Alon USA Energy, Inc. - FORM 10-K

Attached files

file	filename
EX-31.2 - CERTIFICATION - Alon USA Energy, Inc.	alj-ex312_20151231xq4.htm
EX-31.1 - CERTIFICATION - Alon USA Energy, Inc.	alj-ex311_20151231xq4.htm
EX-23.1 - AUDITOR CONSENT - Alon USA Energy, Inc.	alj-ex231_2015xconsent.htm
EX-21.1 - SUBSIDIARY LIST - Alon USA Energy, Inc.	alj-ex211_2015xlistofsubsi.htm
EX-32.1 - CERTIFICATION - Alon USA Energy, Inc.	alj-ex321_20151231xq4.htm

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, 2015



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: None.

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, 2015, the last day of the registrant’s most recently completed second fiscal quarter was $582,306,184.

The number of shares of the Registrant’s common stock, par value $0.01 per share, outstanding as of February 19, 2016, was 71,076,808.

Documents incorporated by reference: Proxy statement of the registrant relating to the registrant’s 2016 annual meeting of stockholders, which is incorporated into Part III of this Form 10-K.

TABLE OF CONTENTS



	Page
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES	1
ITEM 1A. RISK FACTORS	12
ITEM 1B. UNRESOLVED STAFF COMMENTS	23
ITEM 3. LEGAL PROCEEDINGS	23
ITEM 4. MINE SAFETY DISCLOSURES	23
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	24
ITEM 6. SELECTED FINANCIAL DATA	27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	28
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	57
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	58
ITEM 9A. CONTROLS AND PROCEDURES	58
ITEM 9B. OTHER INFORMATION	58
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	59
ITEM 11. EXECUTIVE COMPENSATION	59
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	59
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	59
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES	59
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	60

GLOSSARY OF TERMS

The following are definitions of certain industry terms used in this Annual Report on Form 10-K:

“2-1-1 crack spread” The approximate refining margin resulting from processing two barrels of crude oil to produce one barrel gasoline and one barrel of distillate.

“3-2-1 crack spread” The approximate refining margin resulting from processing three barrels of crude oil to produce two barrels of gasoline and one barrel of distillate.

“Alkylation” A process that chemically combines isobutane with other hydrocarbons through the control of temperature and pressure in the presence of an acid catalyst. This process produces alkylates, which have a high octane value and are blended into gasoline to improve octane values.

“Backwardation” A market is in backwardation when at a point in time the forward price is lower than the current (spot) price.

“Barrel” A common unit of measurement in the oil industry, which equates to 42 gallons.

“Biodiesel” A renewable fuel produced from vegetable oils or animal fats that can be blended with petroleum-derived diesel to produce biodiesel blends for use in diesel engines. Pure biodiesel is referred to as B100, whereas blends of biodiesel are referenced by how much biodiesel is in the blend (e.g., a B5 blend contains five volume percent biodiesel and 95 volume percent ULSD).

“Blendstocks” The various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel; these may include natural gasoline, fluid catalytic cracking unit or FCCU gasoline, ethanol, reformate or butane, among others.

“Bpd” An abbreviation for barrels per calendar day, which is defined by the EIA as the amount of input that a distillation facility can process under usual operating conditions reduced for regular limitations that may delay, interrupt, or slow down production such as downtime due to such conditions as mechanical problems, repairs, and slowdowns.

“Brent crude oil” A light sweet crude oil characterized by an API gravity of approximately 38 degrees, and a sulfur content of approximately 0.4 weight percent.

“Catalyst” A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.

“Contango” A market is in contango when at a point in time the forward price is higher than the current (spot) price.

“Cpg” An abbreviation for cents per gallon.

“Cracking” The process of breaking down larger hydrocarbon molecules into smaller molecules, using catalysts and/or elevated temperatures and pressures.

“Crack spread” A simplified calculation that measures the difference between the price for light products and crude oil.

“Delayed Coking Unit (Coker)” A refinery unit that processes (“cracks”) heavy oils, such as the bottom cuts of crude oil from the crude or vacuum units, to produce blendstocks for light transportation fuels or feedstocks for other units and petroleum coke.

“Distillates” Primarily diesel, kerosene and jet fuel.

“EPA” An abbreviation for the U.S. Environmental Protection Agency.

“Feedstocks” Petroleum products, such as crude oil, that are processed and blended into refined products.

“Fluid Catalytic Cracking” A process that breaks down larger, heavier, and more complex hydrocarbon molecules into simpler and lighter molecules (LPG, gasoline, LCO, etc.) through the use of a catalytic agent and is used to increase the yield of gasoline. Fluid catalytic cracking uses a catalyst in the form of very fine particles, which behave as a fluid when aerated with a vapor.

“Gulf Coast 2-1-1 high sulfur diesel crack spread” The 2-1-1 crack spread calculated using the market value of Gulf Coast conventional gasoline and Gulf Coast high sulfur diesel against the market value of LLS crude oil.

“Gulf Coast (WTI) 3-2-1 crack spread” The 3-2-1 crack spread calculated using the market value of Gulf Coast conventional gasoline and ultra-low sulfur diesel against the market value of NYMEX Cushing WTI.

“Heavy Crude Oil” Crude oil with an API gravity of 24 degrees or less. Heavy crude oil is typically sold at a discount to lighter crude oil.

“Heavy Fuel Oils, Residual Products, Internally Produced Fuel and Other” Products other than gasoline, jet fuel and diesel fuel produced in the refining process. These products include residual fuels, gas oils, propane, petroleum coke, asphalt and internally produced fuel.

“HLS” Heavy Louisiana Sweet crude oil; typical API gravity of 32.9° and sulfur content of 0.35%.

“Hydrocracking” A process that uses a catalyst to crack heavy hydrocarbon molecules in the presence of hydrogen. Major products from hydrocracking are distillates, naphtha, propane and gasoline components such as butane.

“Hydrotreating” A process that removes sulfur from refined products in the presence of catalysts and substantial quantities of hydrogen to reduce sulfur dioxide emissions that result from the use of the products.

“Isomerization” A process that alters the fundamental arrangement of atoms in the molecule without adding or removing anything from the original material. The process is used to convert normal butane into isobutane and normal pentane into isopentane and hexane into isohexane.

“Light Crude Oil” Crude oil with an API gravity greater than 24 degrees. Light crude oil is typically sold at a premium to heavy crude oil.

“Light/Medium/Heavy Crude Oil” Terms used to describe the relative densities of crude oil, normally represented by their API gravities. Light crude oils (those having relatively high API gravities) may be refined into a greater amount of valuable products and are typically more expensive than a heavier crude oil.

“LLS” Light Louisiana Sweet crude oil; typical API gravity of 37.9° and sulfur content of 0.34%;

“Naphtha” A hydrocarbon fraction that is used as a gasoline blending component, a feedstock for reforming and as a petrochemical feedstock.

“Nelson complexity” A measure of secondary conversion capacity of a refinery relative to its primary distillation capacity. Generally, more complex refineries have a higher index number.

“NYMEX” The New York Mercantile Exchange. A commodities futures exchange.

“Refined products” Petroleum products, such as gasoline, diesel and jet fuel, which are produced by a refinery.

“Refining margin” A metric used in the refining industry to assess a refinery’s product margins by comparing the difference between the price of refined products produced at the refinery and the price of crude oil required to produce those products.

“Reforming” A process that uses controlled heat and pressure with catalysts to rearrange certain hydrocarbon molecules into petrochemical feedstocks and higher octane stocks suitable for blending into finished gasoline.

“Renewable Fuels Standard 2 (RFS-2)” An EPA regulation promulgated pursuant to the Energy Independence and Security Act of 2007, which requires most refineries to blend increasing amounts of renewable fuels (including biodiesel and ethanol) with refined products.

“Renewable Identification Number (RINs)” A serial number assigned to a batch of biofuel for the purpose of tracking its production, use, and trading as required by the United States Environmental Protection Agency's Renewable Fuel Standard (RFS-2).

“Retail Fuel Margin” The margin on fuel products sold through our retail segment calculated as revenues less cost of sales. Cost of sales in fuel margin are based on purchases from our refining segment and third parties using average bulk market prices adjusted for transportation and other differentials.

“Sour crude oil” A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.

“Sweet crude oil” A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.

“Throughput” The volume processed through a unit or a refinery.

“Turnaround” A periodically required standard procedure to refurbish and maintain a refinery that involves the shutdown and inspection of major processing units and occurs every three to four years on industry average.

“Ultra-Low Sulfur Diesel” Diesel fuel produced with lower sulfur content to lower emissions, which is required for on-road use in the U.S.

“Utilization” Average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.

iii

“Vacuum Distillation” Distillation under reduced pressure, which lowers the boiling temperature of crude oil in order to distill crude oil components that have high boiling points.

“WTI” West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity between 39° and 41° and a sulfur content of approximately 0.3 weight percent that is used as a benchmark for other crudes.

“WTS” West Texas Sour crude oil, a sour crude oil, characterized by an API gravity between 30° and 33° and a sulfur content of approximately 1.28 weight percent that is used as a benchmark for other sour crudes.

“Yield” The percentage of refined products that is produced from crude oil and other feedstocks.

Table of Contents

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES.

Statements in this Annual Report on Form 10-K, including those in Items 1 and 2, “Business and Properties,” and Item 3, “Legal Proceedings,” that are not historical in nature should be deemed forward-looking statements that are inherently uncertain. See “Forward-Looking Statements” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of forward-looking statements and of factors that could cause actual outcomes and results to differ materially from those projected.

Company Overview

In this Annual Report, the words “Alon,” “we,” “our” and “us” or like terms 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 consolidated 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 Big Spring, Texas, with a crude oil throughput capacity of 73,000 barrels per day and an integrated wholesale marketing business. In addition, we directly own a crude oil refinery in Krotz Springs, Louisiana, with a crude oil throughput capacity of 74,000 bpd. We also own crude oil refineries in California, which have not processed crude oil since 2012. We are a leading marketer of asphalt, which we distribute primarily through asphalt terminals located predominately in the Southwestern and Western United States. We are the largest 7-Eleven licensee in the United States and operate approximately 300 convenience stores which also market motor fuels in Central and West 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 file annual, quarterly and current reports, 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 http://ir.alonusa.com as soon as reasonably practicable after we file with or furnish such material to the SEC. We will provide copies of our filings free of charge to our stockholders upon written 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 through our website:


•	Compensation Committee Charter;


•	Audit Committee Charter;


•	Nominating and Corporate Governance Committee Charter;


•	Corporate Governance Guidelines; and


•	Code of Business Conduct and Ethics.

Business

Our presentation of segment data reflects our following three operating segments: (i) refining and marketing, (ii) asphalt and (iii) retail. 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 a sour crude oil refinery located in Big Spring, Texas, a light sweet crude oil refinery located in Krotz Springs, Louisiana, and heavy crude oil refineries located in Paramount, Bakersfield and Long Beach, California (“California refineries”). Our California refineries have not processed crude oil since 2012 due to the high cost of crude oil relative to product yield and low asphalt demand. We refine crude oil into petroleum products, including various grades of gasoline, diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt, and other petroleum-based products, which are marketed primarily in the South Central, Southwestern and Western regions of the United States.

Table of Contents

Alon USA Partners, LP (NYSE: ALDW)

Alon owns the Big Spring refinery and its integrated wholesale marketing operations through the Partnership. As of December 31, 2015, 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 general partner interest in the Partnership, which is a non-economic interest. The Partnership is consolidated within our refining and marketing segment.

Big Spring Refinery

The Big Spring refinery has a crude oil throughput capacity of 73,000 bpd and is located on 1,306 acres in the Permian Basin in West Texas. Major processes at our Big Spring refinery include fluid catalytic cracking, naphtha reforming, vacuum distillation, hydrotreating, aromatic extraction and alkylation.

Our Big Spring refinery has a Nelson complexity of 10.5, which allows us the flexibility to process a variety of crudes into higher-value refined products. Our Big Spring refinery has a sulfur processing capability of approximately two tons per thousand bpd of crude oil capacity, which provides the capability to process significant volumes of high-sulfur, or sour, crude oil to produce a high percentage of light, high-value refined products. Our Big Spring refinery is also capable of processing significant volumes of light, sweet crude as market conditions dictate. All of the crude oil processed at our Big Spring refinery is West Texas crude oil based on Midland pricing, which has generally 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 products. This refinery typically converts approximately 90% of its feedstock into high-value products such as gasoline, diesel, jet fuel and petrochemicals, with the remaining 10% primarily converted to asphalt and liquefied petroleum gas. In 2015, this refinery achieved a liquid recovery of 100.2%.

Big Spring Refinery Raw Material Supply

West Texas crudes have historically been transported to Cushing for sale. Over the last few years, strong growth in Permian Basin oil production and logistical constraints with moving oil to end markets had depressed prices for Midland crudes resulting in significant discounts to WTI Cushing. However, new pipeline takeaway capacity to the Texas Gulf Coast has recently been added to alleviate those constraints. The lower price of crude during 2015 has reduced production growth in the Permian Basin, and existing takeaway capacity is sufficient for current oil production. As a result, discounts in Midland crudes relative to WTI Cushing have contracted.

The Big Spring refinery is the closest refinery to Midland, Texas, which allows us to efficiently source WTS and WTI Midland crudes. Additionally, the Big Spring refinery has the ability to source locally-trucked crudes, which enables us to better control quality and eliminate the cost of transporting the crude supply from Midland. During 2015, our Big Spring refinery’s total refinery throughput was comprised of 44.9% WTS, 51.6% WTI Midland and 3.5% blendstocks.

Our Big Spring refinery receives WTS and WTI crudes by truck from local gathering systems and regional common carrier pipelines, such as the Mesa Interconnect, Centurion, Sunrise and Navigator pipelines.

Other feedstocks, including butane, isobutane and asphalt blending components, are delivered by truck and railcar. A majority of the natural gas we use to run the refinery is delivered by a pipeline in which we own a 63.0% interest.

Big Spring Refinery Production

Transportation Fuels. We produce various grades of gasoline which comply with the EPA’s current ultra-low sulfur gasoline standard of 30 parts per million including boutique fuels supplied to the El Paso and Phoenix markets. We produce both on-road and off-road diesel which complies with the EPA’s ultra-low sulfur diesel standard of 15 ppm. Our jet fuel production conforms to the JP-8 grade military specifications.

Asphalt. Our asphalt facilities are capable of producing up to 30 different product formulations, including both polymer modified asphalt and ground tire rubber asphalt. Asphalt produced at the Big Spring refinery is sold 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.

Big Spring Refinery Transportation Fuel Marketing

We sell 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 Central and West Texas, Oklahoma, New Mexico and

Table of Contents

Arizona. We refer to our operations in these regions as our “physically integrated system” because we primarily supply our customers in this region with motor fuels produced at our Big Spring refinery and distributed through a network of pipelines and terminals that we own or access through leases or long-term throughput agreements.

Branded Transportation Fuel Marketing. We sell motor fuels under the Alon brand through various terminals to supply 633 locations, including our convenience stores. We provide substantially all of our branded customers motor fuels, brand support and payment processing services in addition to the license of the Alon brand name and associated trade dress. In 2015, we sold 324.6 million gallons of gasoline and 85.0 million gallons of diesel as branded fuels, which represented 56% of the gasoline and 23% of the diesel produced at our Big Spring refinery.

We supply substantially all of the retail segment’s motor fuel requirements, which are sold at market prices. In 2015, we sold 147.7 million gallons of gasoline and 25.7 million gallons of diesel to our retail convenience stores, which represented 26% of the gasoline and 7% of the diesel produced at our Big Spring refinery.

Unbranded Transportation Fuel Marketing. We sell motor fuels on an unbranded basis through terminals. Including purchases for resale, in 2015, we sold 168.2 million gallons of gasoline and 262.4 million gallons of diesel as unbranded fuels, which were largely sold through our physically integrated system. These unbranded fuel sales represented 29% of the gasoline and 72% of the diesel produced at our Big Spring refinery.

Jet Fuel Marketing. We market substantially all the jet fuel produced at our Big Spring refinery as JP-8 grade to the Defense Energy Supply Center (“DESC”). All DESC contracts are for a one-year term and are awarded through a competitive bidding process. We have traditionally bid for contracts to supply Dyess Air Force Base in Abilene, Texas, and Sheppard Air Force Base in Wichita Falls, Texas. Jet fuel production in excess of existing contracts is sold through unbranded terminal sales.

Product Supply Sales. We sell transportation fuel production in excess of our branded and unbranded marketing needs through bulk sales and exchange channels. These bulk sales and exchange arrangements are entered into with various oil companies and trading companies and are transported through a product pipeline network or truck deliveries. Our petrochemical feedstock and the other petroleum products we produce are sold to a wide customer base and transported by truck and railcars.

