options”) with the initial purchasers of the Convertible Notes (the “Hedge Counterparties”). We paid an aggregate amount of $28,455 to the Hedge Counterparties for the Purchased Options. The Purchased Options, with a strike price of $14.79 per share of our common stock, cover 10,144,050 shares of our common stock, subject to customary anti-dilution adjustments, that initially underlie the Convertible Notes sold in the offering. The Purchased Options will expire in September 2018.

The Purchased Options are intended to reduce the potential dilution with respect to our common stock upon conversion of the Convertible Notes as well as offset any potential cash payments we are required to make in excess of the principal amount upon any conversion of the notes. The Purchased Options have been included in additional paid-in capital on the consolidated balance sheets, net of deferred tax assets of $10,468.

F-28

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

The Purchased Options are separate transactions and are not part of the terms of the Convertible Notes and are excluded from classification as a derivative as the amount could be settled in our stock. Holders of the Convertible Notes do not have any rights with respect to the Purchased Options.

Warrant Transactions

In connection with the Convertible Notes offering, we also entered into warrant transactions (the “Warrants”), whereby we sold to the Hedge Counterparties warrants in an aggregate amount of $13,230 to acquire, subject to customary anti-dilution adjustments, up to 10,144,050 shares of our common stock at a strike price of approximately $20.09 per share of our common stock. The Warrants will be settled on a net-share basis and will expire in April 2019. The Warrants have been included in additional paid-in capital on the consolidated balance sheets.

The Warrants are separate transactions and are not part of the terms of the Convertible Notes and are excluded from classification as a derivative as the amount could be settled in our stock. Holders of the Convertible Notes do not have any rights with respect to the Warrants.

2006 Term Loan Credit Facility. In June 2006, we entered into a $450,000 term loan (“2006 Term Loan”). The 2006 Term Loan required principal repayments of $4,500 per annum paid in quarterly installments until maturity in August 2013. In November 2012, we repaid in full our obligations under the 2006 Term Loan. As a result of the prepayment of the 2006 Term Loan, a write-off of unamortized debt issuance costs of $1,459 is included in interest expense on the consolidated statements of operations for the year ended December 31, 2012.

Alon USA Term Loan Credit Facility. In November 2012, we entered into a term loan (“Alon USA Term Loan”) with an aggregate principal amount of $450,000, issued at an offering price of 95%, that matures in November 2018. Proceeds from the Alon USA Term Loan were used to repay in full our obligations under the 2006 Term Loan and for general corporate purposes.

In connection with the closing of the Partnership’s initial public offering in November 2012 (the “Offering”), we assigned $250,000 of the aggregate principal balance of the Alon USA Term Loan to the Partnership and used proceeds from the Offering to fully repay the remaining outstanding balance of the Alon USA Term Loan.

As a result of the prepayment of the Alon USA Term Loan, write-offs of unamortized original issuance discount and debt issuance costs of $18,750 and $7,367, respectively, are included in interest expense on the consolidated statements of operations for the year ended December 31, 2012.

Letter of Credit Facilities. In March 2010, we entered into a credit facility with Israel Discount Bank of New York (“IDB”), as amended from time to time, (the “Alon Energy Letter of Credit Facility”) for the issuance of letters of credit in an amount not to exceed $60,000 with a sub-limit for borrowings not to exceed $30,000.

In December 2013, the Alon Energy Letter of Credit Facility was amended to extend the maturity to November 2015. The Alon Energy Letter of Credit Facility is for the issuance of standby letters of credit in an amount not to exceed $60,000. We are required to pledge $100,000 of the Partnership’s common units as collateral for the Alon Energy Letter of Credit Facility. Additionally, Alon Assets, Inc. was named as a guarantor, guaranteeing all of our obligations under the Alon Energy Letter of Credit Facility in the event of default. The Alon Energy Letter of Credit Facility contains certain restrictive covenants including maintenance financial covenants.

At December 31, 2013 and 2012, we had outstanding letters of credit under this facility of $56,827 and $59,485, respectively.

(b) Alon USA Partners, LP Credit Facility

Partnership Term Loan Credit Facility. In connection with the Offering, the Partnership was assigned $250,000 of the aggregate principal balance of the Alon USA Term Loan (the “Partnership Term Loan”). The Partnership Term Loan requires principal payments of $2,500 per annum paid in quarterly installments until maturity in November 2018.

The Partnership Term Loan bears interest at a rate equal to the sum of (i) the Eurodollar rate (with a floor of 1.25% per annum) plus (ii) a margin of 8.00% per annum for a per annum rate of 9.25%, based on current Eurodollar market rates at December 31, 2013.

The Partnership Term Loan is secured by a first priority lien on all of the Partnership’s fixed assets and other specified property, as well as on the general partner interest in the Partnership held by the General Partner, and a second lien on the Partnership’s cash, accounts receivables, inventories and related assets.

F-29

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

The Partnership Term Loan contains restrictive covenants, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, different businesses, certain lease obligations and certain restricted payments. The Partnership Term Loan does not contain any maintenance financial covenants.

At December 31, 2013 and 2012, the Partnership Term Loan had an outstanding balance (net of unamortized discount) of $244,322 and $246,311, respectively.

Revolving Credit Facility. We have a $240,000 revolving credit facility (the “Alon USA LP Credit Facility”) that will mature in March 2016. The Alon USA LP Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility amount or the borrowing base amount under the facility.

Borrowings under the Alon USA LP Credit Facility bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%.

The Alon USA LP Credit Facility is secured by a first lien on cash, accounts receivables, inventories and related assets and a second lien on fixed assets and other specified property, in each case, excluding those of Alon Paramount Holdings, Inc. (“Alon Holdings”) and its subsidiaries other than Alon Pipeline Logistics, LLC (“Alon Logistics”), the subsidiaries established in conjunction with the Krotz Springs refinery acquisition, the subsidiaries established in conjunction with the Bakersfield refinery acquisition and our retail subsidiaries.

The Alon USA LP Credit Facility contains certain restrictive covenants including maintenance financial covenants.

Borrowings of $100,000 and $49,000 were outstanding under the Alon USA LP Credit Facility at December 31, 2013 and 2012, respectively. At December 31, 2013 and 2012, outstanding letters of credit under the Alon USA LP Credit Facility were $109,772 and $58,759, respectively.

(c) Alon Refining Krotz Springs, Inc. Credit Facilities

Senior Secured Notes. In October 2009, ARKS issued 13.50% senior secured notes (the “Senior Secured Notes”) in aggregate principal amount of $216,500 in a private offering. In February 2010, ARKS exchanged $216,500 of Senior Secured Notes for an equivalent amount of Senior Secured Notes (“Exchange Notes”) registered under the Securities Act of 1933. The Exchange Notes will mature in October 2014 and the entire principal amount is due at maturity. Interest is payable semi-annually in arrears on April 15 and October 15. The Exchange Notes are substantially identical to the Senior Secured Notes, except that the Exchange Notes have been registered with the Securities and Exchange Commission and are not subject to transfer restrictions. The Senior Secured Notes were issued at an offering price of 94.857% and ARKS received gross proceeds of $205,365 (before fees and expenses related to the offering).

The terms of the Senior Secured Notes are governed by an indenture (the “Indenture”) and the obligations under the Indenture are secured by a first priority lien on ARKS’ property, plant and equipment and a second priority lien on ARKS’ cash, accounts receivable and inventory.