Distribution Network and Distributor Arrangements. We sell motor fuel to our retail locations and to 25 third-party distributors, who then supply and sell to retail outlets. The supply agreements we maintain with our third-party 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.

Big Spring Refined Product Pipelines

The product pipelines we utilize to deliver refined products from our Big Spring refinery are linked to the major third-party product pipelines in the geographic area around the 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 four product terminals in Big Spring, Abilene, and Wichita Falls, Texas and Duncan, Oklahoma to market transportation fuels produced at our Big Spring refinery. All four of these terminals are physically integrated with our Big Spring refinery through the product pipelines we utilize. The Big Spring, Abilene and Wichita Falls terminals are equipped with truck loading racks. The Duncan, Oklahoma terminal is 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.

Krotz Springs Refinery

The Krotz Springs refinery has a crude oil throughput capacity of 74,000 bpd with a Nelson complexity of 8.4 and is strategically located on 381 acres on the Atchafalaya River in central Louisiana. This location provides access to crude from barge, pipeline, railcar and truck. The refinery has direct access to the Colonial product pipeline system (“Colonial Pipeline”). This combination of logistics assets provides us with diversified access to locally-sourced, domestic and foreign crudes, as well as distribution of our products to markets throughout the Southern and Eastern United States and along the Mississippi and Ohio Rivers. Major processes at the Krotz Springs refinery include vacuum distillation, catalytic cracking, basic distillation and naphtha reforming to minimize low quality black oil production and to produce higher light product yields.

Our Krotz Springs refinery has the capability to process substantial volumes of low sulfur, or sweet, crude, which has historically accounted for 100% of the Krotz Springs refinery’s crude oil throughput. This refinery typically converts

Table of Contents

approximately 90% of its feedstock into high-value finished products such as gasoline and distillates, with the remaining 10% primarily converted to liquefied petroleum gas. This refinery generally achieves a high liquid recovery, which was 101.9% in 2015.

Krotz Springs Refinery Raw Material Supply

The Krotz Springs refinery has access to various types of domestic and foreign crudes via pipeline, barge, rail and truck rack delivery. We are capable of receiving LLS, HLS and foreign crudes from the EMPCo “Northline System.” The Northline System delivers LLS, HLS and foreign crude oils from the St. James, Louisiana, crude oil terminaling complex. Additionally, the Krotz Springs refinery has the ability to receive crude oil sourced from West Texas. This crude oil 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. As discounts in West Texas crude prices have narrowed, the Krotz Springs refinery has shifted its crude supply to rely less on West Texas crude. The Krotz Springs refinery also receives approximately 20% of its crude by barge and truck from inland Louisiana and Mississippi.

Krotz Springs Refinery Production

Our Krotz Springs refinery produces gasoline, high sulfur diesel, light cycle oil, jet fuel, petrochemical feedstocks, LPG and slurry oil.

Krotz Springs Refinery Transportation Fuel Marketing

We market transportation fuel production substantially through bulk sales and exchange channels. These bulk sales and exchange arrangements are entered into with various oil companies and trading companies and are transported to markets on the Mississippi River and the Atchafalaya River as well as to the Colonial Pipeline. Beginning in the fourth quarter of 2015, we began shipping and selling gasoline into wholesale markets in the Southern and Eastern United States using our status as a regular shipper on 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 us and our customers to the Southern and Eastern United States.

Krotz Springs Refinery Barge, Railcar and Truck

Products not shipped through the Colonial Pipeline, such as high sulfur diesel, are transported by 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 Napoleonville, 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 by truck for blending, and sell the isobutane and natural gasoline on a spot basis.

California Refineries

Our California refineries historically operated as one integrated refinery. However, due to the high cost of crude oil relative to product yield and low asphalt demand, our California refineries have not processed crude oil since 2012. The Paramount refinery is located on 63 acres in Paramount, California. The Long Beach refinery is located on 19 acres in Long Beach, California. The Bakersfield refinery is located on approximately 600 acres in Bakersfield, California. The California refineries have the capability to produce gasoline, distillates, vacuum gas oil and asphalt.

We own a minority interest in AltAir Paramount, LLC (“AltAir”), a renewable fuels project that is located at our Paramount refinery. Upon the achievement of certain operational milestones, this ownership can be converted into a majority interest. The project utilizes existing equipment at the Paramount refinery and newly installed equipment to convert tallow into renewable biofuels. These renewable biofuels are drop-in replacements for petroleum-based fuel, requiring no modification to factory-standard engines or aircraft, with which they are fully compatible. This fuel provides the same performance as conventional, petroleum-based jet fuel.

In the third quarter of 2014, we received a permit to construct a new 140,000 bpd rail unloading facility at the Bakersfield refinery and to modify the refinery to process light crude. The rail facility would be capable of receiving shipments of light Mid-Continent crudes or heavy crudes for use by third parties or by us upon the restart of the Bakersfield refinery. However, the reduction in crude prices and subsequent decrease in U.S. oil production has caused crude differentials to narrow. The rail facility would require a widening of current crude differentials to be economically viable.

Table of Contents

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. 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 Pipelines/Terminal

The California refineries utilize product pipelines, truck racks and terminals to distribute refined products. The Paramount and Long Beach refineries are connected by pipelines that we own or lease.

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.

Supply and Offtake Agreements

J. Aron and Company (“J. Aron”), through arrangements with various oil companies, is one of our largest suppliers of crude oil and the largest customer of refined products from our Big Spring, Krotz Springs and California refineries.

We have 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. 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.

For additional information on our Supply and Offtake Agreements, see Note 9 to the consolidated financial statements in Item 8, “Financial Statements and Supplementary Data,” of this Annual Report on Form 10-K.

Asphalt

We own or operate 11 asphalt terminals located in Texas (Big Spring), Washington (Richmond Beach), California (Paramount, Long Beach, Elk Grove, Mojave and Bakersfield), Arizona (Phoenix and Flagstaff) as well as asphalt terminals in which we own a 50% interest located in Fernley, Nevada, and Brownwood, Texas. The operations in which we have a 50% interest are recorded under the equity method of accounting, and the investments are included as part of total assets in the asphalt segment data.

We purchase non-blended asphalt from third parties in addition to non-blended asphalt produced at the Big Spring refinery. We market asphalt through our terminals as blended and non-blended 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.

Asphalt produced at our Big Spring refinery is transferred to our asphalt segment at prices substantially determined by reference to the cost of crude, which is intended to approximate wholesale market prices. We market asphalt primarily as paving asphalt to road and materials manufacturers and as ground tire rubber polymer modified or emulsion asphalt to highway construction/maintenance contractors. Sales of asphalt are seasonal with the majority of sales occurring between May and October.

Table of Contents

Retail

As of December 31, 2015, we operated 309 owned and leased convenience store sites located primarily in Central and West Texas and New Mexico. Our convenience stores typically offer various grades of gasoline, diesel, food products, food service, tobacco products, non-alcoholic and alcoholic beverages, general merchandise as well as money orders to the public.

In August 2015, we acquired 14 retail convenience stores in the Albuquerque, New Mexico area, which doubled the number of our fueling positions in the Albuquerque market.

The following table shows our owned and leased convenience stores by location:



Location	Owned	Leased	Total
Big Spring, Texas	6	1	7
Wichita Falls, Texas	9	2	11
Waco, Texas	10	—	10
Midland, Texas	10	7	17
Lubbock, Texas	17	4	21
Albuquerque, New Mexico	26	12	38
Odessa, Texas	13	22	35
Abilene, Texas	32	8	40
El Paso, Texas	13	70	83
Other locations in Central and West Texas	30	17	47
Total stores	166	143	309

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 January 2017.

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. 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 retail store operations.

Competition

The petroleum refining and marketing industry continues to be highly competitive. Our industry is impacted by competition from integrated multi-national oil companies including ExxonMobil, Chevron and Royal Dutch Shell. Because of their diversity, integration of operations and larger capitalization, these major competitors may have greater financial support and diversity with a potentially better ability to bear the economic risks, operating risks and volatile market conditions associated with the petroleum industry.

Refining and Marketing

Our principal competitors include major independent refining and marketing companies such as Valero, Phillips 66, HollyFrontier and Western Refining. Profitability in the refining and marketing industry depends on the difference between refined product prices and the prices for crude oil and other feedstocks, also referred to as refining margins. Refining margins are impacted by, among other things, levels of crude and refined product inventories, balance of supply and demand, utilization rates of refineries and global economic and political events.

All of our crude oil and feedstocks are purchased from third-party sources, while some of our vertically-integrated competitors have their own sources of crude oil that they may use to supply their refineries. However, our Big Spring refinery is in close proximity to Midland, Texas, which is the largest origination terminal for West Texas crude oil. We believe this provides us with transportation cost advantages.

The markets for our refined products are generally supplied by a number of competitors, including large integrated oil companies and independent refiners. These larger companies typically have greater resources and may have greater flexibility in responding to volatile market conditions or absorbing market changes.

The principal competitive factors affecting our marketing businesses are price and quality of products, reliability and availability of supply and location of distribution points.

Table of Contents

Asphalt

We compete in the asphalt market with various refiners including Valero, Tesoro, U.S. Oil, Western Refining, 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.

Retail

Our major retail competitors include CST Brands, Chevron, Sunoco LP (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. Additionally, national and regional grocery and dry goods retailers such as Wal-Mart, Kroger and Costco have motor fuel retail businesses. 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 compliance with these requirements. Over the next several years, our operations will have to meet new requirements recently promulgated by the EPA and the states and jurisdictions in which we operate, as well as requirements which may be promulgated in the future.

Fuels. The federal Clean Air Act and its implementing regulations require, among other things, significant reductions in the sulfur content in gasoline and diesel. 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 refinery currently meet the low sulfur gasoline and diesel 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. In April 2014, the EPA promulgated 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 volume refineries have until January 1, 2020 to meet the standard. The EPA has approved the Big Spring, Krotz Springs, Paramount and Bakersfield refineries as “small volume refineries” under the Tier 3 rule. 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.

The EPA has issued renewable fuel standards mandates, requiring refiners to blend renewable fuels into the transportation fuels they produce and sell in the United States. To the extent refiners do not or cannot blend renewable fuels into the transportation fuels they produce in the quantities required to satisfy their obligations under the RFS-2 program, those refiners must purchase RINs to demonstrate compliance. Under the RFS-2 program, the volume of renewable fuels that obligated parties are required to blend into their transportation fuels increases annually over time until 2022. The Big Spring and Krotz Springs refineries first became subject to the RFS-2 program in 2013, and the Krotz Springs refinery received a hardship exemption for 2013. The California refineries did not process crude oil during 2013-2015 and as a result were not subject to the RFS-2 requirements. The Big Spring refinery is able to blend renewable fuel into some of its transportation fuels, generating RINs for compliance. In 2015, we were able to meet 80% of the Big Spring refinery’s required renewable volume obligation using RINs separated from renewable fuel blending during the period. The Krotz Springs refinery sells substantially all of its transportation fuels subject to the RFS-2 program via the Colonial pipeline, which does not accept ethanol-blended products. As a result, we must purchase RINs to satisfy the resulting compliance obligation.

Table of Contents

2014-2016 and biomass-based diesel for 2017, the EPA articulated a policy to incentivize additional investments in renewable fuel blending and distribution infrastructure by increasing the price of RINs.

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, including recently promulgated regulations by the EPA. We cannot currently determine the amounts of such future expenditures.

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. 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.

In January 2015, California’s cap-and-trade program to limit emissions of GHG began to apply to California fuel suppliers whose annual emissions exceeded 25,000 metric tons of GHG in any year from 2011-2014. Under the program, covered entities must reduce the GHG emissions associated with their products or purchase GHG reduction credits.

In September 2015, California regulators re-adopted the state’s low-carbon fuel standard (“LCFS”) which requires fuel producers to reduce the carbon intensity of transportation fuels used in California by at least 10% by 2020. Under the program, fuel producers must reduce the carbon emissions associated with their products or purchase carbon reduction credits.

While it is possible that the federal government will adopt some form of federal mandatory cap-and-trade GHG emission reductions legislation in the future, the timing and specific requirements of any such legislation are uncertain at this time.

The EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act including rules that require a reduction in emissions of GHGs from motor vehicles and another rule that established GHG emissions thresholds that determine when certain stationary sources must obtain construction or operating permits under the Clean Air Act. Under these rules, facilities already subject to the Prevention of Significant Deterioration and Title V operating permitting process that increase their emissions of GHGs by 75,000 tons per year are required to limit GHG emissions through application of control technology, known as “Best Available Control Technology.”

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. In September 2014, the EPA indicated that the Petroleum Refinery Sector Risk and Technology Review, proposed in May 2014 to address air toxics and volatile organic compounds from refineries, may make it unnecessary for EPA to regulate GHG emissions from petroleum refineries at this time. The final rule, published in December 2015, places additional emission control requirements and work practice standards on FCCUs, storage tanks, flares, coking units and other equipment at petroleum refineries.

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. According to the EPA, as of July 2015, approximately 90% of the nation’s refinery capacity is under lodged or entered “global” settlements. The Big Spring refinery is currently in negotiations with the EPA under the initiative. 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. 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. These civil penalties will likely exceed $100,000 and other related costs that may be required under the settlement for pollution controls or environmentally beneficial projects could be significant.

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. The Krotz Springs refinery has completed its obligations under the consent decree other than ongoing reporting obligations.

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. The compliance date has been proposed as January 1, 2017, coincident with the compliance date in local flare Rule 4311, and the costs of any work related to this obligation are unknown at this time.

Table of Contents

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. 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. Texas submitted a state clean-air implementation plan, including the flexible permit provisions, to the EPA for reconsideration in accordance with the Fifth Circuit’s decision, made revisions requested by the EPA, and secured approval of its program from the EPA on July 20, 2015. Our Big Spring refinery will revise its permit as prescribed by the new final rule.

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 entered into consent decrees with several refining companies pertaining to flare efficiency.

In May 2013, the EPA issued a partial compliance evaluation report to the Big Spring refinery related to an inspection of the refinery’s compliance with the Clean Air Act’s Risk Management Program conducted in March 2013 and requested that we enter into a settlement agreement with the agency. Whether we will enter into a settlement and the costs of any such settlement or enforcement are not known at this time, but are not expected to be material.

Remediation Efforts. We are currently remediating historical soil and groundwater contamination at our Big Spring refinery and terminals system. We spent $1.2 million in 2015 for remediation costs, and we estimate an additional $1.7 million will be spent during 2016. We are also remediating historical soil and groundwater contamination at the Abilene, Southlake and Wichita Falls terminals that were in existence at the time they were acquired. As a result of the completed remediation efforts, we have submitted a request to TCEQ requesting closure of the wells at the Southlake terminal.

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. We also have remediation projects at the Long Beach refinery and Pipeline 145 that existed at the time of our acquisitions. In 2015, a total of $2.1 million was spent for all four of these remediation projects of which our portion was $1.3 million. We estimate that an additional $2.1 million will be spent in 2016 with our portion being $1.5 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 asphalt terminal. We spent $0.5 million in 2015 for remediation costs and we estimate an additional $0.6 million will be spent during 2016.

In conjunction with our acquisition of the Bakersfield refinery in June 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 were required to make indemnification claims to the prior owner by March 15, 2015. We spent $2.4 million in 2015 for these remediation costs, and we estimate that an additional $2.2 million will be spent during 2016. Additionally, the local Water Board has issued a Clean-up and Abatement Order to the Bakersfield refinery, and additional capital expenditures associated with the Order were completed in 2015.

In addition, a majority of our owned and leased convenience stores have underground gasoline and diesel 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 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.

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

Table of Contents

hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents.

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 non-renewal are met and we also comply with the prescribed notice requirements.

Employees

As of December 31, 2015, we had approximately 2,860 employees. Approximately 630 employees worked in our refining and marketing segment, of which approximately 490 were employed at our refineries and approximately 140 were employed at our corporate offices in Dallas, Texas. Approximately 80 employees worked in our asphalt segment and approximately 2,150 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 in April 2019. 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 and Insurance

Our principal properties are described above under the captions “Refining and Marketing,” “Asphalt” and “Retail” in the “Business” section of Item 1. We believe that our properties and 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, 2015, we were the lessee under a number of cancelable and non-cancelable leases for certain properties. For additional information on our leases, see Note 21 to the consolidated financial statements in Item 8, “Financial Statements and Supplementary Data,” of this Annual Report on Form 10-K.

Our property damage and business interruption insurance policies that cover our refineries and asphalt terminals have a combined limit of $950 million. Claims for physical damage at our refineries and asphalt terminals are subject to a $10 million deductible. Claims for business interruption losses are subject to a 45-day waiting period. We maintain third-party liability insurance policies that cover third-party claims with a $300 million limit, subject to a $5 million deductible.

Executive Officers of the Registrant

Our current executive officers and key employees (identified by an asterisk), their ages as of February 1, 2016, and their business experience during at least the past five years are set forth below.



Name	Age	Position
Paul Eisman	60	Chief Executive Officer and President
Shai Even	47	Senior Vice President and Chief Financial Officer
Claire A. Hart	60	Senior Vice President
Alan Moret	61	Senior Vice President of Supply
Michael Oster	44	Senior Vice President of Mergers and Acquisitions
Jimmy C. Crosby	56	Senior Vice President of Refining
James Ranspot	45	Senior Vice President, General Counsel and Secretary
Scott Rowe	57	Senior Vice President of Asphalt Marketing
Jeff Brorman*	47	Vice President of Refining — Big Spring
Gregg Byers*	61	Vice President of Refining — Krotz Springs
Kyle McKeen*	52	President and Chief Executive Officer of Alon Brands
Josef Lipman*	70	President and Chief Executive Officer of SCS

Table of Contents

Set forth below is a brief description of the business experience of each of the executive officers and key employees listed above.

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. Mr. Eisman also serves as a director of the general partner of the Partnership, since 2012, and AZZ Inc., which is listed on the NYSE, since January 2016.

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. Prior to joining Alon, Mr. Even served as Chief Financial Officer of DCL Technologies, Ltd. from 1996 to July 2003 and prior to that worked for KPMG LLP from 1993 to 1996. Mr. Even has also been a director of Alon Refining Krotz Springs, Inc. since July 2008 and Alon Brands, Inc. since November 2008. Mr. Even was selected to serve as a director of the general partner of the Partnership because of his financial education and expertise, financial reporting background, public accounting experience, management experience and detailed knowledge of our operations. Mr. Even stepped down as a director of the general partner of the Partnership in November 2012.

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.

Scott Rowe has served as our Senior Vice President, Asphalt Marketing, since joining Alon in 2014. Mr. Rowe has over 30 years of experience in the petroleum refining and marketing business, with most of his experience specific to asphalt. Prior to joining Alon, Mr. Rowe was the President of The Hudson Companies, a privately held asphalt terminaling company headquartered in Providence, Rhode Island and founded Black Creek Terminal, LLC. Previously Mr. Rowe held several positions in the petroleum industry, including that of Vice President of Asphalt Marketing for CITGO and various management roles at Koch Industries. Mr. Rowe has an extensive background in business development and acquisitions.

Jeff Brorman has served as our Vice President of Refining - Big Spring since March 2013, with responsibility for operations at the Big Spring refinery. 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.

Table of Contents

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.

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.

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, as has been the case in recent periods and may 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 and refined products. 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 in the United States;


•	refinery utilization rates;


•	infrastructure limitations;


•	the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to affect oil prices and maintain production controls;


•	the actions of customers and competitors;

Table of Contents


•	disruptions due to equipment interruption, pipeline disruptions or failure at our or third-party facilities and other factors affecting transportation infrastructure;


•	the effects of transactions involving forward contracts and derivative instruments and general commodities speculation;


•	the execution of planned capital projects, including the build out of additional pipeline infrastructure;


•	the effects and costs of compliance with current and future federal, state and local environmental, economic, safety and other laws, policies and regulations;


•	operating hazards, natural disasters, casualty losses and other matters beyond our control;


•	the impact of global economic conditions on our business; and


•	the development and marketing of alternative and competing fuels.

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 certain levels of 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 commodities, we have no control over the changing market value of these inventories. Our inventory is valued at the lower of cost or market value under the last-in, first-out (“LIFO”) inventory valuation methodology. As a result, if the market value of our inventory were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of sales. Our investment in inventory is affected by the general level of crude oil prices, and significant increases in crude oil prices could result in substantial working capital requirements to maintain inventory volumes. Changes in the value of our inventory or increases in the amount of our working capital necessary to maintain our inventory volumes could have a material adverse effect on our earnings, profitability and cash flows.

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. An adverse change in these differentials affecting one or more of our refineries could have a negative impact on our earnings.

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.

The addition of new takeaway capacity from the Permian Basin could adversely affect our crude costs.

Over the last two years, pipeline capacity additions and expansions have significantly increased takeaway capacity from the Permian Basin. Meanwhile, the lower crude price environment in 2015 has slowed production growth in the region. For these reasons, takeaway capacity from the Permian Basin is adequate for current oil production. As such, we may not be able to purchase WTS and WTI at discounted prices to Cushing as we have historically and any discount to Cushing may decrease, which could adversely impact our earnings and profitability.

Table of Contents

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 intended to mitigate our crack spread risk. 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 refineries, 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. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Quantitative and Qualitative Disclosures About Market Risk.”

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 summer months than during 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. This seasonality is most pronounced in our asphalt business. 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.

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 during times of intense price fluctuations 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 or other 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 oil 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

Table of Contents

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.

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.

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 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.

Table of Contents

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.

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.

A recession and credit crisis and related turmoil in the global financial system could have an adverse impact on our business, results of operations and cash flows.

Our business and profitability are affected by the overall level of demand for our products, which in turn is affected by factors such as overall levels of economic activity and business and consumer confidence and spending. Declines in global economic activity and consumer and business confidence and spending have in the past, and may in the future, significantly reduce the level of demand for our products, including by consumers and our wholesale customers. In the past, severe reductions in the availability and increases in the cost of credit have adversely affected our ability to fund our operations and operate our refineries at full capacity, and have adversely affected our operating margins. Together, these factors have had and may in the future have an adverse impact on our business, financial condition, results of operations and cash flows.

Our business is indirectly exposed to risks faced by our suppliers, customers and other business partners. The impact on these constituencies of the risks posed by a recession or credit crisis and related turmoil in the global financial system could include interruptions or delays in the performance by counterparties to our contracts, reductions and delays in customer purchases, delays in or the inability of customers to obtain financing to purchase our products and the inability of customers to pay for our products. Any of these events may have an adverse impact on our business, financial condition, results of operations and cash flows.

We depend upon our subsidiaries for cash to meet our obligations and pay any dividends, and we do not own 100% of the stock of our operating subsidiaries.

We are a holding company. Our subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or pay dividends to our stockholders depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends, tax sharing payments or otherwise. Our subsidiaries’ ability to make any payments will depend on their earnings, cash flows, the terms of their indebtedness, tax considerations and legal restrictions. One of our former executive officers, Mr. Morris, is party to a stockholder’s agreement with Alon Assets and us, pursuant to which we may elect or be required to purchase the shares owned by Mr. Morris in connection with put/call rights or rights of first refusal contained in the agreement. The purchase price for the shares is generally determined pursuant to certain formulas set forth in the stockholder’s agreement. 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 Alon USA Partners GP, LLC, our wholly-owned subsidiary, owns 100% of the non-economic general partner interests of the Partnership. To the extent the Partnership is unable to make distributions to its partners, we may be unable to pay any dividends.

Table of Contents

We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.

If we cannot generate sufficient cash flows or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations, comply with certain deadlines related to environmental laws, regulations and standards or pursue our business strategies, any of which could have a material adverse effect on our results of operations or liquidity. We have substantial short-term working capital needs and may have substantial long-term capital needs. Our short-term working capital needs are primarily related to financing our inventory and accounts receivable. Our long-term needs for cash include those to support ongoing capital expenditures for equipment maintenance and upgrades during turnarounds at our refineries and for costs of catalyst replacement and to complete our routine and normally scheduled maintenance, regulatory and security expenditures. In addition, from time to time, we are required to spend significant amounts for repairs when one or more processing units experience temporary shutdowns. We continue to utilize significant capital to upgrade equipment, improve facilities, and reduce operational, safety and environmental risks. We may incur substantial compliance costs in connection with any new or amended environmental, health and safety laws and regulations. Our liquidity will affect our ability to satisfy any of these needs.

The costs, scope, timelines and benefits of our refining projects may deviate significantly from our original plans and estimates.

We may experience unanticipated increases in the cost, scope and completion time for our improvement, maintenance and repair projects at our refineries. Refinery projects are generally initiated to increase the yields of higher-value products, increase our ability to process a variety of crude oils, increase production capacity, meet new regulatory requirements or maintain the safe and reliable operations of our existing assets. Equipment that we require to complete these projects may be unavailable to us at expected costs or within expected time periods. Additionally, employee or contractor labor expense may exceed our expectations. Due to these or other factors beyond our control, we may be unable to complete these projects within anticipated cost parameters and timelines. In addition, the benefits we realize from completed projects may take longer to achieve and/or be less than we anticipated. Our inability to complete and/or realize the benefits of refinery projects in a cost-efficient and timely manner could have a material adverse effect on our business, financial condition and results of operations.

Our arrangements with J. Aron expose us to J. Aron related credit and performance risk.

We have supply and offtake agreements with J. Aron, who is one of our largest suppliers of crude oil and the largest customer of refined products from our refineries. In the future, we could purchase up to 100% of our supply needs at each of our refineries from J. Aron pursuant to these agreements. Additionally, we are obligated to repurchase all consigned inventories and certain other inventories upon termination or expiration of these agreements, which may be terminated by J. Aron as early as May 2018. 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 or expiration of these agreements, which could have a material adverse effect on our 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 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 comply with environmental requirements, we may be subject to administrative, civil and criminal proceedings by state and federal authorities, as well as civil proceedings by non-governmental 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.

Table of Contents

negotiations with the EPA under the initiative. 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. 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. These civil penalties will likely exceed $100,000 and other related costs that may be required under the settlement for pollution controls or environmentally beneficial projects could be significant and collectively could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In July 2012, 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. 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. Texas submitted a state clean-air implementation plan, including the flexible permit provisions, to the EPA for reconsideration in accordance with the Fifth Circuit’s decision, made revisions requested by the EPA, and secured approval of its program from the EPA on July 20, 2015. We are presently assessing our Big Spring refinery’s air emissions permitting alternatives as a result of these developments, but intend to revise the permit as prescribed by the new final rule.

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 as early as January 1, 2017; however, approved small volume refineries have until January 1, 2020 to meet the standard. The EPA has approved the Big Spring, Krotz Springs, Paramount, and Bakersfield refineries as “small volume refineries” under the Tier 3 rule. We estimate that the capital investment associated with upgrades necessary to meet these new required sulfur levels will be less than $30 million. Also, the Petroleum Refinery Sector Risk and Technology Review, which was published in the Federal Register on December 1, 2015, places additional emission control requirements and work practice standards on FCCUs, storage tanks, flares, coking units and other equipment at petroleum refineries. We are currently assessing the costs of compliance with the EPA’s final rule. 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 carbon dioxide, methane and other 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 rules that require a reduction in emissions of GHGs from motor vehicles and another rule that established GHG emissions thresholds that determine when certain stationary sources must obtain construction or operating permits under the Clean Air Act. Under the rule, facilities already subject to the Prevention of Significant Deterioration and Title V operating permitting process that increase their emissions of GHGs by 75,000 tons per year are required to limit GHG emissions through application of control technology, known as “Best Available Control Technology.” 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 U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and a number of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or monitoring and reporting requirements, or result in reduced demand for refined petroleum products we produce. 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.

Table of Contents

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 $6.4 million in investigation and remediation expenses over the next 15 years in connection with historical soil and groundwater contamination at our Big Spring refinery and the Abilene, Southlake and Wichita Falls terminals, which we formerly owned and operated. We anticipate spending an additional $36.7 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. Joint and several strict liability may be incurred in connection with such releases of petroleum hydrocarbons, hazardous substances and/or wastes. Although we have sold two of our pipelines pursuant to a transaction with Sunoco, we have agreed, subject to certain limitations, to indemnify Sunoco for costs and liabilities that may be incurred by Sunoco as a result of environmental conditions existing at the time of the sale. 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 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 worker health and safety, environmental and other laws and regulations.

From time to time, we have been sued or investigated for alleged violations of worker health and 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 environmental and various other 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 worker health and safety. A violation of authorization or permit conditions or of 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 an adverse effect on our business, results of operations or cash flows.

Renewable fuels mandates may reduce demand for the petroleum fuels we produce, which could have a material adverse effect on our results of operations and financial condition.

The EPA has issued renewable fuel standards mandates, requiring refiners to blend renewable fuels into the transportation fuels they produce and sell in the United States. To the extent refiners do not or cannot blend renewable fuels in the transportation fuels they produce in the quantities required to satisfy their obligations under the RFS-2 program, those refiners must purchase RINs to demonstrate compliance. Under the RFS-2 program, the volume of renewable fuels that obligated parties are required to blend into their transportation fuels increases annually over time until 2022. As a result of receiving hardship relief made available to obligated parties meeting certain criteria, our Big Spring refinery first became subject to the RFS-2 program in 2013 and the Krotz Springs refinery first became subject to the program in 2014. The Big Spring refinery is able to blend renewable fuel into some of its transportation fuels, generating RINs for compliance. The Krotz Springs refinery sells substantially all of its transportation fuels subject to the RFS-2 program via the Colonial pipeline, which does not accept ethanol-blended products. As a result, we must purchase RINs to satisfy the resulting compliance obligation. Our total RINs costs for 2015 and 2014 were $35.1 million and $27.1 million, respectively.

In December 2015, the EPA published a final rule in the Federal Register establishing the renewable fuel volume mandates for 2014, 2015 and 2016, and the biomass-based diesel mandate for 2017. The volumes included in the EPA’s final rule increase each year, but are lower, with the exception of the volumes for biomass-based diesel, than the volumes required by the Clean Air Act. The EPA used its waiver authority to lower the volumes, but its decision to do so has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In addition, in the final rule establishing the renewable volume obligations for 2014-2016 and biomass-based diesel for 2017, the EPA articulated a policy to incentivize additional investments in renewable fuel blending and distribution infrastructure by increasing the price of RINs. The price of RINs has been extremely volatile and has increased over the last year. If the price of RINs increases, as predicted by the EPA, the impact could be material. We cannot predict the future prices of RINs and, thus, the expenses related to RINs compliance have the potential to be material. Existing laws and regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum fuels may increase. Because we do not produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products displaces an increasing volume of our refineries’ product pool. If the demand for our transportation fuel decreases as a result of the use of increasing volumes of renewable fuels, increased fuel economy as a result

Table of Contents

of new EPA fuel economy standards, or other factors, it could have an adverse effect on our business, results of operations and cash flows.

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 proposed 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. As these proposed position limit rules are not yet final, the effect of those provisions on us is uncertain at this time. The Dodd-Frank Act may also require compliance with margin requirements and with certain clearing and trade-execution requirements in connection with certain derivative activities, although the application of those provisions to us, and the impact of such provisions on 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 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 operating income could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties subject to such foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

We could encounter significant opposition to operations at our California refineries.

Our Paramount refinery is located in a residential area. The refinery is located near schools, apartment complexes, private homes and shopping establishments. In addition, our Long Beach refinery is located in close proximity to other commercial facilities, and our Bakersfield refinery is adjacent to newly developed commercial and retail property. Any loss of community support for our California refining operations could result in higher than expected expenses in connection with opposing any community action to restrict or terminate the operation of the refinery. Any community action in opposition to our current and planned use of the California refineries could have a material adverse effect on our business, results of operations and cash flows.

The occurrence of a release of hazardous materials or a catastrophic event affecting our California refineries could endanger persons living nearby.

Because our California refineries are located in residential areas, any release of hazardous material or catastrophic event could cause injuries to persons outside the confines of these refineries. In the event that persons were injured as a result of such an event, we would likely incur substantial legal costs as well as any costs resulting from settlements or adjudication of claims from such injured persons. The extent of these expenses and costs could be in excess of the limits provided by our insurance policies. As a result, any such event could have a material adverse effect on our business, results of operations and cash flows.

The dangers inherent in our operations could cause disruptions and expose us to potentially significant costs and 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

Table of Contents

failure of equipment at our or third-party facilities and other events beyond our control. The occurrence of any of these events 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.

In addition, certain of our refineries, pipelines and terminals are located in populated areas and any release of hazardous material or catastrophic event could affect our employees and contractors as well as persons outside our property. Our pipelines, trucks and rail cars carry flammable and toxic materials on public railways and roads and across populated and/or environmentally sensitive areas and waterways that could be severely impacted in the event of a release. An accident could result in significant personal injuries and/or cause a release that results in damage to occupied areas as well as damage to natural resources. It could also affect deliveries of crude oil to our refineries resulting in a curtailment of operations. The cost to remediate such an accidental release and address other potential liabilities as well as the costs associated with any interruption of operations could be substantial. Although we maintain significant insurance coverage for such events, it may not cover all potential losses or liabilities.

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, results of operations and cash flows.

We are subject to interruptions of supply and distribution as a result of our reliance on pipelines and barges 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 and barges. 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 and barges to transport crude oil or refined products is disrupted because of accidents, earthquakes, hurricanes, flooding, governmental regulation, terrorism, or other third-party action. Our prolonged inability to use any of the pipelines or barges 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.

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 and results of operations.