The Indenture contains restrictive covenants such as restrictions on loans, mergers, sales of assets, additional indebtedness and restricted payments. The Indenture does not contain any maintenance financial covenants.

In October 2013, we used proceeds from the Convertible Notes offering, along with cash on hand, to redeem $140,000 of the outstanding principal balance on the Senior Secured Notes. As a result of the prepayment of the Senior Secured Notes, a prepayment premium of $4,725 and write-offs of unamortized original issuance discount and debt issuance costs of $1,871 and $1,871, respectively, were charged to interest expense in the consolidated statements of operations for the year ended December 31, 2013.

At December 31, 2013, the Senior Secured Notes due October 2014 had an outstanding balance (net of unamortized discount) of $73,706, included in current portion of long-term debt. At December 31, 2012, the Senior Secured Notes had an outstanding balance (net of unamortized discount) of $211,573, included in long-term debt. ARKS is utilizing the effective interest method to amortize the original issue discount over the life of the Senior Secured Notes.

(d) Retail Credit Facilities

Alon Brands Term Loans. In March 2011, Alon Brands issued $30,000 five-year unsecured notes (the “Alon Brands Term Loans”) to a group of investors including certain shareholders of Alon Israel and their affiliates. In conjunction with the issuance of the Alon Brands Term Loans, we issued 3,092,783 warrants to purchase shares of our common stock. The allocated fair value of the warrants was $10,988 and was recorded as additional paid-in capital at the time of issuance.

F-30

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

In March 2012, we issued $30,000 of 8.5% Series B Convertible Preferred Stock to the holders of the Alon Brands Term Loans and repaid in full the obligations under the Alon Brands Term Loans. Also as part of the transaction, the warrants issued in conjunction with the Alon Brands Term Loans were surrendered to Alon Energy. As the Alon Brands Term Loans were originally issued at a discount, the remaining $9,624 of unamortized original issuance discount was charged to interest expense in the consolidated statements of operations for the year ended December 31, 2012.

Term Credit Agreement. Southwest Convenience Stores, LLC (“SCS”) is party to a credit agreement (the “SCS Credit Agreement”) that, as amended, matures in December 2015. In December 2010, SCS entered into an amendment to the SCS Credit Agreement, which increased the amount outstanding from $73,361 (“SCS Refinancing Term Loan”) by $10,000 (“SCS Additional Term Loan”) and also included a revolving credit loan (“SCS Revolving Credit Loan”) with a maximum loan amount of the lesser of the borrowing base or $10,000.

Borrowings under the SCS Refinancing Term Loan bear interest at a Eurodollar rate plus 2.00% per annum with principal payments made in quarterly installments based on a 15-year amortization schedule. Borrowings under the SCS Additional Term Loan bear interest at a Eurodollar rate plus 2.75% per annum with principal payments made in quarterly installments based on a 5-year amortization schedule. Borrowings under the SCS Revolving Credit Loan bear interest at a Eurodollar rate plus 2.75% per annum.

The obligations under the SCS Credit Agreement are secured by a pledge of substantially all of the assets of SCS and Skinny’s, LLC and each of their subsidiaries, including cash, accounts receivable and inventory. The SCS Credit Agreement contains certain restrictive covenants including maintenance financial covenants.

At December 31, 2013 and 2012, the SCS Credit Agreement had an outstanding balance under the term loans of $62,689 and $69,580, respectively. At December 31, 2013 and 2012, the SCS Revolving Credit Loan had an outstanding balance of $10,000 and $10,000, respectively.

(e) Other Retail Related Credit Facilities

In 2003, we obtained $1,545 in mortgage loans to finance the acquisition of new retail locations. The interest rates on these loans ranged between 5.5% and 9.7%, with 5 to 15 year payment terms. At December 31, 2013 and 2012, the outstanding balances were $441 and $553, respectively.

(f) Financial Covenants

We have certain credit facilities that contain restrictive covenants, including maintenance financial covenants. At December 31, 2013, we were in compliance with these covenants.

(g) Maturity of Long-Term Debt

The aggregate scheduled maturities of long-term debt for each of the five years subsequent to December 31, 2013 are as follows:

2014	$	83,174
2015	68,381
2016	102,572
2017	2,565
2018	355,485
2019 and thereafter	71
Total	$	612,248

F-31

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(h) Interest and Financing Expense

Interest and financing expense included the following:

	Year Ended December 31,
	2013			2012			2011
Interest expense	$	54,191		$	57,987		$	57,569
Letters of credit and finance charges	32,286			28,159			23,471
Amortization of debt issuance costs	4,496			6,296			6,493
Write-off of debt issuance costs	1,871			8,826			—
Amortization of original issuance discount	4,300			2,570			3,050
Write-off of original issuance discount	1,871			28,374			—
Capitalized interest	(4,321		)	(2,640		)	(2,273		)
Total interest expense	$	94,694		$	129,572		$	88,310

(15) Stockholders' Equity

(a) Common stock (share value in dollars)

Our authorized common stock consists of 150,000,000 shares of common stock, $0.01 par value. Issued and outstanding shares of common stock were 68,641,428 and 61,272,429 as of December 31, 2013 and 2012, respectively.

Standby Equity Distribution Agreement. In January 2011, we entered into a Standby Equity Distribution Agreement (the “SEDA”) with YA Global Master SPV Ltd. to purchase up to $25,000 of Alon USA Energy, Inc. common stock. During 2011, we sold shares of our common stock with total proceeds of $11,900. The SEDA expired in January 2013.

Warrants. In conjunction with the issuance of the Alon Brands Term Loans, we issued 3,092,783 warrants to purchase shares of Alon USA Energy, Inc. common stock at an initial exercise price per share of $9.70. In conjunction with the repayment of the Alon Brands Term Loans in March 2012, all warrants were surrendered to us.

Amended Shareholder Agreement. In 2011, an agreement was reached with one of the non-controlling interest shareholders of Alon Assets, Inc.,whereby the participant would exchange 2,019 shares of Alon Assets, Inc., ratably over a three year period for up to 377,710 shares of our common stock. One-third of the Alon Assets, Inc. shares were exchanged in each of October 2013, October 2012 and October 2011.

In 2012, we signed agreements with the remaining two non-controlling interest shareholders of Alon Assets, Inc. We have the right to exchange 581,699 shares of our common stock over a period of 12 quarters and 2,326,946 shares of our common stock over a period of 20 quarters, beginning July 2012, for 15,549.30 shares of Alon Assets, Inc.