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 and results of operations. 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 and results of operations. 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 could have a material adverse effect on our business, financial condition and results of operations. In addition, disruption or significant increases in energy prices could result in government-imposed price controls.

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. Our property damage and business interruption insurance policies that cover our refineries and asphalt terminals have a combined limit of $950 million. Claims for physical damage at our refineries and asphalt terminals are subject to a $10 million deductible. The business interruption insurance policies that cover our Big Spring and Krotz Springs refineries have a $550 million limit and are subject to a 45-day waiting period. At all of our facilities, including the Big Spring and Krotz Springs refineries, we are fully exposed to all losses in excess of the applicable limits and sub-limits, a $10 million deductible due to property damage and for losses due to business interruptions of fewer than 45 days.

Table of Contents

We maintain third party liability insurance policies that cover third party claims with a $300 million limit subject to a $5 million deductible. We are fully exposed to third party claims in excess of the applicable limit and sub-limits and a $5 million deductible.

Additionally, 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, results of operations and cash flows.

We rely on information technology in our operations, and any material failure, inadequacy, interruption or security failure of that technology could harm our business.

We rely on information technology systems across our operations, including management of our supply chain, point of sale processing at our retail sites, and various other processes and transactions. We rely on commercially available systems, software, tools and monitoring to provide security for processing, transmission and storage of confidential customer information, such as payment card and personal credit information.

In addition, the systems currently used for certain transmission and approval of payment card transactions, and the technology utilized in payment cards themselves, may put certain payment card data at risk. These systems are determined and controlled by the PCI, and not by us. The regulatory environment surrounding information security and privacy is increasingly demanding, with the frequent imposition of new and constantly changing requirements. We have taken the necessary steps to assure the PCI compliance and Data Security Standards are being employed at all our locations. However, compliance with these requirements may result in cost increases due to necessary systems changes and the development of new administrative processes.

In recent years, several retailers have experienced data breaches resulting in the exposure of sensitive customer data, including payment card information. Any compromise or breach of our information and payment technology systems could cause interruptions in our operations, damage our reputation, reduce our customers' willingness to visit our sites and conduct business with us, or expose us to litigation from customers or sanctions from the PCI. In addition, a compromise of our internal data network at any of our refining or terminal locations may have disruptive impacts similar to that of our retail operations. These disruptions could range from inconvenience in accessing business information to a disruption in our refining operations. Cost increases may be incurred in this area to combat the continued escalation of cyber attacks and/or disruptive criminal activity.

Also, we utilize information technology systems and controls that monitor the movement of petroleum products through our pipelines and terminals. An undetected failure of these systems could result in environmental damage, operational disruptions, regulatory enforcement or private litigation. Further, the failure of any of our systems to operate effectively, or problems we may experience with transitioning to upgraded or replacement systems, could significantly harm our business and operations and cause us to incur significant costs to remediate such problems.

A significant interruption related to our information technology systems could adversely affect our business.

Our information technology systems and network infrastructure may be subject to unauthorized access or attack, which could result in a loss of sensitive business information, systems interruption, or the disruption of our business operations. There can be no assurance that our infrastructure protection technologies and disaster recovery plans can prevent a technology systems breach or systems failure, which could have a material adverse effect on our financial position or results of operations.

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.

Table of Contents

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, 2015, we employed approximately 200 people at our Big Spring refinery, approximately 135 of whom were covered by a collective bargaining agreement that expires in April 2019. 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 operations and financial condition.

It may be difficult to serve legal process on or enforce a United States judgment against certain of our directors.

Certain of our directors 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.

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 preclude recovery. Attempts to reach a commercial arrangement to resolve the dispute have been unsuccessful to this point. This matter is scheduled for trial in June 2016. Due to the uncertainties of litigation, we cannot predict with certainty the ultimate resolution of this lawsuit.

ITEM 4. MINE SAFTETY DISCLOSURES

None.

Table of Contents

PART II

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

Market Information

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

The following table sets forth the quarterly high and low sales prices of our common stock and dividends issued during 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		Dividends per Common Share

2015
Fourth Quarter	$	19.84	$	14.65	$	0.15
Third Quarter	23.29		16.95		0.15
Second Quarter (1)	19.09		15.41		0.15
First Quarter	17.15		10.28		0.10
2014
Fourth Quarter (2)	$	17.17	$	11.64	$	0.31
Third Quarter (3)	17.31		12.08		0.10
Second Quarter	17.58		12.43		0.06
First Quarter	17.04		12.92		0.06

_______________________


(1)	Beginning in the second quarter of 2015, our board of directors increased the regular quarterly cash dividend from $0.10 per common share to $0.15 per common share.


(2)	Dividends declared on our common stock during the fourth quarter of 2014 includes a special non-recurring dividend of $0.21 per common share.


(3)	Beginning in the third quarter of 2014, our board of directors increased the regular quarterly cash dividend from $0.06 per common share to $0.10 per common share.

On February 11, 2016, our board of directors approved the regular quarterly cash dividend of $0.15 per share on our common stock, payable on March 18, 2016, to holders of record at the close of business on February 26, 2016.

We intend to continue to pay quarterly cash dividends on our common stock at an annual rate of $0.60 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 and other factors our board of directors deems relevant.

Holders

As of February 19, 2016, there were 40 common stockholders of record.

Recent Sales of Unregistered Securities

In June 2012, Alon entered into amendments to shareholder agreements among Alon, Jeff Morris and Claire Hart, two of our current executives, 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 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.

Table of Contents

The following issuances of shares of our common stock occurred during the December 31, 2015 fiscal year pursuant to the agreements described above:



	Exchange Date	Number of Shares Issued
Jeff D. Morris	January 11, 2015	116,347
	April 11, 2015	116,347
	July 11, 2015	116,347
	October 11, 2015	116,347

Claire A. Hart	January 11, 2015	48,475
	April 11, 2015	48,475

The issuances of the shares of common stock to Messrs. Morris and Hart reflected above were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. The final exchange with respect to Mr. Hart occurred on April 11, 2015.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

Table of Contents

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, 2010 to December 31, 2015, 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.



	12/2010		12/2011		12/2012		12/2013		12/2014		12/2015
Alon	$	100.00	$	147.99	$	311.91	$	291.90	$	231.87	$	280.82
S&P 500	100.00		102.11		118.45		156.82		178.29		180.75
Peer Group	100.00		102.20		195.38		277.91		276.79		368.43

Table of Contents

ITEM 6. SELECTED FINANCIAL DATA.

The following table sets forth selected historical consolidated financial data as of and for each of the five years in the period ending December 31, 2015. The selected historical consolidated statement of operations data for the years ended December 31, 2015, 2014 and 2013, and the selected consolidated balance sheet data as of December 31, 2015 and 2014, are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The selected historical consolidated statement of operations data for the years ended December 31, 2012 and 2011, and the selected consolidated balance sheet data as of December 31, 2013, 2012 and 2011, are derived from our audited consolidated financial statements, which are not included in this Annual Report on Form 10-K.

The following selected historical consolidated financial 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,
	2015			2014		2013		2012		2011
	(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
Net sales	$	4,338,152		$	6,779,456	$	7,046,381	$	8,017,741	$	7,186,257
Loss on impairment of goodwill (1)	(39,028		)	—		—		—		—
Operating income	203,409			201,572		149,433		269,475		181,521
Net income available to stockholders	52,751			38,457		22,986		79,134		42,507
Earnings per share, basic	$	0.76		$	0.56	$	0.33	$	1.29	$	0.77
Weighted average shares outstanding, basic	69,772			68,985		63,538		57,501		55,431
Earnings per share, diluted	$	0.75		$	0.55	$	0.32	$	1.24	$	0.69
Weighted average shares outstanding, diluted	70,714			69,373		64,852		63,917		61,401
Cash dividends per common share	$	0.55		$	0.53	$	0.38	$	0.16	$	0.16

BALANCE SHEET DATA:
Cash and cash equivalents	$	234,127		$	214,961	$	224,499	$	116,296	$	157,066
Working capital	78,694			126,665		60,863		87,242		99,452
Total assets (2)	2,176,138			2,191,644		2,235,024		2,211,061		2,319,475
Total debt (2)	555,962			554,457		602,132		574,504		1,039,289
Total debt less cash and cash equivalents (2)	321,835			339,496		377,633		458,208		882,223
Total equity	664,160			673,778		625,404		621,186		395,784

_________________


(1)	During the year ended December 31, 2015, we recognized a goodwill impairment loss of $39,028 related to our California refining reporting unit.

(2)

During the year ended December 31, 2015, we adopted the FASB’s recently issued accounting guidance simplifying the presentation of debt issuance costs. As a result of adopting this guidance, debt issuance costs that had previously been included as deferred charges in our consolidated balance sheets have been reclassified as a direct deduction from the carrying value of the associated debt. These changes have been applied retrospectively to all periods presented.

Table of Contents

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

The following discussion of our financial condition and results of operations is provided as a supplement to, and should be read in conjunction with, our consolidated financial statements and the notes thereto included elsewhere in this Annual Report on Form 10-K and the other sections of this Annual Report on Form 10-K, including Items 1 and 2 “Business and Properties,” and Item 6 “Selected Financial Data.”

Forward-Looking Statements

Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.

Forward-looking statements reflect our current expectations of 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 WTI Cushing crude oil and WTS crude oil or WTI Midland crude oil;


•	changes in the spread between WTI Cushing crude oil and LLS crude oil;


•	changes in the spread between Brent crude oil and WTI Cushing crude oil;


•	changes in the spread between Brent crude oil and LLS crude oil;


•	the effects of transactions involving forward contracts and derivative instruments;


•	actions of customers and competitors;


•	changes in the ownership of our common stock by Delek US Holdings, Inc. (“Delek”), which may trigger change of control provisions contained in the agreements and instruments governing our convertible senior notes and the related purchased options and warrant transactions;

•

termination of our Supply and Offtake Agreements with J. Aron & Company (“J. Aron”), which include all of our refineries and certain of our asphalt terminals, under which J. Aron is one of our largest suppliers of crude oil and one of our largest customers of refined products. Additionally, upon termination of the Supply and Offtake Agreements, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron at then current market prices;


•	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 and cost of compliance with the RFS-2 program, including the availability, cost and price volatility of RINs;


•	the effects and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;


•	the effects of seasonality on demand for our products;

Table of Contents


•	the level of competition from other petroleum refiners;


•	operating hazards, accidents, fires, severe weather, floods and other natural disasters, casualty losses and other matters beyond our control, which could result in unscheduled downtime;


•	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.”

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. We own 100% of the general partner and 81.6% of the limited partner interests in Alon USA Partners, LP (the “Partnership”) (NYSE: ALDW), which owns a crude oil refinery in Big Spring, Texas, with a crude oil throughput capacity of 73,000 barrels per day and an integrated wholesale marketing business. In addition, we directly own a crude oil refinery in Krotz Springs, Louisiana, with a crude oil throughput capacity of 74,000 bpd. We also own crude oil refineries in California, which have not processed crude oil since 2012. We are a leading marketer of asphalt, which we distribute primarily through asphalt terminals located predominately in the Southwestern and Western United States. We are the largest 7-Eleven licensee in the United States and operate 309 convenience stores which also market motor fuels in Central and West Texas and New Mexico.

Refining and Marketing

We own the Big Spring refinery and its integrated wholesale marketing operations through the Partnership. Our marketing of transportation fuels produced at the Big Spring refinery is focused on Central and West Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in these regions as our “physically integrated system” because we primarily supply our customers in this region with motor fuels produced at our Big Spring refinery and distributed through a network of pipelines and terminals that we own or access through leases or long-term throughput agreements.

We sell motor fuels under the Alon brand through various terminals to supply 633 locations, including our retail segment convenience stores. We provide substantially all of our branded customers motor fuels, brand support and payment processing services in addition to the license of the Alon brand name and associated trade dress.

We market transportation fuel production from our Krotz Springs refinery substantially through bulk sales and exchange channels. These bulk sales and exchange arrangements are entered into with various oil companies and trading companies and are transported to markets on the Mississippi River and the Atchafalaya River as well as to the Colonial Pipeline.

Asphalt

We own or operate 11 asphalt terminals located in Texas (Big Spring), Washington (Richmond Beach), California (Paramount, Long Beach, Elk Grove, Mojave and Bakersfield), Arizona (Phoenix and Flagstaff) as well as asphalt terminals in which we own a 50% interest located in Fernley, Nevada, and Brownwood, Texas. The operations in which we have a 50% interest are recorded under the equity method of accounting and the investments are included as part of total assets in the asphalt segment data.

Table of Contents

Asphalt produced by our Big Spring refinery is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude, which is intended to approximate wholesale market prices. We market asphalt primarily as paving asphalt to road and materials manufacturers and as ground tire rubber polymer modified or emulsion asphalt to highway construction/maintenance contractors. Sales of asphalt are seasonal with the majority of sales occurring between May and October.

Retail

Our convenience stores typically offer various grades of gasoline, diesel, food products, food service, tobacco products, non-alcoholic and alcoholic beverages, general merchandise as well as money orders to the 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.

For additional information on each of our operating segments, see Items 1. and 2. “Business and Properties.”

Summary of 2015 Developments


•	We paid cash dividends on common stock totaling $0.55 per share, including an increase to our regular quarterly cash dividend from $0.10 per share to $0.15 per share during the second quarter.


•	During 2015, the Partnership generated cash available for distribution of $2.81 per unit.


•	In May 2015, the $240.0 million revolving credit facility was amended to, among other matters, extend the expiration date to May 2019.


•	In August 2015, we acquired 14 retail convenience stores in the Albuquerque, New Mexico area for $11.2 million, which included property, plant and equipment and related inventories.


•	In October 2015, our board of directors approved moving forward with detailed engineering and procurement of long lead equipment for the sulfuric acid alkylation unit at the Krotz Springs refinery. We expect this project to cost approximately $85.0 million and to generate annual EBITDA of $45.0 million once completed. We expect this project to be completed in 2017.


•	In November 2015, we completed the planned major turnaround at the Krotz Springs refinery.

•

2015 Operational and Financial Highlights

Operating income for 2015 was $203.4 million, compared to $201.6 million in 2014. Our operational and financial highlights for 2015 include the following:


•	Combined refinery average throughput for 2015 was 140,036 bpd, compared to a combined refinery average throughput of 136,378 bpd in 2014.

The Big Spring refinery average throughput for 2015 was 74,906 bpd compared to 66,033 bpd for 2014. During the second quarter of 2014, refinery throughput at the Big Spring refinery was reduced as we completed both the planned major turnaround and the vacuum tower project.

The Krotz Springs refinery average throughput for 2015 was 65,130 bpd compared to 70,345 bpd for 2014. During the fourth quarter of 2015, we completed the planned major turnaround at the Krotz Springs refinery, which reduced throughput during the period.

•

Refinery operating margin at the Big Spring refinery was $14.43 per barrel in 2015, compared to $16.69 per barrel in 2014. This decrease in operating margin was primarily due to the less favorable industry margin environment. All of the crude throughput at the Big Spring refinery was WTI Midland priced and WTS. The unfavorable contraction in the WTI Cushing to WTI Midland and the WTI Cushing to WTS spreads was greater than the improvement in the Gulf Coast 3/2/1 spread and the cost of crude benefit from the market moving from backwardation into contango.

Table of Contents

•

Refinery operating margin at the Krotz Springs refinery was $7.02 per barrel in 2015 compared to $7.57 per barrel for 2014. This decrease in operating margin was primarily due to the less favorable industry margin environment. The unfavorable contraction in the WTI Cushing to WTI Midland and the LLS to WTI Cushing spreads was greater than the improvement in the Gulf Coast 2/1/1 high sulfur diesel crack spread and the cost of crude benefit from the market moving from backwardation into contango.

•

The average WTI Cushing to WTI Midland spread for 2015 was $0.39 per barrel compared to $6.93 per barrel for 2014. The average WTI Cushing to WTS spread for 2015 was $(0.06) per barrel compared to $6.04 per barrel for 2014. The average Brent to WTI Cushing spread for 2015 was $3.54 per barrel compared to $6.19 per barrel for 2014. The average LLS to WTI Cushing spread for 2015 was $3.73 per barrel compared to $3.85 per barrel for 2014. The average Brent to LLS spread for 2015 was $0.14 per barrel compared to $3.45 per barrel for 2014.


•	The average Gulf Coast 3/2/1 crack spread was $17.02 per barrel for 2015 compared to $14.52 per barrel for 2014. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for 2015 was $10.81 per barrel compared to $9.76 per barrel for 2014.


•	The contango environment in 2015 created a cost of crude benefit of $1.01 per barrel compared to the backwardated environment creating a cost of crude detriment of $0.73 per barrel for 2014.


•	Asphalt margins in 2015 were $105.70 per ton compared to $43.86 per ton in 2014. The increase in asphalt margins was primarily due to a smaller reduction in blended asphalt sales price relative to the reduction in cost of blended asphalt during 2015 compared to 2014.


•	Retail fuel sales volume increased to 199.1 million gallons in 2015 from 192.6 million gallons in 2014. Merchandise margins increased to 31.9% in 2015 from 31.4% in 2014. Merchandise sales increased to $328.5 million in 2015 from $322.3 million in 2014.

Major Influences on Results of Operations

Refining and Marketing. Earnings and cash flows 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, not necessarily fluctuations in those prices, that affects our earnings.

In order to measure our operating performance, we compare our per barrel refinery operating margins to certain industry benchmarks. We calculate this margin for each refinery by dividing the refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales (exclusive of certain 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 Krotz Springs refinery’s operating margin to the Gulf Coast 2/1/1 high sulfur diesel crack spread. A Gulf Coast 2/1/1 high sulfur diesel 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 price of WTI Cushing crude oil and the price 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.

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. The Krotz Springs refinery’s crude oil input is primarily comprised of LLS and WTI Midland.

In addition, the location of the Big Spring refinery near Midland, the largest origination terminal for West Texas crude oil, provides reliable crude sourcing with a relatively low transportation cost. We are also able to source locally produced crude at Big Spring by truck, which tends to have cost and quality advantages. The WTI Cushing less WTI Midland spread represents the differential between the average per barrel price of WTI Cushing crude oil and the average per barrel price of WTI Midland crude oil. A widening of the WTI Cushing less WTI Midland spread will favorably influence the operating margin for both our

Table of Contents

Big Spring and Krotz Springs refineries. Alternatively, a narrowing of this differential will have an adverse effect on our operating margins.

Recently, the additional takeaway capacity moving crude from Midland to the Gulf Coast has caused a contraction of the WTI Cushing less WTI Midland spread. In addition, the relative small growth in WTS production compared to WTI production and the relative high demand for WTS has caused a contraction of the WTI Cushing less WTS spread.

Global product prices are influenced by the price of Brent crude which is a global benchmark crude. Global product prices influence 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. The Brent less WTI Cushing spread represents the differential between the average per barrel price of Brent crude oil and the average per barrel price of WTI Cushing crude oil. A widening of the spread between Brent and WTI Cushing will favorably influence both the Big Spring and Krotz Springs refineries’ operating margins. Also, the Krotz Springs refinery is influenced by the spread between Brent crude and LLS. The Brent less LLS spread represents the differential between the average per barrel price of Brent crude oil and the average per barrel price of LLS crude oil. A widening of the spread between Brent and LLS will 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.

The nature of our business requires us to maintain 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 last-in, first-out (“LIFO”) inventory valuation methodology, price fluctuations generally have little effect on our financial results.

Asphalt. Earnings and cash flows from our asphalt segment depend primarily upon the margin between the price at which we sell our asphalt and the price asphalt is purchased from third parties or the transfer price for asphalt produced at the Big Spring refinery. 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 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, 2015 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.

Maintenance and Turnaround impact on Crude Oil Throughput

During the year ended December 31, 2015, we completed the planned major turnaround at the Krotz Springs refinery. This planned downtime at our Krotz Springs refinery resulted in reduced refinery throughput and earnings during the period.

Table of Contents

During the year ended December 31, 2014, we completed both the planned major turnaround and the vacuum tower project at the Big Spring refinery, which increased our distillate yield, improved energy efficiency and allowed us to better optimize our crude slate. This planned downtime at our Big Spring refinery resulted in reduced refinery throughput and earnings during 2014.

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.

Certain Derivative Impacts

Included in cost of sales for the years ended December 31, 2015, 2014 and 2013 are realized and unrealized gains on commodity swaps of $59.2 million, $4.7 million and $23.9 million, respectively.

Impairment of Goodwill

Renewable Fuel Standards

The Big Spring and Krotz Springs refineries first became subject to the RFS-2 program in 2013. However, the Krotz Springs refinery received a hardship exemption for 2013, and as a result did not record costs associated with RINs for the year ended December 31, 2013.

Interest Expense Impacts

A component of our supply and offtake agreements fees, which affects our interest expense, is related to the crude oil price environment whereby a backwardated environment adds to our interest expense and a contango environment reduces our interest expense. Interest expense in 2015 compared to 2014 was lower primarily because crude oil prices moved from backwardation into contango.

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 13.50% Alon Refining Krotz Springs senior secured notes. During 2014, we repaid the remaining outstanding balance on the Alon Refining Krotz Springs senior secured notes.

Table of Contents

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.

Refining and marketing net sales consist of gross sales, net of customer rebates, discounts and excise taxes and include intersegment sales to our asphalt and retail segments, which are eliminated through consolidation of our financial statements. Asphalt net sales consist of gross sales, net of any discounts and applicable taxes. Our petroleum and asphalt product 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 and RINs, other raw materials and transportation costs, which include costs associated with crude oil and product pipelines which we utilize. 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.

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 wholesale marketing expenses are also included in SG&A expenses for the refining and marketing and asphalt segments.

Operating income. Operating income represents our net sales less our total operating costs and expenses.

Interest expense. Interest expense includes interest expense, letters of credit, financing charges related to the supply and offtake agreements, financing fees, and amortization of both original issuance discount and deferred debt issuance costs but excludes capitalized interest.

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED

Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for us and our three operating segments for the years ended December 31, 2015, 2014 and 2013. 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,
	2015			2014			2013
	(dollars in thousands, except per share data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	4,338,152		$	6,779,456		$	7,046,381
Operating costs and expenses:
Cost of sales	3,515,406			6,002,270			6,325,088
Direct operating expenses	255,534			281,686			287,752
Selling, general and administrative expenses (2)	200,195			170,139			168,172
Depreciation and amortization (3)	126,494			124,063			125,494
Total operating costs and expenses	4,097,629			6,578,158			6,906,506
Gain on disposition of assets	1,914			274			9,558
Loss on impairment of goodwill (4)	(39,028		)	—			—
Operating income	203,409			201,572			149,433
Interest expense (5)	(79,826		)	(111,143		)	(94,694		)
Equity earnings of investees	6,669			1,678			5,309
Other income, net	417			674			218
Income before income tax expense	130,669			92,781			60,266
Income tax expense	48,282			22,913			12,151
Net income	82,387			69,868			48,115
Net income attributable to non-controlling interest	29,636			31,411			25,129
Net income available to stockholders	$	52,751		$	38,457		$	22,986
Earnings per share, basic	$	0.76		$	0.56		$	0.33
Weighted average shares outstanding, basic (in thousands)	69,772			68,985			63,538
Earnings per share, diluted	$	0.75		$	0.55		$	0.32
Weighted average shares outstanding, diluted (in thousands)	70,714			69,373			64,852
Cash dividends per share	$	0.55		$	0.53		$	0.38
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	226,065		$	193,658		$	162,233
Investing activities	(160,011		)	(108,995		)	(51,441		)
Financing activities	(46,888		)	(94,201		)	(2,589		)
OTHER DATA:
Adjusted EBITDA (6)	$	374,103		$	327,713		$	270,896
Capital expenditures (7)	101,195			88,429			68,513
Capital expenditures for turnarounds and catalysts	35,348			62,473			8,617

Table of Contents



	As of December 31,
	2015		2014
BALANCE SHEET DATA (end of period):	(dollars in thousands)
Cash and cash equivalents	$	234,127	$	214,961
Working capital	78,694		126,665
Total assets (8)	2,176,138		2,191,644
Total debt (8)	555,962		554,457
Total debt less cash and cash equivalents (8)	321,835		339,496
Total equity	664,160		673,778


(1)	Includes excise taxes on sales by the retail segment of $77,860, $75,409 and $73,597 for the years ended December 31, 2015, 2014 and 2013, respectively.


(2)	Includes corporate headquarters selling, general and administrative expenses of $713, $705 and $721 for the years ended December 31, 2015, 2014 and 2013, respectively, which are not allocated to our three operating segments.


(3)	Includes corporate depreciation and amortization of $1,552, $2,399 and $2,673 for the years ended December 31, 2015, 2014 and 2013, respectively, which are not allocated to our three operating segments.


(4)	During the year ended December 31, 2015, we recognized a goodwill impairment loss of $39,028 related to our California refining reporting unit.


(5)	Interest expense for the year ended December 31, 2013 includes charges of $8,467 for a prepayment premium and write-offs of unamortized original issuance discount and debt issuance costs recognized for the prepayment of a portion of the Alon Refining Krotz Springs senior secured notes.


(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 $5,388, $2,756 and $881 for the years ended December 31, 2015, 2014 and 2013, respectively, which are not allocated to our three operating segments.

(8)

Table of Contents



REFINING AND MARKETING SEGMENT
	Year Ended December 31,
	2015			2014			2013
	(dollars in thousands, except per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	3,663,956		$	5,937,982		$	6,090,688
Operating costs and expenses:
Cost of sales	3,034,531			5,329,605			5,561,825
Direct operating expenses	227,517			241,833			244,759
Selling, general and administrative expenses	79,022			56,004			52,846
Depreciation and amortization	107,619			104,676			105,597
Total operating costs and expenses	3,448,689			5,732,118			5,965,027
Gain (loss) on disposition of assets	1,842			(1,255		)	7,359
Loss on impairment of goodwill (2)	(39,028		)	—			—
Operating income	$	178,081		$	204,609		$	133,020
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin – Big Spring (3)	$	14.43		$	16.69		$	14.59
Refinery operating margin – Krotz Springs (3)	7.02			7.57			6.16
Refinery direct operating expense – Big Spring (4)	3.62			4.39			4.53
Refinery direct operating expense – Krotz Springs (4)	4.03			4.12			4.09
Capital expenditures	$	73,429		$	63,148		$	40,272
Capital expenditures for turnarounds and catalysts	35,348			62,473			8,617
PRICING STATISTICS:
Crack spreads (3/2/1) (per barrel):
Gulf Coast	$	17.02		$	14.52		$	19.16
Crack spreads (2/1/1) (per barrel):
Gulf Coast high sulfur diesel	$	10.81		$	9.76		$	7.89
WTI Cushing crude oil (per barrel)	$	48.68		$	93.10		$	97.97
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland	$	0.39		$	6.93		$	2.59
WTI Cushing less WTS	(0.06		)	6.04			3.72
LLS less WTI Cushing	3.73			3.85			11.06
Brent less LLS	0.14			3.45			1.35
Brent less WTI Cushing	3.54			6.19			11.60
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	1.56		$	2.49		$	2.70
Gulf Coast ultra-low sulfur diesel	1.58			2.71			2.97
Gulf Coast high sulfur diesel	1.45			2.59			2.87
Natural gas (per MMBtu)	2.63			4.26			3.73

Table of Contents



THROUGHPUT AND PRODUCTION DATA: BIG SPRING REFINERY	Year Ended December 31,
THROUGHPUT AND PRODUCTION DATA: BIG SPRING REFINERY	2015			2014			2013
	bpd	%		bpd	%		bpd	%
Refinery throughput:
WTS crude	33,647	44.9		30,323	45.9		43,705	65.1
WTI crude	38,632	51.6		32,429	49.1		20,706	30.9
Blendstocks	2,627	3.5		3,281	5.0		2,692	4.0
Total refinery throughput (5)	74,906	100.0		66,033	100.0		67,103	100.0
Refinery production:
Gasoline	37,519	50.0		32,932	49.7		33,736	50.4
Diesel/jet	27,651	36.8		23,252	35.1		22,404	33.5
Asphalt	2,639	3.5		2,716	4.1		3,640	5.4
Petrochemicals	4,579	6.1		3,756	5.7		4,152	6.2
Other	2,678	3.6		3,565	5.4		3,033	4.5
Total refinery production (6)	75,066	100.0		66,221	100.0		66,965	100.0
Refinery utilization (7)		99.0	%		97.2	%		94.9	%



THROUGHPUT AND PRODUCTION DATA: KROTZ SPRINGS REFINERY	Year Ended December 31,
THROUGHPUT AND PRODUCTION DATA: KROTZ SPRINGS REFINERY	2015			2014			2013
	bpd	%		bpd	%		bpd	%
Refinery throughput:
WTI crude	22,408	34.4		28,373	40.3		29,580	45.7
Gulf Coast sweet crude	38,699	59.4		39,636	56.4		33,233	51.4
Blendstocks	4,023	6.2		2,336	3.3		1,892	2.9
Total refinery throughput (5)	65,130	100.0		70,345	100.0		64,705	100.0
Refinery production:
Gasoline	30,193	45.5		32,925	45.9		29,432	44.6
Diesel/jet	27,259	41.0		30,060	41.9		26,508	40.2
Heavy Oils	1,165	1.8		1,146	1.6		1,175	1.8
Other	7,781	11.7		7,579	10.6		8,857	13.4
Total refinery production (6)	66,398	100.0		71,710	100.0		65,972	100.0
Refinery utilization (7)		91.3	%		91.9	%		85.9	%

Table of Contents


(1)	Net sales include intersegment sales to our asphalt and retail segments at prices which approximate wholesale market prices. These intersegment sales are eliminated through consolidation of our financial statements.


(2)	During the year ended December 31, 2015, we recognized a goodwill impairment loss of $39,028 related to our California refining reporting unit.

(3)

Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales (exclusive of certain adjustments) attributable to each refinery by its throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margins to these crack spreads to assess our operating performance relative to other participants in our industry.

The refinery operating margin for the years ended December 31, 2015, 2014 and 2013 excludes realized and unrealized gains on commodity swaps of $59,215, $4,660 and $23,900, respectively. The refinery operating margin for the year ended December 31, 2015 also excludes insurance recoveries of $10,868.

For the year ended December 31, 2015, $3,941 related substantially to inventory adjustments was not included in cost of sales for the Big Spring refinery and the Krotz Springs refinery.


(4)	Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses at our refineries by the applicable refinery’s total throughput volumes.


(5)	Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.


(6)	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.


(7)	Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.

Table of Contents



ASPHALT SEGMENT
	Year Ended December 31,
	2015		2014			2013
	(dollars in thousands, except per ton data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	257,955	$	457,412		$	612,443
Operating costs and expenses:
Cost of sales (1) (2)	212,166		431,931			558,263
Direct operating expenses	28,017		39,853			42,993
Selling, general and administrative expenses	10,517		7,874			8,886
Depreciation and amortization	4,892		4,747			6,398
Total operating costs and expenses	255,592		484,405			616,540
Gain on disposition of assets	—		1,396			—
Operating income (loss) (5)	$	2,363	$	(25,597	)	$	(4,097	)
KEY OPERATING STATISTICS:
Blended asphalt sales volume (tons in thousands) (3)	451		516			701
Non-blended asphalt sales volume (tons in thousands) (4)	59		65			88
Blended asphalt sales price per ton (3)	$	486.34	$	571.18		$	573.87
Non-blended asphalt sales price per ton (4)	231.00		397.91			372.00
Asphalt margin per ton (5)	105.70		43.86			68.67
Capital expenditures	$	3,385	$	5,777		$	9,425


(1)	Net sales and cost of sales include asphalt purchases sold as part of the supply and offtake arrangement of $24,988, $136,818 and $177,425 for the years ended December 31, 2015, 2014 and 2013, respectively. 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 material 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.

Asphalt margin for the year ended December 31, 2015 excludes a loss of $8,118 resulting from a price adjustment related to asphalt inventory. This loss is included in operating income (loss) above.

Table of Contents



RETAIL SEGMENT
	Year Ended December 31,
	2015			2014			2013
	(dollars in thousands, except per gallon data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	774,435		$	939,684		$	944,193
Operating costs and expenses:
Cost of sales (2)	626,903			796,356			805,943
Selling, general and administrative expenses	109,943			105,556			105,719
Depreciation and amortization	12,431			12,241			10,826
Total operating costs and expenses	749,277			914,153			922,488
Gain on disposition of assets	72			134			2,199
Operating income	$	25,230		$	25,665		$	23,904
KEY OPERATING STATISTICS:
Number of stores (end of period) (3)	309			295			297
Retail fuel sales (thousands of gallons)	199,147			192,582			188,493
Retail fuel sales (thousands of gallons per site per month) (3)	58			57			55
Retail fuel margin (cents per gallon) (4)	21.3			21.6			19.3
Retail fuel sales price (dollars per gallon) (5)	$	2.24		$	3.20		$	3.33
Merchandise sales	$	328,505		$	322,262		$	316,432
Merchandise sales (per site per month) (3)	$	91		$	91		$	89
Merchandise margin (6)	31.9		%	31.4		%	32.1		%
Capital expenditures	$	18,993		$	16,748		$	17,935


(1)	Includes excise taxes on sales of $77,860, $75,409 and $73,597 for the years ended December 31, 2015, 2014 and 2013, 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, 2015, we had 309 retail convenience stores of which 298 sold fuel. At December 31, 2014, we had 295 retail convenience stores of which 283 sold fuel. At December 31, 2013, we had 297 retail convenience stores of which 285 sold fuel.