During 2013 and 2012, 785,192 and 455,547 shares of our common stock were issued in exchange for 4,197.55 and 2,435.31 shares of Alon Assets, Inc., respectively. At December 31, 2013, 1,919,711 shares of our common stock remain available for exchange. Compensation expense associated with the difference in value between the participants’ ownership of Alon Assets, Inc. compared to our common stock of $2,499, $1,036 and $542 was recognized for the years ended December 31, 2013, 2012 and 2011, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

F-32

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

For the years ended December 31, 2013, 2012 and 2011, activity in the number of common stock was as follows:

	Common Stock
	(in thousands)
Balance as of December 31, 2010	54,282
Shares issued in connection with stock plans	186
Shares issued for payment of preferred stock dividends	328
Shares issued in connection with standby equity distribution agreement	1,228
Shares issued in connection with amended shareholder agreement	84
Balance as of December 31, 2011	56,108
Shares forfeited	(20	)
Shares issued in connection with stock plans	256
Shares issued for payment of preferred stock dividends	358
Shares issued in connection with preferred share conversions	4,125
Shares issued in connection with amended shareholder agreement	445
Balance as of December 31, 2012	61,272
Shares issued in connection with stock plans	237
Shares issued for payment of preferred stock dividends	197
Shares issued in connection with preferred share conversions	6,160
Shares issued in connection with amended shareholder agreement	776
Balance as of December 31, 2013	68,641

(b) Preferred stock (share value in dollars)

Our authorized preferred stock consists of 15,000,000 shares of convertible preferred stock, $0.01 par value. Issued and outstanding shares of preferred stock were 68,180 and 4,220,000 as of December 31, 2013 and 2012, respectively.

In October 2010, we completed a registered direct offering of 4,000,000 shares of Alon’s 8.5% Series A Convertible Preferred Stock (the “Series A Preferred Stock”) for an aggregate offering price of $40,000 less offering expenses, of which Alon Israel purchased $35,000. The holders of the Series A Preferred Stock can convert, at the holder’s option, the Series A Preferred Stock into shares of our common stock based on an initial conversion price of $6.74 per share, in each case subject to adjustments. The Series A Preferred Stock may be redeemed at our option after October 28, 2017, but under certain conditions we have the right to convert the Series A Preferred Stock into shares of our common stock from October 2013. If all of the Series A Preferred Stock were to be converted into shares of our common stock based on the initial conversion price of $6.74 per share, then 5,934,800 shares of our common stock would be issued. As of December 31, 2013 all of the Series A Preferred Stock have been converted into shares of our common stock.

In March 2012, we issued 3,000,000 shares of 8.5% Series B Convertible Preferred Stock (the “Series B Preferred Stock”) to a group of investors who held, in the aggregate, $30,000 of the Alon Brands Term Loans and 3,092,783 warrants to purchase shares of our common stock. We repaid in full the obligations under the Alon Brands Term Loans and the warrants were surrendered to us. The terms of the Series B Preferred Stock are substantially the same as the terms of the Series A Preferred Stock except that, based on certain conditions, we have the right to convert the Series B Preferred Stock into shares of our common stock from March 2015. If all of the Series B Preferred Stock were to be converted into shares of our common stock based on the initial conversion price of $6.74 per share, then 4,451,100 shares of our common stock would be issued. At December 31, 2013, 68,180 shares of Series B Convertible Preferred Stock remain outstanding.

During the year ended December 31, 2013, certain holders converted 3,500,000 shares of Series A Preferred Stock and 651,820 shares of Series B Preferred Stock to 6,160,057 shares of our common stock. During the year ended December 31, 2012, certain holders converted 500,000 shares of Series A Preferred Stock and 2,280,000 shares of Series B Preferred Stock to 4,124,686 shares of our common stock.

(c) Dividends

During the year ended December 31, 2013, we paid cash dividends on common stock totaling $0.38 per share which included a special non-recurring dividend of $0.16 per share paid in June 2013 as well as an increase in our regular quarterly

F-33

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

dividend from $0.04 per share to $0.06 per share. During the years ended December 31, 2012 and 2011, we paid cash dividends on common stock totaling $0.16 per share each year. Additionally, the non-controlling interest shareholders of Alon Assets, Inc. received aggregate cash dividends of $886, $524 and $704 during 2013, 2012, and 2011, respectively.

Preferred Stock Dividends. We issued 196,648 and 358,000 shares in aggregate of our common stock for payment of the quarterly 8.5% preferred stock dividends to preferred stockholders for the years ended December 31, 2013 and 2012, respectively.

(d) Accumulated Other Comprehensive Income (Loss)

The following table displays the change in accumulated other comprehensive income (loss), net of tax:

	Unrealized Gain (Loss) on Cash Flow Hedges			Postretirement Benefit Plans			Total
Balance at December 31, 2012	$	921		$	(31,368	)	$	(30,447	)
Other comprehensive income (loss) before reclassifications	(32,565		)	14,546			(18,019		)
Amounts reclassified from accumulated other comprehensive income (loss)	13,396			(2,445		)	10,951
Net current-period other comprehensive income (loss)	(19,169		)	12,101			(7,068		)
Balance at December 31, 2013	$	(18,248	)	$	(19,267	)	$	(37,515	)

(16) Stock-Based Compensation

Amended and Restated 2005 Incentive Compensation Plan (share value in dollars)

The Alon USA Energy, Inc. Second Amended and Restated 2005 Incentive Compensation Plan (“the Plan”) is a component of our overall executive incentive compensation program. The Plan permits the granting of awards in the form of options to purchase common stock, Stock Appreciation Rights (“SARs”), restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses to our directors, officers and key employees.

Restricted Stock. Non-employee directors are awarded an annual grant of $25 in shares of restricted stock. The restricted shares granted to the non-employee directors vest over a period of three years, assuming continued service at vesting. In May 2013, we granted awards of 4,257 restricted shares at a grant date price of $17.62 per share.

In May 2013, we granted awards of 255,000 restricted shares to certain executive officers at a grant date price of $17.25 per share. These May 2013 restricted shares will vest as follows: 50% in May 2014 and 50% in May 2016, assuming continued service at vesting.

In May 2012, we granted awards of 180,000 restricted shares to certain executive officers at a weighted average grant date price of $8.77 per share. These May 2012 restricted shares are 50% vested as of December 31, 2013, with the remaining 50% vesting in May 2016, assuming continued service at vesting.

In August 2012, we granted awards of 37,500 restricted shares to certain executive officers at a weighted average grant date price of $13.95 per share. These August 2012 restricted shares are fully vested as of December 31, 2013.

In May 2011, we granted awards of 180,000 restricted shares to certain executive officers at a weighted average grant date price of $13.53 per share. These May 2011 restricted shares are 50% vested as of December 31, 2013, with the remaining 50% vesting in May 2016, assuming continued service at vesting.

F-34

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

The following table summarizes the restricted share activity from January 1, 2012:

			Weighted Average Grant Date Fair Values
Nonvested Shares	Shares		(per share)
Nonvested at January 1, 2012	194,906		$	13.26
Granted	228,648		9.63
Vested	(97,424	)	13.27
Forfeited	—		—
Nonvested at December 31, 2012	326,130		$	10.71
Granted	259,257		17.26
Vested	(136,693	)	10.21
Forfeited	—		—
Nonvested at December 31, 2013	448,694		$	14.64

Compensation expense for the restricted stock grants amounted to $3,005, $1,656 and $1,054 for the years ended December 31, 2013, 2012 and 2011, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations. The fair value of shares vested in 2013 was $2,379.

Restricted Stock Units. In May 2011, we granted 500,000 restricted stock units to the CEO and President of Alon at a grant date fair value of $11.47 per share. Each restricted unit represents the right to receive one share of our common stock upon the vesting of the restricted stock unit. All 500,000 restricted stock units vest on March 1, 2015, assuming continued service at vesting. Compensation expense for the restricted stock units amounted to $1,496, $1,496 and $997 for the years ended December 31, 2013, 2012 and 2011 respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

Senior Executive Plan Bonuses.  In August 2012, we granted 37,500 shares of common stock to certain executive officers at a weighted average grant date price of $13.95 per share. These shares vested immediately upon issuance. Compensation expense for the bonuses amounted to $523 for the year ended December 31, 2012, and is included in selling, general and administrative expenses in the consolidated statements of operations.