The 14 retail convenience stores acquired in mid-August 2015 have been included in the per site key operating statistics only for the period after acquisition.


(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 industry to measure in-store, or non-fuel, operating results.

Table of Contents

Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014

Net Sales

Consolidated. Net sales for the year ended December 31, 2015 were $4,338.2 million, compared to $6,779.5 million for the year ended December 31, 2014, a decrease of $2,441.3 million, or 36.0%. This decrease was primarily due to lower refined product prices, partially offset by higher combined refinery throughput.

Refining and Marketing Segment. Net sales for our refining and marketing segment were $3,664.0 million for the year ended December 31, 2015, compared to $5,938.0 million for the year ended December 31, 2014, a decrease of $2,274.0 million, or 38.3%. This decrease was primarily due to lower refined product prices, partially offset by higher combined refinery throughput for the year ended December 31, 2015 compared to the year ended December 31, 2014.

Combined refinery average throughput for the year ended December 31, 2015 was 140,036 bpd, consisting of 74,906 bpd at the Big Spring refinery and 65,130 bpd at the Krotz Springs refinery, compared to a combined refinery average throughput of 136,378 bpd for the year ended December 31, 2014, consisting of 66,033 bpd at the Big Spring refinery and 70,345 bpd at the Krotz Springs refinery. During the year ended December 31, 2015, we completed the planned major turnaround at the Krotz Springs refinery, which reduced throughput during the period. During the year ended December 31, 2014, refinery throughput at the Big Spring refinery was reduced as we completed both the planned major turnaround and the vacuum tower project.

Refined product prices decreased during the year ended December 31, 2015 compared to the year ended December 31, 2014. The average per gallon price of Gulf Coast gasoline for the year ended December 31, 2015 decreased $0.93, or 37.3%, to $1.56, compared to $2.49 for the year ended December 31, 2014. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the year ended December 31, 2015 decreased $1.13, or 41.7%, to $1.58, compared to $2.71 for the year ended December 31, 2014. The average per gallon price for Gulf Coast high sulfur diesel for the year ended December 31, 2015 decreased $1.14, or 44.0%, to $1.45, compared to $2.59 for the year ended December 31, 2014.

Asphalt Segment. Net sales for our asphalt segment were $258.0 million for the year ended December 31, 2015, compared to $457.4 million for the year ended December 31, 2014, a decrease of $199.4 million, or 43.6%. This decrease was primarily due to lower asphalt sales as part of the supply and offtake arrangement of $111.8 million, lower blended asphalt sales volumes and lower blended asphalt sales prices for the year ended December 31, 2015. The blended asphalt sales volume decreased 12.6% to 451 thousand tons for the year ended December 31, 2015 from 516 thousand tons for the year ended December 31, 2014. The average blended asphalt sales price decreased 14.9% to $486.34 per ton for the year ended December 31, 2015 from $571.18 per ton for the year ended December 31, 2014.

Retail Segment. Net sales for our retail segment were $774.4 million for the year ended December 31, 2015, compared to $939.7 million for the year ended December 31, 2014, a decrease of $165.3 million, or 17.6%. This decrease was primarily due to lower retail fuel sales prices, partially offset by increased retail fuel sales volumes and higher merchandise sales. The average retail fuel sales price decreased 30.0% to $2.24 per gallon for the year ended December 31, 2015 from $3.20 per gallon for the year ended December 31, 2014. Retail fuel sales volumes increased to 199.1 million gallons for the year ended December 31, 2015 from 192.6 million gallons for the year ended December 31, 2014. Merchandise sales increased to $328.5 million for the year ended December 31, 2015 from $322.3 million for the year ended December 31, 2014.

Cost of Sales

Consolidated. Cost of sales for the year ended December 31, 2015 were $3,515.4 million, compared to $6,002.3 million for the year ended December 31, 2014, a decrease of $2,486.9 million, or 41.4%. This decrease was primarily due to lower crude oil prices, lower blended asphalt sales volumes and lower retail fuel costs, partially offset by higher combined refinery throughput for the year ended December 31, 2015.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $3,034.5 million for the year ended December 31, 2015, compared to $5,329.6 million for the year ended December 31, 2014, a decrease of $2,295.1 million, or 43.1%. This decrease was primarily due to lower crude oil prices, partially offset by higher combined refinery throughput for the year ended December 31, 2015. The average price of WTI Cushing decreased 47.7% to $48.68 per barrel for the year ended December 31, 2015 from $93.10 per barrel for the year ended December 31, 2014.

Asphalt Segment. Cost of sales for our asphalt segment were $212.2 million for the year ended December 31, 2015, compared to $431.9 million for the year ended December 31, 2014, a decrease of $219.7 million, or 50.9%. This decrease was primarily due to decreased blended sales volumes, lower asphalt purchases as part of the supply and offtake arrangement of $111.8 million and lower costs of asphalt during the year ended December 31, 2015.

Table of Contents

Retail Segment. Cost of sales for our retail segment were $626.9 million for the year ended December 31, 2015, compared to $796.4 million for the year ended December 31, 2014, a decrease of $169.5 million, or 21.3%. This decrease was primarily due to lower retail fuel costs, partially offset by higher retail fuel sales volumes and merchandise costs for the year ended December 31, 2015.

Direct Operating Expenses

Consolidated. Direct operating expenses for the year ended December 31, 2015 were $255.5 million, compared to $281.7 million for the year ended December 31, 2014, a decrease of $26.2 million, or 9.3%.

Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the year ended December 31, 2015 were $227.5 million, compared to $241.8 million for the year ended December 31, 2014, a decrease of $14.3 million, or 5.9%. This decrease was primarily due to lower utility costs during the year ended December 31, 2015.

Asphalt Segment. Direct operating expenses for our asphalt segment for the year ended December 31, 2015 were $28.0 million, compared to $39.9 million for the year ended December 31, 2014, a decrease of $11.9 million, or 29.8%. This decrease was the result of a reduction in our fixed operating costs to better align our asphalt operations to the current level of asphalt demand during the year ended December 31, 2015.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the year ended December 31, 2015 were $200.2 million, compared to $170.1 million for the year ended December 31, 2014, an increase of $30.1 million, or 17.7%. This increase was primarily due to higher employee related costs, including employee retention costs and higher professional fees associated with recoveries from third parties that reduced cost of sales and income tax expense during the year ended December 31, 2015.

Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the year ended December 31, 2015 were $79.0 million, compared to $56.0 million for the year ended December 31, 2014, an increase of $23.0 million, or 41.1%. This increase was primarily due to higher employee related costs, including employee retention costs, and higher professional fees during the year ended December 31, 2015.

Asphalt Segment. SG&A expenses for our asphalt segment for the year ended December 31, 2015 were $10.5 million, compared to $7.9 million for the year ended December 31, 2014, an increase of $2.6 million, or 32.9%. This increase was primarily due to higher professional fees, partially offset by reduced employee related costs during the year ended December 31, 2015.

Retail Segment. SG&A expenses for our retail segment for the year ended December 31, 2015 were $109.9 million, compared to $105.6 million for the year ended December 31, 2014, an increase of $4.3 million, or 4.1%. This increase was primarily due to higher employee related costs including the increase in costs due to the addition of 14 stores during the year ended December 31, 2015.

Depreciation and Amortization

Depreciation and amortization for the year ended December 31, 2015 was $126.5 million, compared to $124.1 million for the year ended December 31, 2014, an increase of $2.4 million, or 1.9%.

Operating Income

Consolidated. Operating income for the year ended December 31, 2015 was $203.4 million, compared to $201.6 million for the year ended December 31, 2014, an increase of $1.8 million, or 0.9%. This increase was primarily due to higher combined refinery throughput, higher asphalt margins, lower utility costs and the impacts of commodity swaps, partially offset by lower refinery operating margins, a loss on impairment of goodwill of $39.0 million and higher SG&A expenses during the year ended December 31, 2015.

Refining and Marketing Segment. Operating income for our refining and marketing segment was $178.1 million for the year ended December 31, 2015, compared to $204.6 million for the year ended December 31, 2014, a decrease of $26.5 million, or 13.0%. This decrease was primarily due to lower refinery operating margins, a loss on impairment of goodwill of $39.0 million and higher SG&A expenses, partially offset by higher combined refinery throughput, lower utility costs and the impacts of commodity swaps during the year ended December 31, 2015. Operating income for the year ended December 31, 2015 includes gains on commodity swaps of $59.2 million, compared to $4.7 million for the year ended December 31, 2014.

Refinery operating margin at the Big Spring refinery was $14.43 per barrel for the year ended December 31, 2015, compared to $16.69 per barrel for the year ended December 31, 2014. This decrease in operating margin was primarily due to the less favorable industry margin environment. The unfavorable contraction in the WTI Cushing to WTI Midland and the WTI Cushing to WTS spreads was greater than the improvement in the Gulf Coast 3/2/1 spread and the cost of crude benefit from

Table of Contents

the market moving from backwardation into contango. The average WTI Cushing to WTI Midland spread for the year ended December 31, 2015 was $0.39 per barrel, compared to $6.93 per barrel for the year ended December 31, 2014. The average WTI Cushing to WTS spread for the year ended December 31, 2015 was $(0.06) per barrel, compared to $6.04 per barrel for the year ended December 31, 2014. The average Brent to WTI Cushing spread for the year ended December 31, 2015 was $3.54 per barrel, compared to $6.19 per barrel for the year ended December 31, 2014. The average Gulf Coast 3/2/1 crack spread increased 17.2% to $17.02 per barrel for the year ended December 31, 2015, compared to $14.52 per barrel for the year ended December 31, 2014. The contango environment for the year ended December 31, 2015 created a cost of crude benefit of $1.01 per barrel compared to the backwardated environment creating a cost of crude detriment of $0.73 per barrel for the year ended December 31, 2014.

Refinery operating margin at the Krotz Springs refinery was $7.02 per barrel for the year ended December 31, 2015, compared to $7.57 per barrel for the year ended December 31, 2014. This decrease in operating margin was primarily due to the less favorable industry margin environment. The unfavorable contraction in the WTI Cushing to WTI Midland and the LLS to WTI Cushing spreads was greater than the improvement in the Gulf Coast 2/1/1 high sulfur diesel crack spread and the cost of crude benefit from the market moving from backwardation into contango. The average Gulf Coast 2/1/1 high sulfur diesel crack spread increased 10.8% to $10.81 per barrel for the year ended December 31, 2015, compared to $9.76 per barrel for the year ended December 31, 2014. The average LLS to WTI Cushing spread for the year ended December 31, 2015 was $3.73 per barrel, compared to $3.85 per barrel for the year ended December 31, 2014. The average Brent to LLS spread for the year ended December 31, 2015 was $0.14 per barrel, compared to $3.45 per barrel for the year ended December 31, 2014.

Asphalt Segment. Operating income for our asphalt segment was $2.4 million for the year ended December 31, 2015, compared to an operating loss of $25.6 million for the year ended December 31, 2014, an increase of $28.0 million. This increase was primarily due to higher asphalt margins and lower direct operating expenses, partially offset by lower blended asphalt sales volumes and a loss of $8.1 million resulting from a price adjustment related to asphalt inventory for the year ended December 31, 2015. Asphalt margins for the year ended December 31, 2015 were $105.70 per ton, compared to $43.86 per ton for the year ended December 31, 2014. Operating loss for the year ended December 31, 2014 included the gain on the sale of our Willbridge, Oregon, asphalt terminal of $1.9 million.

Retail Segment. Operating income for our retail segment was $25.2 million for the year ended December 31, 2015, compared to $25.7 million for the year ended December 31, 2014, a decrease of $0.5 million, or 1.9%. This decrease was primarily due to lower retail fuel margins and higher SG&A expenses, partially offset by higher retail fuel sales volumes and higher merchandise margins for the year ended December 31, 2015. Retail fuel margins were 21.3 cents per gallon for the year ended December 31, 2015, compared to 21.6 cents per gallon for the year ended December 31, 2014. Merchandise margins were 31.9% for the year ended December 31, 2015, compared to 31.4% for the year ended December 31, 2014.

Interest Expense

Interest expense was $79.8 million for the year ended December 31, 2015, compared to $111.1 million for the year ended December 31, 2014, a decrease of $31.3 million, or 28.2%. A component of our supply and offtake agreements fees, which affects our interest expense, is related to the crude oil price environment whereby a backwardated environment adds to our interest expense and a contango environment reduces our interest expense. The decrease in interest expense for the year ended December 31, 2015 was primarily due to crude oil prices moving from backwardation in 2014 into contango in 2015 as well as reduced interest costs on our long-term debt obligations of $4.7 million during the year ended December 31, 2015.

Income Tax Expense

Income tax expense was $48.3 million for the year ended December 31, 2015, compared to $22.9 million for the year ended December 31, 2014. This increase resulted from our higher pre-tax income and an increase in the effective tax rate for the year ended December 31, 2015. Our effective tax rate was 36.9% for the year ended December 31, 2015, compared to an effective tax rate of 24.7% for the year ended December 31, 2014. The increase in our effective tax rate was primarily due to the loss on impairment of goodwill during the year ended December 31, 2015, which is not deductible for tax purposes. Our effective tax rate is lower than the statutory rate due to the impact of the non-controlling interest’s share of Partnership income.

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 limited partner interests held by the public. Additionally, net income attributable to non-controlling interest includes the proportional share of net income related to non-voting common stock of our subsidiary, Alon Assets, Inc., owned by non-controlling interest shareholders. Net income attributable to non-controlling interest was $29.6 million for the year ended December 31, 2015, compared to $31.4 million for the year ended December 31, 2014, a decrease of $1.8 million, or 5.7%.

Table of Contents

Net Income Available to Stockholders

Net income available to stockholders was $52.8 million for the year ended December 31, 2015, compared to $38.5 million for the year ended December 31, 2014, an increase of $14.3 million, or 37.1%. This increase was attributable to the factors discussed above.

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

Net Sales

Consolidated. Net sales for the year ended December 31, 2014 were $6,779.5 million, compared to $7,046.4 million for the year ended December 31, 2013, a decrease of $266.9 million. This decrease was primarily due to lower refined product prices, partially offset by higher combined refinery throughput.

Refining and Marketing Segment. Net sales for our refining and marketing segment were $5,938.0 million for the year ended December 31, 2014, compared to $6,090.7 million for the year ended December 31, 2013, a decrease of $152.7 million. This decrease was primarily due to lower refined product prices, partially offset by higher combined refinery throughput for the year ended December 31, 2014 compared to the year ended December 31, 2013.

Combined refinery average throughput for the year ended December 31, 2014 was 136,378 bpd, consisting of 66,033 bpd at the Big Spring refinery and 70,345 bpd at the Krotz Springs refinery, compared to a combined refinery average throughput of 131,808 bpd for the year ended December 31, 2013, consisting of 67,103 bpd at the Big Spring refinery and 64,705 bpd at the Krotz Springs refinery. The lower refinery throughput at the Big Spring refinery was the result of downtime necessary to complete both the planned turnaround and the vacuum tower project during the second quarter of 2014. Refinery throughput at the Krotz Springs refinery was lower for 2013 due to the unplanned shut down and repair of the reformer unit for approximately one month.

Refined product prices decreased during the year ended December 31, 2014 compared to the year ended December 31, 2013. The average per gallon price of Gulf Coast gasoline for the year ended December 31, 2014 decreased $0.21, or 7.8%, to $2.49, compared to $2.70 for the year ended December 31, 2013. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the year ended December 31, 2014 decreased $0.26, or 8.8%, to $2.71, compared to $2.97 for the year ended December 31, 2013. The average per gallon price for Gulf Coast high sulfur diesel for the year ended December 31, 2014 decreased $0.28, or 9.8%, to $2.59, compared to $2.87 for the year ended December 31, 2013.

Asphalt Segment. Net sales for our asphalt segment were $457.4 million for the year ended December 31, 2014, compared to $612.4 million for the year ended December 31, 2013, a decrease of $155.0 million, or 25.3%. This decrease was primarily due to lower asphalt sales as part of the supply and offtake arrangement of $40.6 million and decreased sales volumes associated with reduced asphalt demand in local markets in which we operate. The asphalt sales volume decreased 26.4% to 581 thousand tons for the year ended December 31, 2014 from 789 thousand tons for the year ended December 31, 2013.

Retail Segment. Net sales for our retail segment were $939.7 million for the year ended December 31, 2014, compared to $944.2 million for the year ended December 31, 2013, a decrease of $4.5 million, or 0.5%. This decrease was primarily due to lower retail fuel sales prices, partially offset by higher retail fuel sales volumes and merchandise sales.

Cost of Sales

Consolidated. Cost of sales for the year ended December 31, 2014 were $6,002.3 million, compared to $6,325.1 million for the year ended December 31, 2013, a decrease of $322.8 million, or 5.1%. This decrease was primarily due to lower crude oil prices, partially offset by higher combined refinery throughput.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $5,329.6 million for the year ended December 31, 2014, compared to $5,561.8 million for the year ended December 31, 2013, a decrease of $232.2 million, or 4.2%. This decrease was primarily due to lower crude oil prices, partially offset by higher combined refinery throughput and higher RINs costs. The average price of WTI Cushing decreased 5.0% to $93.10 per barrel for the year ended December 31, 2014 from $97.97 per barrel for the year ended December 31, 2013. Cost of sales for the year ended December 31, 2014 includes $27.1 million of costs to purchase RINs needed to satisfy our obligation to blend biofuels into the products we produce, compared to RINs costs of $14.9 million for the year ended December 31, 2013.

Asphalt Segment. Cost of sales for our asphalt segment were $431.9 million for the year ended December 31, 2014, compared to $558.3 million for the year ended December 31, 2013, a decrease of $126.4 million, or 22.6%. This decrease was primarily due to decreased sales volumes and lower asphalt purchases as part of the supply and offtake arrangement of $40.6 million, partially offset by higher costs of asphalt purchased during the year ended December 31, 2014 compared to the year ended December 31, 2013.

Table of Contents

Retail Segment. Cost of sales for our retail segment were $796.4 million for the year ended December 31, 2014, compared to $805.9 million for the year ended December 31, 2013, a decrease of $9.5 million, or 1.2%. This decrease was primarily due to lower retail fuel prices, partially offset by higher retail fuel sales volumes and merchandise costs.

Direct Operating Expenses

Consolidated. Direct operating expenses were $281.7 million for the year ended December 31, 2014, compared to $287.8 million for the year ended December 31, 2013, a decrease of $6.1 million, or 2.1%.

Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the year ended December 31, 2014 were $241.8 million, compared to $244.8 million for the year ended December 31, 2013, a decrease of $3.0 million, or 1.2%. This decrease was primarily due to lower major maintenance and insurance costs, partially offset by higher natural gas costs during the year ended December 31, 2014.

Asphalt Segment. Direct operating expenses for our asphalt segment for the year ended December 31, 2014 were $39.9 million, compared to $43.0 million for the year ended December 31, 2013, a decrease of $3.1 million, or 7.2%. This decrease was primarily due to reduced insurance costs during the year ended December 31, 2014.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the year ended December 31, 2014 were $170.1 million, compared to $168.2 million for the year ended December 31, 2013, an increase of $1.9 million, or 1.1%. This increase was primarily due to higher employee related costs during the year ended December 31, 2014.

Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the year ended December 31, 2014 were $56.0 million, compared to $52.8 million for the year ended December 31, 2013, an increase of $3.2 million, or 6.1%. This increase was primarily due to higher employee related costs during the year ended December 31, 2014.

Asphalt Segment. SG&A expenses for our asphalt segment for the year ended December 31, 2014 were $7.9 million, compared to $8.9 million for the year ended December 31, 2013, a decrease of $1.0 million, or 11.2%. This decrease was primarily due to lower corporate expense allocated to the asphalt segment, partially offset by higher employee related costs during the year ended December 31, 2014.

Retail Segment. SG&A expenses for our retail segment for the year ended December 31, 2014 were $105.6 million, compared to $105.7 million for the year ended December 31, 2013, a decrease of $0.1 million, or 0.1%.

Depreciation and Amortization

Depreciation and amortization for the year ended December 31, 2014 was $124.1 million, compared to $125.5 million for the year ended December 31, 2013, a decrease of $1.4 million, or 1.1%.

Operating Income

Consolidated. Operating income for the year ended December 31, 2014 was $201.6 million, compared to $149.4 million for the year ended December 31, 2013, an increase of $52.2 million. This increase was primarily due to higher refinery operating margins and lower direct operating expenses during the year ended December 31, 2014.

Refining and Marketing Segment. Operating income for our refining and marketing segment was $204.6 million for the year ended December 31, 2014, compared to $133.0 million for the year ended December 31, 2013, an increase of $71.6 million. This increase was primarily due to higher refinery operating margins and higher combined refinery throughput, partially offset by impacts from derivative transactions during the year ended December 31, 2014. Operating income for the year ended December 31, 2014 includes gains on commodity swaps of $4.7 million, compared to gains on commodity swaps of $23.9 million for the year ended December 31, 2013.

Refinery operating margin at the Big Spring refinery was $16.69 per barrel for the year ended December 31, 2014, compared to $14.59 per barrel for the year ended December 31, 2013. This increase in operating margin was primarily due to a widening of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread, partially offset by a lower Gulf Coast 3/2/1 crack spread. The average WTI Cushing to WTS spread for the year ended December 31, 2014 was $6.04 per barrel, compared to $3.72 per barrel for the year ended December 31, 2013. The average WTI Cushing to WTI Midland spread for the year ended December 31, 2014 was $6.93 per barrel, compared to $2.59 per barrel for the year ended December 31, 2013. The average Gulf Coast 3/2/1 crack spread decreased 24.2% to $14.52 per barrel for the year ended December 31, 2014, compared to $19.16 per barrel for the year ended December 31, 2013, which was primarily influenced by a decrease in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the year ended December 31, 2014 was $6.19 per barrel compared to $11.60 per barrel for the year ended December 31, 2013.

Table of Contents

Refinery operating margin at the Krotz Springs refinery was $7.57 per barrel for the year ended December 31, 2014, compared to $6.16 per barrel for the year ended December 31, 2013. This increase in operating margin was primarily due to a higher Gulf Coast 2/1/1 high sulfur diesel crack spread and a widening WTI Cushing to WTI Midland spread, partially offset by a narrowing LLS to WTI Cushing spread and the impact of RINs costs during the year ended December 31, 2014. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the year ended December 31, 2014 was $9.76 per barrel, compared to $7.89 per barrel for the year ended December 31, 2013, which was primarily influenced by an increase in the Brent to LLS spread. The average Brent to LLS spread for the year ended December 31, 2014 was $3.45 per barrel compared to $1.35 per barrel for the year ended December 31, 2013. The average LLS to WTI Cushing spread for the year ended December 31, 2014 was $3.85 per barrel, compared to $11.06 per barrel for the year ended December 31, 2013. The Krotz Springs refinery operating margin was also impacted by RINs costs of $21.4 million, or $0.83 per barrel of throughput, for the year ended December 31, 2014. The Krotz Springs refinery received an exemption from the RFS-2 requirements for 2013 and as a result did not record costs associated with RINs.

Asphalt Segment. Operating loss for our asphalt segment was $25.6 million for the year ended December 31, 2014, compared to $4.1 million for the year ended December 31, 2013, an increase in loss of $21.5 million. This increase in loss was primarily due to lower asphalt margins and lower asphalt sales volumes associated with reduced asphalt demand in local markets in which we operate. Asphalt margins for the year ended December 31, 2014 were $43.86 per ton compared to $68.67 per ton for the year ended December 31, 2013. Operating loss for the year ended December 31, 2014 included the gain on the sale of our Willbridge, Oregon, asphalt terminal of $1.9 million.

Retail Segment. Operating income for our retail segment was $25.7 million for the year ended December 31, 2014, compared to $23.9 million for the year ended December 31, 2013, an increase of $1.8 million. This increase was primarily due to higher retail fuel margins, higher retail fuel sales volumes and higher merchandise sales, partially offset by lower merchandise margins.

Interest Expense

Interest expense was $111.1 million for the year ended December 31, 2014, compared to $94.7 million for the year ended December 31, 2013, an increase of $16.4 million, or 17.3%. This increase was primarily due to higher financing costs associated with crude oil purchases under our supply and offtake agreements as a result of a backwardated crude oil market, partially offset by lower interest costs on the reduced balance of our long-term debt obligations during the year ended December 31, 2014. 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.

Income Tax Expense

Income tax expense was $22.9 million for the year ended December 31, 2014, compared to $12.2 million for the year ended December 31, 2013. This increase resulted from our higher pre-tax income for the year ended December 31, 2014 compared to the year ended December 31, 2013, and an increase in the effective tax rate. Our effective tax rate was 24.7% for the year ended December 31, 2014, compared to an effective tax rate of 20.2% for the year ended December 31, 2013. The lower effective tax rate compared to the statutory rate was due to the impact of the non-controlling interest’s share of Partnership income.

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 limited partner interests held by the public. Additionally, net income attributable to non-controlling interest includes the proportional share of net income related to non-voting common stock of our subsidiary, Alon Assets, Inc., owned by non-controlling interest shareholders. Net income attributable to non-controlling interest was $31.4 million for the year ended December 31, 2014, compared to $25.1 million for the year ended December 31, 2013, an increase of $6.3 million.

Net Income Available to Stockholders

Net income available to stockholders was $38.5 million for the year ended December 31, 2014, compared to $23.0 million for the year ended December 31, 2013, an increase of $15.5 million. This increase was attributable to the factors discussed above.

Table of Contents

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 and other credit lines.

We have agreements with J. Aron for the supply of crude oil that support the operations of all our refineries as well as certain 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.

As of December 31, 2015, our total cash and cash equivalents were $234.1 million and we had total debt of $556.0 million.

Cash Flows

The following table sets forth our consolidated cash flows for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
	(dollars in thousands)
Cash provided by (used in):
Operating activities	$	226,065		$	193,658		$	162,233
Investing activities	(160,011		)	(108,995		)	(51,441		)
Financing activities	(46,888		)	(94,201		)	(2,589		)
Net increase (decrease) in cash and cash equivalents	$	19,166		$	(9,538	)	$	108,203

Cash Flows Provided by Operating Activities

Net cash provided by operating activities for the year ended December 31, 2015 was $226.1 million, compared to $193.7 million for the year ended December 31, 2014. The increase in cash provided by operating activities of $32.4 million was primarily due to increased net income after adjusting for non-cash items of $47.2 million, reduced cash used for inventories of $12.3 million, reduced cash used for prepaid expenses and other current assets of $5.7 million, reduced cash used for other non-current assets of $15.7 million and reduced cash used for accounts payable and accrued liabilities of $13.4 million. These changes were partially offset by reduced cash collected on accounts receivable of $60.7 million and increased cash used for other non-current liabilities of $1.2 million.

Net cash provided by operating activities for the year ended December 31, 2014 was $193.7 million, compared to $162.2 million for the year ended December 31, 2013. The increase in cash provided by operating activities of $31.5 million was primarily due to higher net income after adjusting for non-cash items of $28.8 million, increased cash collected on accounts receivable of $119.1 million and a reduction in non-current liabilities of $47.0 million, partially offset by increased cash used for inventories of $50.2 million, increased cash used for other non-current assets of $33.5 million, increased cash used for accounts payable and accrued liabilities of $63.7 million and increased cash used for prepaid expenses and other current assets of $16.1 million.

Cash Flows Used In Investing Activities

Net cash used in investing activities was $160.0 million for the year ended December 31, 2015, compared to $109.0 million for the year ended December 31, 2014. The increase in cash used in investing activities of $51.0 million was primarily due to reduced cash proceeds from the disposition of assets of $38.1 million, increased cash used for our acquisition of 14 retail convenience stores of $11.2 million and increased contributions to our equity method investments of $14.6 million during the year ended December 31, 2015. These changes were partially offset by a decrease in capital expenditures and capital expenditures for turnarounds and catalysts of $14.4 million, which is related to the completion of planned major turnarounds at our Krotz Springs and Big Spring refineries during 2015 and 2014, respectively.

Table of Contents

Net cash used in investing activities was $109.0 million for the year ended December 31, 2014, compared to $51.4 million or the year ended December 31, 2013. The increase in cash used in investing activities of $57.6 million was primarily due to an increase in capital expenditures and capital expenditures for turnarounds and catalysts of $73.8 million, partially offset by increased cash proceeds from the disposition of assets of $13.9 million. The increase in capital expenditures and capital expenditures from turnarounds and catalysts is related to the completion of the planned major turnaround, including the vacuum tower revamp project, at our Big Spring refinery during the second quarter of 2014.

Cash Flows Used In Financing Activities

Net cash used in financing activities was $46.9 million for the year ended December 31, 2015, compared to $94.2 million for the year ended December 31, 2014. The decrease in cash used in financing activities of $47.3 million was primarily due to decreased net payments on debt related transactions of $48.6 million and increased cash provided on our inventory agreement transactions of $15.9 million, partially offset by increased payments to shareholders and non-controlling interests of $17.4 million.

Net cash used in financing activities was $94.2 million for the year ended December 31, 2014, compared to $2.6 million for the year ended December 31, 2013. The increase in cash used in financing activities of $91.6 million was primarily due to increased net payments on debt related transactions of $89.5 million and increased payments to shareholders and non-controlling interests of $4.1 million.

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.

Indebtedness

Alon USA Energy, Inc.

Convertible Senior Notes. In September 2013, we completed an offering of 3.00% unsecured convertible senior notes (the “Convertible Notes”) in the aggregate principal amount of $150.0 million, which mature in September 2018. Interest on the Convertible Notes is payable in arrears in March and September of each year. 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 Convertible Notes do not contain any maintenance financial covenants.

The holders of the Convertible Notes may convert at any time after June 15, 2018 if our common stock is above the conversion price. Prior to June 15, 2018 and after December 31, 2013, holders may convert if our common stock is 130% above the conversion price, 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 conversion rate of the Convertible Notes is subject to adjustment upon the occurrence of certain events, including cash dividend adjustments, but will not be adjusted for any accrued and unpaid interest. As of December 31, 2015, the adjusted conversion rate was 70.215 shares of our common stock per each $1 (in thousands) principal amount of Convertible Notes, equivalent to a per share conversion price of approximately $14.24, to reflect cash dividend adjustments. As of December 31, 2015, there have been no conversions of the Convertible Notes.

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). 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.

As of December 31, 2015, the if-converted value of the Convertible Notes exceeded the outstanding principal by $6.3 million.

Convertible Note Hedge Transactions

Table of Contents

adjustments, that initially underlie the Convertible Notes sold in the offering. As of December 31, 2015, the Purchased Options had an adjusted strike price of $14.24 per share of our common stock. The Purchased Options will expire in September 2018.

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. The Warrants allow the Hedge Counterparties to purchase up to 10,144,050 shares of our common stock, subject to customary anti-dilution adjustments. As of December 31, 2015, the Warrants had an adjusted strike price of $19.35 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.

Make-Whole Provision

In May 2015, Delek acquired approximately 48% of our outstanding common stock from Alon Israel Oil Company, Ltd. (“Alon Israel”). Delek agreed to a one year standstill provision limiting Delek’s ability to acquire greater than 49.99% of our outstanding common stock, with additional ownership above this threshold subject to the approval of Alon’s independent directors. If Delek were to acquire greater than 50.00% of our outstanding common stock, which would qualify as a fundamental change, it could require us to render a make-whole payment to holders of our Convertible Notes. As of December 31, 2015, the make-whole payment would be approximately $23.0 million, assuming full conversion of the Convertible Notes. In the event of a conversion, the Purchased Options will cover our obligation to render payment under the make-whole provision. Under these circumstances, we could also be required to settle the outstanding Warrants, which had a value of approximately $35.0 million as of December 31, 2015.

Letter of Credit Facility. In December 2013, we entered into a Letter of Credit Facility (the “Alon Energy Letter of Credit Facility”). 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. (“Alon Assets”) 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 Letter of Credit Facility matures November 2017 and contains certain restrictive covenants including maintenance financial covenants.

At December 31, 2015 and 2014, we had outstanding letters of credit under this facility of $60.6 million and $54.2 million, respectively.

Alon Energy Term Loan. In March 2014, we entered into a five-year Term Loan Agreement (“Alon Energy Term Loan”) for a principal amount of $25.0 million, maturing in March 2019. Repayments are monthly, commencing June 2014. Borrowings under this agreement incur interest at an annual rate equal to LIBOR plus a margin of 3.75%. We pledged 2,200,000 of the Partnership’s common units as collateral for the Alon Energy Term Loan. Additionally, Alon Assets guarantees all payments under the Alon Energy Term Loan. The Alon Energy Term Loan contains certain restrictive covenants including maintenance financial covenants.

At December 31, 2015 and 2014, the Alon Energy Term Loan had an outstanding balance, net of unamortized issuance costs, of $16.7 million and $21.9 million, respectively.

2015 Term Loan Credit Facility. In August 2015, we entered into a $3.0 million unsecured term loan (“2015 Term Loan”), which requires principal repayments of $0.1 million monthly until maturity in August 2020. Borrowings under the 2015 Term Loan bear interest at LIBOR plus 2.50% per annum. At December 31, 2015, the outstanding balance, net of unamortized issuance costs, was $2.7 million.

Alon USA Partners, LP

Partnership Term Loan Credit Facility. In November 2012, the Partnership entered into a $250.0 million 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. Based on Eurodollar market rates at December 31, 2015, the interest rate was 9.25% per annum.