Stock Appreciation Rights. As of December 31, 2013, we had 8,750 SARs that have been granted but have not vested, of which 6,875 will vest in 2014 and 1,875 will vest in 2015. These awards have grant prices ranging from $10.00 to $16.00 per share. As of December 31, 2013, 110,687 SARs have vested and are not exercised. Compensation expense for the SARs grants amounted to $24, $56 and $336 for the years ended December 31, 2013, 2012 and 2011, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

Unrecognized Compensation. As of December 31, 2013, there was $5,279 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 1.5 years.

F-35

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(17) Income Taxes

Income tax expense included the following:

	Year Ended December 31,
	2013			2012		2011
Current:
Federal	$	1,348		$	3,074	$	—
State	2,525			4,788		1,502
Total current	$	3,873		$	7,862	$	1,502
Deferred:
Federal	$	9,770		$	41,868	$	20,285
State	(1,492		)	154		(2,869		)
Total deferred	8,278			42,022		17,416
Income tax expense	$	12,151		$	49,884	$	18,918

A reconciliation between the income tax expense computed on pretax income at the statutory federal rate and the actual provision for income tax expense is as follows:

	Year Ended December 31,
	2013			2012			2011
Computed expected tax expense	$	21,093		$	49,169		$	21,933
State and local income taxes, net of federal benefit	844			3,373			373
Tax effect of non-controlling interest in Partnership income	(8,927		)	(2,426		)	—
Other, net	(859		)	(232		)	(3,388		)
Income tax expense	$	12,151		$	49,884		$	18,918

The following table sets forth the tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities.

	As of December 31,
	2013			2012
Deferred income tax assets:
Accounts receivable, allowance	$	155		$	211
Accrued liabilities and other	1,521			1,694
Post-retirement benefits	25,929			21,887
Non-current accrued liabilities and other	22,631			21,220
Net operating loss carryover	22,399			22,211
Tax credits	3,279			19,597
Other	5,428			7,568
Deferred income tax assets	$	81,342		$	94,388
Deferred income tax liabilities:
Deferred gain on the Offering of the Partnership	$	50,491		$	50,581
Deferred charges	524			271
Unrealized gains	925			(504		)
Property, plant and equipment	374,852			385,567
Other non-current	3,793			4,907
Inventories	(10,402		)	(11,021		)
Intangibles	8,771			7,637
Deferred income tax liabilities	$	428,954		$	437,438

F-36

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of taxable income and projections for future taxable income, over the periods which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the benefits of these deductible differences in future periods.

At December 31, 2013, we have net operating loss carryforwards for state and local income tax purposes of $414,431 which are available to offset future state taxable income in various years through 2031.

We have elected to recognize interest expense related to the underpayment of income taxes in interest expense, and penalties relating to underpayment of income taxes as a reduction to other income (loss), net, in the consolidated statements of operations. We are subject to U.S. federal income tax, and income tax in multiple state jurisdictions with California, Texas, New Mexico, Oklahoma and Louisiana comprising the majority of our state income tax. The federal tax years 2000 to 2009 are closed to audit. In general, the state tax years open to audit range from 2006 to 2012. Our liability for unrecognized tax benefits and accrued interest did not increase during the year ended December 31, 2013, as there were no unrecognized tax benefits recorded in 2013.

(18) Earnings Per Share

Basic earnings per share is calculated as net income available to common stockholders divided by the weighted average number of participating shares of common stock outstanding. Diluted earnings per share includes the dilutive effect of SARs, granted restricted stock units, convertible debt and warrants using the treasury stock method and the dilutive effect of convertible preferred shares using the if-converted method.

The calculation of earnings per share, basic and diluted, for the years ended December 31, 2013, 2012 and 2011, is as follows:

	Year Ended December 31,
	2013		2012		2011
Net income available to stockholders	$	22,986	$	79,134	$	42,507
less: preferred stock dividends	2,288		4,892		—
Net income available to common stockholders	20,698		74,242		42,507
Weighted average number of shares of common stock outstanding	63,538		57,501		55,431
Dilutive SARs, RSUs, convertible debt, warrants and convertible preferred stock	1,314		6,416		5,970
Weighted average number of shares of common stock outstanding, assuming dilution	64,852		63,917		61,401
Earnings per share – basic	$	0.33	$	1.29	$	0.77
Earnings per share – diluted	$	0.32	$	1.24	$	0.69

For the year ended December 31, 2013, we have excluded 4,509 common stock equivalents from the weighted average number of diluted shares outstanding as the effect of including such shares would be anti-dilutive. For the years ended December 31, 2012 and 2011, the weighted average number of diluted shares includes all potentially dilutive securities.

(19) Related Party Transactions

(a)Letters of Credit

Alon Israel Oil Company, Ltd. (“Alon Israel”) provided letters of credit to us of $15,000. In December 2012, the amount was reduced by $12,500 and in December 2013, the letter of credit was canceled.

In 2010, Alon Israel provided a letter of credit fee agreement of $23,000. We returned the $23,000 to Alon Israel in October 2011 and the letter of credit fee agreement was terminated.

F-37

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(b)Preferred Stock Conversions

In 2010, Alon Israel purchased 3,500,000 shares of our 8.5% Series A Convertible Preferred Stock. During the year ended December 31, 2013, Alon Israel converted all of their 3,500,000 shares of Series A Preferred Stock to 5,192,950 shares of our common stock.

In 2011, Alon Brands issued $12,000 five-year unsecured notes to certain shareholders of Alon Israel and their affiliates as part of the Alon Brands Term Loans. In conjunction with the issuance of the Alon Brands Term Loans, we issued to certain shareholders of Alon Israel 1,237,113 warrants to purchase shares of our common stock.

In 2012, we issued 1,200,000 shares of 8.5% Series B Convertible Preferred Stock for $12,000 to certain shareholders of Alon Israel and their affiliates to repay all amounts due under the Alon Brands Term Loans. The warrants held by Alon Israel and their affiliates were also surrendered to us.

During the years ended December 31, 2013 and 2012, 651,820 and 480,000 shares of Series B Convertible Preferred Stock were converted into 967,107 and 712,176 shares of our common stock, respectively. At December 31, 2013, 68,180 shares of Series B Convertible Preferred Stock remain outstanding.

(c)Collateral Fee Agreement

In March 2010, we entered into a line letter with IDB, pursuant to which IDB agreed to provide a line of credit to us for a maximum amount of $60,000. The collateral supporting the line of credit was comprised of a security interest in a $30,000 deposit account maintained at IDB by Alon Israel. In 2010, in consideration for maintaining the deposit at IDB as collateral under the line letter, we entered into a Collateral Fee Agreement with Alon Israel whereby we agreed to pay a fee to Alon Israel based upon a formula set forth in the agreement which includes, among other items, costs to Alon Israel associated with the deposit. In 2013, the $30,000 deposit was returned to Alon Israel.

(d)Development Agreement

We entered into a development agreement with BSRE Point Wells, LP (“BSRE”), a subsidiary of Alon Holdings Blue Square-Israel, Ltd., in conjunction with the sale of a parcel of land at Richmond Beach, Washington to BSRE. In order to enhance the value of the land with a view towards maximizing the proceeds from its sale, the agreement provides that Alon and BSRE intend to cooperate in the development and construction of a mixed-use residential and planned community real estate project on the land. As part of this agreement, we agreed to pay a quarterly development fee of $439 in exchange for the right to participate in the potential profits realized by BSRE from the development of the land.

(e)Purchase of Equipment

During the year ended December 31, 2012, we purchased, from an affiliate, hydrotreating equipment and other refinery processing equipment for $18,000 and $8,000, respectively.

(20) Commitments and Contingencies

(a) Leases

We have long-term lease commitments for land, office facilities, retail facilities and related equipment and various equipment and facilities used in the storage and transportation of refined products. We also have long-term lease commitments for land at our Krotz Springs refinery. In most cases we expect that in the normal course of business, our leases will be renewed or replaced by other leases. We have commitments under long-term operating leases for certain buildings, land, equipment and pipelines expiring at various dates over the next twenty-two years. Certain long-term operating leases relating to buildings, land and pipelines include options to renew for additional periods. At December 31, 2013, minimum lease payments on operating leases were as follows:

Year ending December 31:
2014	$	25,710
2015	22,525
2016	20,191
2017	17,813
2018	13,125
2019 and thereafter	45,916
Total	$	145,280

F-38

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

Total rental expense was $33,965, $34,943, and $42,218 for the years ended December 31, 2013, 2012, and 2011, respectively. Contingent rentals and subleases were not significant.

(b) Commitments

In the normal course of business, we have long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by our refineries, terminals, pipelines and retail locations. We are also party to various refined product and crude oil supply and exchange agreements. These agreements are typically short-term in nature or provide terms for cancellation.

We have a pipelines and terminals agreement with Holly Energy Partners (“HEP”) through February 2020 with three additional five year renewal terms exercisable at our sole option. Pursuant to the pipelines and terminals agreement, we have committed to transport and store minimum volumes of refined products in these pipelines and terminals. The tariff rates applicable to the transportation of refined products on the pipelines are variable, with a base fee which is reduced for volumes exceeding defined volumetric targets. The agreement provides for the reduction of the minimum volume requirement under certain circumstances. The service fees for the storage of refined products in the terminals are set at rates competitive in the marketplace.

We have a throughput and deficiency agreement with Sunoco Pipeline, LP (“Sunoco”) that gives us the option to transport crude oil through the Amdel Pipeline either (1) westbound from the Nederland Terminal to the Big Spring refinery, or (2) eastbound from the Big Spring refinery to the Nederland Terminal for further barge transportation to the Krotz Springs refinery. Our minimum throughput commitment is 15,645 bpd. The agreement is for five years from the operational date of September 2012 with an option to extend the agreement by four additional thirty-month periods.

We have an arrangement with Centurion through June 2021. This arrangement gives us transportation pipeline capacity to ship crude oil from Midland to the Big Spring refinery using Centurion’s approximately forty-mile long pipeline system from Midland to Roberts Junction and our three-mile pipeline from Roberts Junction to the Big Spring refinery which we lease to Centurion. Our minimum throughput commitment is 25,000 bpd.

In July 2013, we entered into offtake agreements with two investment grade oil companies that provides for the sale, at market prices, of light cycle oil and high sulfur distillate blendstock through June 2015. Both agreements will automatically extend for successive one year terms unless either we or the other party cancels the agreement by delivering written notice of termination to the other at least 180 days prior to the end of the then current term.

(c) Contingencies

We are involved in various legal actions arising in the ordinary course of business. We believe the ultimate disposition of these matters will not have a material effect on our financial position, results of operations or liquidity.

One of our subsidiaries is a party to a lawsuit alleging breach of contract pertaining to an asphalt supply agreement. We believe that we have valid counterclaims as well as affirmative defenses that will prevent recovery. Attempts to reach a commercial arrangement to resolve the dispute have been unsuccessful to this point. A pre-trial ruling by the trial court is currently being appealed and therefore the matter has not been scheduled for trial. Due to the uncertainties of litigation, we cannot predict with certainty the ultimate resolution of this lawsuit.

(d) Environmental

We are subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These laws and regulations govern the discharge of materials into the environment and may require us to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites and to compensate others for damage to property and natural resources. These contingent obligations relate to sites that we own and our past or present operations. We are currently participating in environmental investigations, assessments and cleanups pertaining to our refineries, service stations, pipelines and terminals. We may be involved in additional future environmental investigations, assessments and cleanups. The magnitude of future costs are unknown and will depend on factors such as the nature and contamination at many sites, the timing, extent and method of the remedial actions which may be required, and the determination of our liability in proportion to other responsible parties.

We have an environmental agreement with HEP pursuant to which we agreed to indemnify HEP against costs and liabilities incurred by HEP to the extent resulting from the existence of environmental conditions at the pipelines or terminals or from violations of environmental laws with respect to the pipelines and terminals occurring prior to February 28, 2005. Our environmental indemnification obligations under the environmental agreement expire after February 28, 2015. In addition, our indemnity obligations are subject to HEP first incurring $100 of damages as a result of pre-existing environmental conditions or violations. Our environmental indemnity obligations are further limited to an aggregate indemnification amount of $20,000,

F-39

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

including any amounts we paid to HEP with respect to indemnification for breaches of our representations and warranties under a contribution agreement. With respect to any remediation required for environmental conditions existing prior to February 28, 2005, we have the option under the environmental agreement to perform such remediation ourself in lieu of indemnifying HEP for their costs of performing such remediation. Pursuant to this option, we are continuing to perform the ongoing remediation at the Abilene and Wichita Falls terminals. Any remediation required under the terms of the environmental agreement is limited to the standards under the applicable environmental laws as in effect at February 28, 2005.

We have an environmental agreement with Sunoco pursuant to which we agreed to indemnify Sunoco against costs and liabilities incurred by Sunoco to the extent resulting from the existence of environmental conditions at the pipelines or from violations of environmental laws with respect to the pipelines occurring prior to March 1, 2006. With respect to any remediation required for environmental conditions existing prior to March 1, 2006, we have the option to perform such remediation ourself in lieu of indemnifying Sunoco for their costs of performing such remediation.

We have accrued environmental remediation obligations of $58,382 ($12,898 current liability and $45,484 non-current liability) at December 31, 2013, and $61,402 ($6,730 current liability and $54,672 non-current liability) at December 31, 2012. Environmental liabilities with payments that are fixed or reliably determinable have been discounted to present value at a rate of 3.38%.

The table below summarizes our environmental liability accruals:

	As of December 31,
	2013		2012
Discounted environmental liabilities	$	35,938	$	36,013
Undiscounted environmental liabilities	22,444		25,389
Total accrued environmental liabilities	$	58,382	$	61,402

As of December 31, 2013, the estimated future payments of environmental obligations for which discounts have been applied are as follows:

Year ending December 31,
2014	$	4,143
2015	3,893
2016	3,498
2017	3,373
2018	3,268
2019 and thereafter	28,069
Discounted environmental liabilities, gross	46,244
Less: Discount applied	10,306
Discounted environmental liabilities	$	35,938

In connection with the 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 refinery on the acquisition date. We are required to make indemnification claims to the prior owner by March 15, 2015. We have recorded current receivables of $9,100 and $3,239 and non-current receivables of $1,774 and $11,599 at December 31, 2013 and 2012, respectively.

We have an indemnification agreement with a prior owner for part of the remediation expenses at certain West Coast assets. We have recorded current receivables of $418 and $604 and non-current receivables of $2,499 and $1,964 at December 31, 2013 and 2012, respectively.

F-40

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(21) Quarterly Information (unaudited)

Selected financial data by quarter is set forth in the table below:

	Quarters
	First			Second		Third			Fourth			Full Year
2013
Net sales	$	1,651,196		$	1,676,595	$	1,892,836		$	1,825,754		$	7,046,381
Operating income (loss)	125,831			42,032		(39,397		)	20,967			149,433
Net income (loss) available to stockholders	54,184			11,496		(28,709		)	(13,985		)	22,986
Earnings (loss) per share, basic	$	0.86		$	0.17	$	(0.47	)	$	(0.21	)	$	0.33
Weighted average shares outstanding	61,957			62,614		62,901			66,681			63,538
2012
Net sales	$	1,792,133		$	1,910,489	$	2,360,334		$	1,954,785		$	8,017,741
Operating income (loss)	(9,782		)	92,638		90,346			96,273			269,475
Net income (loss) available to stockholders	(29,367		)	43,091		43,223			22,187			79,134
Earnings (loss) per share, basic	$	(0.52	)	$	0.77	$	0.76		$	0.35		$	1.29
Weighted average shares outstanding	56,028			56,238		56,699			61,041			57,501

(22) Subsequent Events

Dividend Declared

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.

Partnership Distribution

On February 13, 2014, the board of directors of the General Partner declared a cash distribution to the Partnership’s common unitholders of $11,250, or $0.18 per common unit. The cash distribution was paid on March 3, 2014 to unitholders of record at the close of business on February 24, 2014. The total cash distribution paid to non-affiliated common unitholders was $2,070.

Disposition of Assets

In January 2014, we sold the Willbridge, Oregon facility for $40,000.

F-41

EXHIBITS

Exhibit No.	Description of Exhibit
1.1	Underwriting Agreement by and among Alon USA Partners, LP, Alon USA Partners GP, LLC, Alon Assets, Inc., Alon USA GP, LLC and Alon USA Energy, Inc. and Goldman, Sachs & Co., Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc., as representatives of the several underwriters named therein, dated November 19, 2012 (incorporated by reference to Exhibit 1.1 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
1.2	Purchase Agreement, dated September 10, 2013, among Alon USA Energy, Inc., Goldman, Sachs & Co. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 1.1 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
3.1	Second Amended and Restated Certificate of Incorporation of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.1 to Form 10-Q, filed by the Company on May 9, 2012, SEC File No. 001-32567).
3.2	Amended and Restated Bylaws of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.2 to Form S-1/A, filed by the Company on July 14, 2005, SEC File No. 333-124797).
4.1	Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
4.2	Specimen 8.50% Series A Convertible Preferred Stock Certificate. (incorporated by reference to Exhibit 4.4 to Form 10-Q, filed by the Company on November 9, 2010, SEC File No. 001-32567).
4.3	Indenture, dated as of October 22, 2009, by and among Alon Refining Krotz Springs, Inc. and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K, filed by the Company on October 23, 2009, SEC File No. 001-32567).
4.4	Indenture related to the 3.00% Convertible Senior Notes due 2018, dated as of September 16, 2013, among Alon USA Energy, Inc. and U.S. Bank National Association, as trustee (including form of 3.00% Convertible Senior Note due 2018) (incorporated by reference to Exhibit 4.1 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
4.5	Form of Certificate of Designation of the 8.75% Series A Convertible Preferred Stock (incorporated by reference to Exhibit 4.3 to Form 10-Q filed by the Company on November 9, 2010, SEC File No. 001-32567).
4.6	Form of Certificate of Designation of the 8.75% Series B Convertible Preferred Stock (incorporated by reference to Exhibit 4.5 to Form 10-K, filed by the Company on March 13, 2012 SEC File No. 001-32567).
10.1	Pipeline Lease Agreement, dated as of December 12, 2007, between Plains Pipeline, L.P. and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on February 5, 2008, SEC File No. 001-32567).
10.2	Pipeline Lease Agreement, dated as of February 21, 1997, between Navajo Pipeline Company and American Petrofina Pipe Line Company (incorporated by reference to Exhibit 10.6 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.3	Amendment and Supplement to Pipeline Lease Agreement, dated as of August 31, 2007, by and between HEP Pipeline Assets, Limited Partnership and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on November 8, 2007, SEC File No. 001-32567).
10.4	Pipelines and Terminals Agreement, dated as of February 28, 2005, between Alon USA, LP and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.8 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.5	Premises Lease, dated as of May 12, 2003, between Southwest Convenience Stores, LLC and SCS Beverage, Inc. (incorporated by reference to Exhibit 10.35 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.6	Registration Rights Agreement, dated as of July 6, 2005, between Alon USA Energy, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.22 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
10.7	Registration Rights Agreement, dated October 22, 2009, between Alon Refining Krotz Springs, Inc. and Jefferies & Company, Inc. (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on October 23, 2009, SEC File No. 001-32567).
10.8	Form of Registration Rights Agreement among the Company and Subsidiary Shareholders, dated June 20, 2012 (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on June 26, 2012, SEC File No. 001-32567).
10.9	Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc. and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.5 to Form 10-Q, filed by the Company on August 9, 2010, SEC File No. 001-32567).

Exhibit No.	Description of Exhibit
10.10	First Amendment, dated as of July 31, 2012, to the Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc. and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.7 to Form 10-Q, filed by the Company on August 9, 2012, SEC File No. 001-32567).
10.11	Second Amendment to Credit Agreement, dated as of July 31, 2013, to the Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc., and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.2 to Form 10-Q Filed by the Company on August 9, 2013, SEC File No. 001-32567).
10.12	Amended and Restated Credit Agreement, dated as of December 30, 2010, among Southwest Convenience Stores, LLC, Skinny’s, LLC, the lenders party thereto and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 6, 2011, SEC File No. 001-32567).
10.13	First Amendment to the Amended and Restated Credit Agreement, dated as of April 20, 2012, by and among Southwest Convenience Stores, LLC, Skinny’s, LLC, the lenders party thereto and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to Form 10-Q Filed by the Company on May 9, 2012, SEC File No. 001-32567).
10.14	Credit and Guaranty Agreement, dated as of November 13, 2012, among Alon USA Energy, Inc., Alon USA Partners, LP, the lenders party thereto and Credit Suisse AG, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on November 19, 2012, SEC File No. 001-32567).
10.15	Credit and Guaranty Agreement, dated as of November 26, 2012, among Alon USA Partners, LP, Alon USA Partners GP, LLC and certain subsidiaries of Alon USA Partners, LP, as Guarantors, the lenders party thereto and Credit Suisse AG, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on November 30, 2012, SEC File No. 001-32567).
10.16	Purchase Agreement, dated October 13, 2009, between Alon Refining Krotz Springs, Inc. and Jefferies & Co. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on October 19, 2009, SEC File No. 001-32567).
10.17	Management and Consulting Agreement, dated as of August 1, 2003, among Alon USA, Inc., Alon Israel Oil Company, Ltd. and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.21 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.18	Amendment, dated as of June 17, 2005, to the Management and Consulting Agreement, dated as of August 1, 2003, among Alon USA, Inc., Alon Israel Oil Company, Ltd. and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.21.1 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.19*	Executive Employment Agreement, dated as of July 31, 2000, between Jeff D. Morris and Alon USA GP, Inc., as amended by the Amendment to Executive/Management Employment Agreement, dated May 1, 2005 (incorporated by reference to Exhibit 10.23 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.20*	Second Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon USA GP, LLC (incorporated by reference to Exhibit 10.9 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
10.21*	Executive Employment Agreement between Jeff Morris and Alon USA Energy, Inc., dated May 3, 2011, (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 6, 2011, SEC File No. 001-32567).
10.22*	Management Employment Agreement, dated as of March 1, 2010, between Paul Eisman and Alon USA GP, LLC (incorporated by reference to Exhibit 10.22 to Form 10-K, filed by the Company on March 15, 2011 SEC File No. 001-32567).
10.23*	Executive Employment Agreement, dated as of July 31, 2000, between Claire A. Hart and Alon USA GP, Inc., as amended by the Amendment to Executive/Management Employment Agreement, dated May 1, 2005 (incorporated by reference to Exhibit 10.24 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.24*	Second Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Claire A. Hart and Alon USA GP, LLC (incorporated by reference to Exhibit 10.10 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
10.25*	Executive Employment Agreement, dated as of August 1, 2003, between Shai Even and Alon USA GP, LLC (incorporated by reference to Exhibit 10.49 to Form 10-K, filed by the Company on March 15, 2007, SEC File No. 001-32567).
10.26*	Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Shai Even and Alon USA GP, LLC (incorporated by reference to Exhibit 10.14 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).

Exhibit No.	Description of Exhibit
10.27*	Management Employment Agreement, dated as of October 30, 2008, between Michael Oster and Alon USA GP, LLC (incorporated by reference to Exhibit 10.71 to Form 10-K, filed by the Company on April 10, 2009, SEC File No. 001-32567).
10.28*	Agreement of Principles of Employment, dated as of December 22, 2009, between David Wiessman and the Company (incorporated by reference to Exhibit 10.44 to Form 10-K, filed by the Company on March 13, 2012 SEC File No. 001-32567).
10.29*	Amended and Restated Employment Agreement by and between Paramount Petroleum Corporation and Alan P. Moret, dated July 8, 2011 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on July 13, 2011, SEC File No. 001-32567).
10.30*	Management Employment Agreement, dated as of May 1, 2008, between Kyle C. McKeen and Alon USA GP, LLC (incorporated by reference to Exhibit 10.47 to Form 10-K, filed by the Company on March 14, 2013 SEC File No. 001-32567).
10.31*	Description of Annual Bonus Plans (incorporated by reference to Exhibit 10.56 to Form 10-K, filed by the Company on March 15, 2011 SEC File No. 001-32567).
10.32*	Change of Control Incentive Bonus Program (incorporated by reference to Exhibit 10.29 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.33*	Description of Director Compensation (incorporated by reference to Exhibit 10.30 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.34*	Form of Director Indemnification Agreement (incorporated by reference to Exhibit 10.31 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.35*	Form of Officer Indemnification Agreement (incorporated by reference to Exhibit 10.32 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.36*	Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.33 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.37*	Alon Assets, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.36 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.38*	Alon USA Operating, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.37 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.39*	Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.38 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.40*	Second Amendment to Incentive Stock Option Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon Assets, Inc. (incorporated by reference to Exhibit 10.15 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
10.41	Shareholder Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.39 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.42*	Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Jeff D. Morris, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.40 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.43*	Second Amendment to Incentive Stock Option Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon USA Operating, Inc. (incorporated by reference to Exhibit 10.16 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
10.44	Shareholder Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Jeff D. Morris, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.41 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.45	Amendment to Shareholder Agreements among the Company, Alon Assets, Inc., Alon Operating, Inc., Jeff Morris and Jeff Morris/IRA, dated June 20, 2012 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on June 26, 2012, SEC File No. 001-32567).
10.46*	Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.42 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.47	Shareholder Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.43 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).

Exhibit No.	Description of Exhibit
10.48	Amendment to Shareholder Agreements among the Company, Alon Assets, Inc., Alon Operating, Inc., Claire Hart and Claire Hart/IRA, dated June 20, 2012 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on June 26, 2012, SEC File No. 001-32567).
10.49*	Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.44 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.50	Shareholder Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.45 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.51*	Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III, as amended by the Amendment to the Incentive Stock Option Agreement, dated July 25, 2002 (incorporated by reference to Exhibit 10.46 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.52	Shareholder Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.47 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.53*	Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III, as amended by the Amendment to the Incentive Stock Option Agreement, dated July 25, 2002 (incorporated by reference to Exhibit 10.48 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.54	Shareholder Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.49 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.55	Amendment to Shareholder Agreements – Option Shares, between Alon Assets, Inc., Alon Operating, Inc., Alon USA Energy, Inc. and Joseph A. Concienne, dated October 3, 2011 (incorporated by reference to Exhibit 10.68 to Form 10-K Filed by the Company on March13, 2012, SEC File No. 001-32567).
10.56	Agreement, dated as of July 6, 2005, among Alon USA Energy, Inc., Alon USA, Inc., Alon USA Capital, Inc., Alon USA Operating, Inc., Alon Assets, Inc., Jeff D. Morris, Claire A. Hart and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.52 to Form S-1/A, filed by the Company on July 7, 2005, SEC File No. 333-124797).
10.57*	Alon USA Energy, Inc. Second Amended and Restated 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 9, 2012, SEC File No. 001-32567).
10.58*	Form of Restricted Stock Award Agreement relating to Director Grants pursuant to Section 12 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on August 5, 2005, SEC File No. 001-32567).
10.59*	Form of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on August 23, 2005, SEC File No. 001-32567).
10.60*	Form II of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on November 8, 2005, SEC File No. 001-32567).
10.61*	Form of Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on March 12, 2007, SEC File No. 001-32567).
10.62*	Form of Amendment to Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on January 27, 2010, SEC File No. 001-32567).
10.63*	Form II of Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 27, 2010, SEC File No. 001-32567).
10.64*	Award Agreement between the Company and Paul Eisman, dated May 5, 2011, (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 9, 2011, SEC File No. 001-32567).
10.65*	Form of Award Agreement relating to Executive Officer Restricted Stock Grants pursuant to the Alon USA Energy, Inc. 2005 Amended and Restated Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on May 9, 2011, SEC File No. 001-32567).

Exhibit No.	Description of Exhibit
10.66	Stock Purchase Agreement, dated as of April 28, 2006, among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy, III and Mark R. Milano (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 2, 2006, SEC File No. 001-32567).
10.67	First Amendment to Stock Purchase Agreement, dated as of June 30, 2006, among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy III and Mark R. Milano (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on November 14, 2006, SEC File No. 001-32567).
10.68	Second Amendment to Stock Purchase Agreement, dated as of July 31, 2006, among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy III and Mark R. Milano (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on November 14, 2006, SEC File No. 001-32567).
10.69	Stock Purchase Agreement, dated May 7, 2008, between Valero Refining and Marketing Company and Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 13, 2008, SEC File No. 001-32567).
10.70	First Amendment to Stock Purchase Agreement, dated as of July 3, 2008, by and among Valero Refining and Marketing Company, Alon Refining Krotz Springs, Inc. and Valero Refining Company-Louisiana (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
10.71	Series A Preferred Stock Purchase Agreement, dated as of July 3, 2008, by and between Alon Refining Louisiana, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
10.72	Stockholders Agreement, dated as of July 3, 2008, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
10.73	Amended and Restated Stockholders Agreement dated as of March 31, 2009, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.88 to Form 10-K, filed by the Company on April 10, 2009, SEC File No. 001-32567).
10.74	First Amendment to Amended and Restated Stockholders Agreement dated as of December 31, 2009, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 5, 2010, SEC File No. 001-32567).
10.75	Offtake Agreement, dated as of July 3, 2008, by and between Valero Marketing and Supply Company and Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 10.9 to Form 10-Q, filed by the Company on August 8, 2008, SEC File No. 001-32567).
10.76†	Amended and Restated Supply and Offtake Agreement, dated May 26, 2010 by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company.
10.77	First Amendment to the Supply and Offtake Agreement, dated January 20, 2011, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 10, 2011, SEC File No. 001-32567).
10.78	Amended and Restated Second Amendment to the Supply and Offtake Agreement, dated March 1, 2011, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.3 to Form 10-Q, filed by the Company on May 10, 2011, SEC File No. 001-32567).
10.79	Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on November 7, 2011, SEC File No. 001-32567).
10.80†	Amendment, dated as of July 20, 2012, to the Amended and Restated Supply and Offtake Agreement, dated May 26, 2010, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company.
10.81	Amendment, dated as of February 1, 2013, to the Amended and Restated Supply and Offtake Agreement, dated May 26, 2010, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 10, 2013, SEC File No. 001-32567).
10.82†	Amended and Restated Supply and Offtake Agreement by and between Alon USA, LP and J. Aron & Company, dated March 1, 2011.

Exhibit No.	Description of Exhibit
10.83	Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon USA, LP and J.Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on November 11, 2011, SEC File No. 001-32567).
10.84†	Amendment, dated as of July 20, 2012, to the Amended and Restated Supply and Offtake Agreement by and between Alon USA, LP, and J. Aron & Company, dated March 1, 2011.
10.85	Amendment to Supply and Offtake Agreement dated as of February 1, 2013 between J. Aron & Company and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on May 10, 2013, SEC File No. 001-32567).
10.86†	Supply and Offtake Agreement by and between J. Aron & Company and Alon Supply, Inc., dated May 30, 2012.
10.87†	Amendment, dated as of July 20, 2012, to the Supply and Offtake Agreement, dated May 30, 2012, by and between Alon Supply, Inc., and J. Aron and Company.
10.88	Amendment, dated as of February 1, 2013, to the Supply and Offtake Agreement between J. Aron & Company and Alon Supply, Inc. (incorporated by reference to Exhibit 10.3 to Form 10-Q, filed by the Company on May 10, 2013, SEC File No. 001-32567).
10.89	Form of Series A Convertible Preferred Stock Purchase Agreement (incorporated by reference to Exhibit 10.105 to Form S-1/A, filed by the Company on October 22, 2010, SEC File No. 333-169583).
10.90	Warrant Agreement, dated March 14, 2011, between the Company and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.106 to Form 10-K, filed by the Company on March 15, 2011 SEC File No. 001-32567).
10.91	Form of Series B Convertible Preferred Stock Purchase Agreement (incorporated by reference to Exhibit 10.106 to Form 10-K, filed by the Company on March 13, 2012 SEC File No. 001-32567).
10.92	Omnibus Agreement by and among Alon USA Partners, LP, Alon USA Partners GP, LLC, Alon Assets, Inc. and Alon Energy, Inc., dated November 26, 2012 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.93	Services Agreement by and among Alon USA Partners, LP, Alon USA Partners GP, LLC by and Alon Energy, Inc., dated November 26, 2012 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.94	Tax Sharing Agreement by and among Alon USA Partners, LP and Alon USA Energy, Inc., dated November 26, 2012 (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.95	Distributor Sales Agreement by and among Alon USA Partners, LP and Southwest Convenience Stores, LLC, dated November 26, 2012 (incorporated by reference to Exhibit 10.4 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.96	Offtake Agreement by and among Alon USA, LP and Paramount Petroleum Corporation, dated November 26, 2012 (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.97	Contribution, Conveyance and Assumption Agreement by and among Alon Assets, Inc., Alon USA Partners GP, LLC, Alon USA Partners, LP, Alon USA Energy, Inc., Alon USA Refining, LLC, Alon USA Operating, Inc., Alon USA, LP and Alon USA GP, LLC, dated November 26, 2012 (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.98	Second Amended Revolving Credit Agreement, dated as of May 23, 2013, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 24, 2013, SEC File No. 001-32567).
10.99	Base Bond Hedge Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.100	Base Bond Hedge Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.101	Additional Bond Hedge Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.102	Additional Bond Hedge Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.4 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).

Exhibit No.	Description of Exhibit
10.103	Base Warrant Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.104	Base Warrant Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.105	Additional Warrant Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.7 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.106	Additional Warrant Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.8 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
21.1	Subsidiaries of Alon USA Energy, Inc.
23.1	Consent of KPMG LLP.
31.1	Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2	Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
100	The following financial information from Alon USA Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Balance Sheets, (ii) Statements of Operations, (iii) Statements of Comprehensive Income, (iv) Statement of Stockholders’ Equity, (v) Statements of Cash Flows and (vi) Notes to Financial Statements.

____________

* Identifies management contracts and compensatory plans or arrangements.

† Filed under confidential treatment request.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date:	March 13, 2014	By:	/s/ Paul Eisman
			Paul Eisman
			President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date:	March 13, 2014	By:	/s/ David Wiessman
			David Wiessman
			Executive Chairman of the Board
Date:	March 13, 2014	By:	/s/ Jeff D. Morris
			Jeff D. Morris
			Vice Chairman of the Board
Date:	March 13, 2014	By:	/s/ Paul Eisman
			Paul Eisman
			President and Chief Executive Officer
Date:	March 13, 2014	By:	/s/ Shai Even
			Shai Even
			Senior Vice President and Chief Financial Officer
			(Principal Accounting Officer)
Date:	March 13, 2014	By:	/s/ Itzhak Bader
			Itzhak Bader
			Director
Date:	March 13, 2014	By:
			Boaz Biran
			Director
Date:	March 13, 2014	By:	/s/ Shlomo Even
			Shlomo Even
			Director
Date:	March 13, 2014	By:	/s/ Ron W. Haddock
			Ron W. Haddock
			Director
Date:	March 13, 2014	By:	/s/ Yeshayuhu Pery
			Yeshayuhu Pery
			Director
Date:	March 13, 2014	By:	/s/ Zalman Segal
			Zalman Segal
			Director
Date:	March 13, 2014	By:	/s/ Avraham Baiga Shochat
			Avraham Baiga Shochat
			Director
Date:	March 13, 2014	By:	/s/ Oded Rubinstein
			Oded Rubinstein
			Director
Date:	March 13, 2014	By:
			Shraga F. Biran
			Director