Table of Contents

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, 2015 and 2014, the Partnership Term Loan had an outstanding balance, net of unamortized issuance costs and issuance discount, of $237.1 million and $238.0 million, respectively.

Revolving Credit Facility. We have a $240.0 million revolving credit facility (the “Alon USA, LP Credit Facility”) that will mature in May 2019. 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 3.00% per annum.

The Alon USA, LP Credit Facility is secured by a first lien on the Partnership’s cash, accounts receivables, inventories and related assets and a second lien on the Partnership’s fixed assets and other specified property. The Alon USA, LP Credit Facility contains certain restrictive covenants including maintenance financial covenants.

Borrowings of $55.0 million and $60.0 million were outstanding under the Alon USA, LP Credit Facility at December 31, 2015 and 2014, respectively. At December 31, 2015 and 2014, outstanding letters of credit under the Alon USA, LP Credit Facility were $48.6 million and $23.5 million, respectively.

Retail

Alon Retail Credit Agreement. In March 2014, Southwest Convenience Stores, LLC and Skinny’s LLC, (“Alon Retail”) entered into a credit agreement (“Alon Retail Credit Agreement”), maturing March 2019. The Alon Retail Credit Agreement includes an initial $110.0 million term loan and a $10.0 million revolving credit loan. The Alon Retail Credit Agreement also includes an accordion feature that provides for incremental term loans up to $30.0 million to fund store rebuilds, new builds and acquisitions. In August 2015, we borrowed $11.0 million using the accordion feature and amended the Alon Retail Credit Agreement to restore the undrawn amount of the accordion feature back to $30.0 million. The $11.0 million incremental term loan was used to fund our acquisition of 14 retail stores in New Mexico.

Borrowings under the Alon Retail Credit Agreement bear interest at a Eurodollar rate plus an applicable margin between 2.00% and 2.75% per annum, determined quarterly based upon Alon Retail’s leverage ratio. As of December 31, 2015, the applicable margin was 2.25% per annum. Principal payments are made in quarterly installments based on a 15-year amortization schedule.

Obligations under the Alon Retail Credit Agreement are secured by a first lien on substantially all of the assets of Alon Retail. The Alon Retail Credit Agreement also contains certain restrictive covenants including maintenance financial covenants.

At December 31, 2015 and 2014, the Alon Retail Credit Agreement had $104.5 million and $101.0 million, respectively, of outstanding term loans, net of unamortized issuance costs, and $10.0 million and $10.0 million, respectively, outstanding under the revolving credit loan.

Financial Covenants. We have certain credit facilities with maintenance financial covenants. At December 31, 2015, 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 and catalyst projects that our management is authorized to undertake in our annual capital budget. Additionally, our management assesses opportunities for growth and profit improvement projects on an ongoing basis and any related projects require further approval from our board of directors. Our total capital expenditure budget, including expenditures for turnarounds and catalysts, for 2016 is $101.0 million.

Table of Contents

The following table summarizes our expected capital expenditures for 2016 by operating segment (dollars in thousands):



	Refining and Marketing		Asphalt		Retail		Corporate		Consolidated Total
Sustaining maintenance and turnarounds and catalysts	$	34,475	$	4,790	$	8,360	$	6,900	$	54,525
Growth/profit improvement	29,100		—		—		—		29,100
Regulatory projects	17,375		—		—		—		17,375
Total	$	80,950	$	4,790	$	8,360	$	6,900	$	101,000

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

Information regarding our known contractual obligations of the types described below as of December 31, 2015 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	$	16,420	$	417,836	$	149,147	$	—	$	583,403
Operating lease obligations	27,290		43,489		18,632		37,137		126,548
Pipelines and terminals agreements (1)	44,543		73,460		64,883		12,285		195,171
Other commitments (2)	3,741		7,482		7,482		935		19,640
Total obligations	$	91,994	$	542,267	$	240,144	$	50,357	$	924,762

_____________________


(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 Holly Energy Partners, LP, as well as our minimum requirements with Sunoco Pipeline, LP, Centurion Pipeline L.P. and Navigator Energy Services, LLC.


(2)	Other commitments include refinery maintenance services costs.

As of December 31, 2015, 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

The preparation of financial statements in conformity with U.S. GAAP requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. See Note 2 - Basis of Presentation and Certain Significant Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our significant accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. Actual results could differ significantly from those estimates. We believe that the following discussion addresses our most critical accounting policies, which are those that are most important to the presentation of our financial condition and results of operations and requires management’s most difficult, subjective and complex judgments.

Table of Contents

LIFO Inventory Valuation. Crude oil, refined products, blendstocks and asphalt (including crude oil consignment inventory) are priced at the lower of cost or market. 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 inventory and increasing our cost of sales. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods.

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 if the plans are overfunded 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, 2015 and net periodic benefit expense for the year ending December 31, 2016 (in thousands):



	0.25-Percentage Point Change
Expected rate of return:
Effect on net periodic pension expense	$	222
Discount rate:
Effect on net periodic pension expense	559
Effect on projected benefit obligation	4,890

Environmental and Other Loss Contingencies. We expense or capitalize environmental expenditures depending on their future economic benefit. We expense costs 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. These estimates are 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, 2015, for those payments we considered fixed or reliably determinable, payments were discounted at a 2.47% 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 amount of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

Turnarounds and Catalysts Costs. Our refinery units require regular major maintenance and repairs that are commonly referred to as “turnarounds.” Catalysts used in certain refinery process units are typically replaced in conjunction with planned turnarounds. The required frequency of the maintenance varies by unit and by catalyst but generally is every three to five years. In order to minimize downtime during turnarounds, we often utilize contract labor as well as our maintenance personnel on a continuous 24 hour basis. Whenever possible, turnarounds are scheduled so that some units continue to operate while others are down for maintenance. We record the turnarounds and catalysts costs as deferred charges and amortize the deferred costs on a straight-line basis over the period of time estimated until the next turnaround occurs (generally 3 to 5 years).

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. An impairment loss would be recorded if it is determined that the assets are not recoverable and the carrying amount of the asset exceeds its fair value, which is based on discounted cash flows.

Table of Contents

In order to test our long-lived assets for recoverability, we must make estimates of projected cash flows related to the asset being evaluated that include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates and growth rates that could significantly impact the estimated fair value of the asset being tested for impairment. At December 31, 2015, the assets of the California reporting unit were tested for recoverability upon identifying that there was an impairment of goodwill. The projected cash flows exceeded the carrying value of the assets and therefore it was concluded that there was not an impairment of the long-lived assets.

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 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.

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. We use December 31, of each year as the valuation date for annual goodwill impairment testing purposes.

At December 31, 2015, we had two reporting units with goodwill: 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 2015 that contain goodwill were determined based on discounted cash flows with estimated cash flows based on internal forecasts of revenues, expenses and capital expenditures. Each reporting unit was evaluated separately. Cash flows were discounted at rates that approximate a market participant’s weighted average cost of capital; 11.4% for both California refining and California asphalt and 8.9% 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.

The volatility in the crude price environment caused a reduction in the growth rate for U.S. crude oil production, which subsequently caused a reduction in U.S. crude oil price discounts compared to waterborne crude prices. The economic impact of these factors caused us to delay planned projects within the California refining reporting unit. The delay in the planned projects had a negative effect on the timing of future cash flows, which is a key factor underlying the valuation of our reporting units. We compared the fair values derived from our discounted cash flows to the carrying values of the California refining reporting unit at December 31, 2015 and determined that the discounted cash flows do not exceed the carrying value of net assets. Consequently, based on this analysis, we recognized a goodwill impairment loss of $39,028 of the entire amount related to our California refining reporting unit for the year ended December 31, 2015.

We also compared the fair values of our California asphalt and Retail operations reporting units to their respective carrying values as of December 31, 2015 and concluded that the fair values of each of these reporting units substantially exceeded their carrying values. Therefore, no goodwill related to the California asphalt and Retail operations reporting units was impaired.

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 our cash flows beyond what is anticipated, we could conclude in future periods that additional impairment losses are required in order to reduce the carrying value of our goodwill, and, to a lesser extent, long-lived assets. Depending on the severity of the changes in the key factors underlying the valuation of our reporting units, such losses could be significant.

Table of Contents

Reconciliation of Amounts Reported Under Generally Accepted Accounting Principles

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

Adjusted EBITDA represents earnings before net income attributable to non-controlling interest, income tax expense, interest expense, depreciation and amortization, loss on impairment of goodwill and gain 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, loss on impairment of goodwill and gain 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, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
	(dollars in thousands)
Net income available to stockholders	$	52,751		$	38,457		$	22,986
Net income attributable to non-controlling interest	29,636			31,411			25,129
Income tax expense	48,282			22,913			12,151
Interest expense	79,826			111,143			94,694
Depreciation and amortization	126,494			124,063			125,494
Loss on impairment of goodwill	39,028			—			—
Gain on disposition of assets	(1,914		)	(274		)	(9,558		)
Adjusted EBITDA	$	374,103		$	327,713		$	270,896

Adjusted EBITDA does not exclude unrealized gains on commodity swaps of $7,937 and $3,778 for the years ended December 31, 2015 and 2014, respectively, which are included in net income available to stockholders. Additionally, Adjusted EBITDA does not exclude a loss of $8,118 for the year ended December 31, 2015 resulting from a price adjustment related to asphalt inventory.

Table of Contents

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. At December 31, 2015, the market value of refined products, asphalt and blendstock inventories was lower than LIFO costs by $0.8 million. At December 31, 2015, the market value of crude oil inventories exceeded LIFO costs, net of the fair value hedged items, by $18.5 million.

As of December 31, 2015, we held 0.6 million barrels of refined products, asphalt and blendstock and 0.9 million barrels of crude oil inventories valued under the LIFO valuation method. If the market value of refined products, asphalt and blendstock inventories would have been $1.00 per barrel lower, we would have recorded a lower of cost or market adjustment of $0.6 million to write-down the value of our inventory to market value, with an offsetting charge to cost of sales. If the market value of crude oil would have been $1.00 per barrel lower, the market value of crude oil inventories would have still exceeded LIFO costs, net of the fair value hedged item, by $17.6 million, requiring no inventory adjustment to be made.

All commodity derivative 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 in 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.

Table of Contents

The following table provides information about our derivative commodity instruments as of December 31, 2015:



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)	64,926		$	39.34	$	—	$	2,554		$	2,553		$	(1	)
Forwards-short (Crude)	(77,938	)	—		37.33		(2,909		)	(2,870		)	39
Forwards-long (Gasoline)	163,509		47.95		—		7,841			7,927			86
Forwards-short (Gasoline)	(326,651	)	—		49.26		(16,092		)	(16,074		)	18
Forwards-long (Distillate)	95,671		41.03		—		3,926			4,195			269
Forwards-short (Distillate)	(260,308	)	—		44.89		(11,685		)	(12,040		)	(355		)
Forwards-long (Jet)	99,436		46.16		—		4,590			4,340			(250		)
Forwards-short (Jet)	(114,926	)	—		43.90		(5,046		)	(5,004		)	42
Forwards-short (Slurry)	(36,512	)	—		17.39		(635		)	(598		)	37
Forwards-long (Catfeed)	162,788		45.63		—		7,428			7,673			245
Forwards-short (Catfeed)	(21,171	)	—		45.63		(966		)	(985		)	(19		)
Forwards-short (Slop)	(35,740	)	—		28.66		(1,024		)	(1,055		)	(31		)
Forwards-short (Propane)	(50,000	)	—		15.45		(773		)	(764		)	9
Forwards-long (Butane)	88,596		23.75		—		2,104			2,088			(16		)
Forwards-long (Asphalt)	23,555		45.11		—		1,063			1,085			22
Forwards-short (Asphalt)	(96,878	)	—		37.33		(3,616		)	(3,698		)	(82		)
Futures-long (Crude)	171,000		36.71		—		6,277			6,334			57
Futures-long (Gasoline)	80,000		53.06		—		4,245			4,271			26
Futures-short (Gasoline)	(281,000	)	—		52.69		(14,807		)	(15,000		)	(193		)
Futures-long (Distillate)	131,000		50.90		—		6,667			6,184			(483		)
Futures-short (Distillate)	(13,000	)	—		46.30		(602		)	(614		)	(12		)

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 long (LLS-WTI)	1,080,000		$	8.04	$	1.34	$	8,680		$	1,443		$	(7,237	)
Futures-swaps short (WTI-Brent)	(3,960,000	)	10.54		0.50		(41,719		)	(1,980		)	39,739
Futures-swaps long (WTI-Brent)	3,420,000		5.74		0.58		19,620			1,980			(17,640		)
Futures-swaps long (HO/ULSD)	30,000		4.83		2.73		145			82			(63		)

Interest Rate Risk

As of December 31, 2015, $433.1 million, excluding discounts and issuance costs, of our outstanding debt was subject to floating interest rates, of which $242.5 million was charged interest at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00%.

As of December 31, 2015, we had interest rate swap contracts, maturing March 2019, that effectively fix the variable interest component on approximately $80.4 million of the outstanding principal of the term loans within the Alon Retail Credit Agreement.

An increase of 1% in the variable rate on our indebtedness, after considering the instrument subject to a minimum interest rate and the interest rate swap contracts, would result in an increase to 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.

Table of Contents

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

None.

ITEM 9A. CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures

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

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate “internal control over financial reporting” (as defined in Rule 13a-15(f) under the Exchange Act) for Alon. The Company evaluated the effectiveness of its internal control over financial reporting based on the framework in the 2013 Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on that evaluation, our management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2015.

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 in Item 8 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, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

None.

Table of Contents

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Pursuant to General Instruction G(3) to Form 10-K, the information concerning our directors to be disclosed under “Corporate Governance Matters — The Board of Directors” in the proxy statement for our 2016 annual meeting of stockholders to be filed with the SEC within 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K (the “Proxy Statement”) is incorporated herein by reference. Certain information concerning our executive officers is to be disclosed 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 to be disclosed 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 to be disclosed 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.

Pursuant to General Instruction G(3) to Form 10-K, the information to be disclosed under “Executive Compensation” in the Proxy Statement is incorporated herein by reference.

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

Pursuant to General Instruction G(3) to Form 10-K, the information to be disclosed under “Security Ownership of Certain Beneficial Holders and Management” in the Proxy Statement is incorporated herein by reference. The information regarding our equity plans under which shares of our common stock are authorized for issuance as set forth under “Equity Compensation Plan Information” in the Proxy Statement is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

Pursuant to General Instruction G(3) to Form 10-K, the information to be disclosed 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.

Pursuant to General Instruction G(3) to Form 10-K, the information to be disclosed under “Independent Public Accountants” in the Proxy Statement is incorporated herein by reference.

Table of Contents

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
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 3.1 to Form 8-K, filed by the Company on February 4, 2016, 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 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).
4.4		Form of Certificate of Designation of the 8.5% 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).
4.5		Form of Certificate of Designation of the 8.5% 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		Form of Registration Rights Agreement among the Company and Subsidiary Shareholders (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on June 26, 2012, SEC File No. 001-32567).
10.8		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).
10.9		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).
10.10		Second Amendment, 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).

Table of Contents



Exhibit No.		Description of Exhibit
10.11		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).
10.12		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).
10.13		Second Amended and Restated Credit Agreement, dated as of March 14, 2014, among Southwest Convenience Stores, LLC, Skinny’s, LLC, as the Borrowers, Alon Brands, Inc., as a Guarantor, the lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender, LC Issuer, Syndication Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on March 26, 2014, 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 between Paul Eisman and Alon USA GP, LLC, dated May 11, 2015 (incorporated by reference to Exhibit 10.2 to Form 8-K filed by the Company on May 15, 2015, 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).
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).

Table of Contents



Exhibit No.		Description of Exhibit
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*		First Amendment to Amended and Restated Employment Agreement dated May 12, 2015 between Alon P. Moret and Alon USA GP, LLC, dated May 11, 2015 (incorporated by reference to Exhibit 10.4 to Form 8-K filed by the Company on May 15, 2015, SEC File No. 001-32567).
10.31*		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).
10.32*		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).
10.33*		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).
10.34*		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).
10.35*		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).
10.36*		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).
10.37*		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).
10.38*		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).
10.39*		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).
10.40*		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).
10.41†		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).
10.42*		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).
10.43*		Second Amendment to Shareholder Agreement, dated May 12, 201 5 among Alon USA Energy, Inc., Alon Assets, Inc., Jeff Morris and Jeff Morris/IRA (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on May 15, 2015, SEC File No. 001-32567).
10.44*		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).
10.45*		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).
10.46*		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).
10.47*		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).
10.48*		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).

Table of Contents



Exhibit No.		Description of Exhibit
10.49*		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).
10.50*		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).
10.51*		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).
10.52*		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).
10.53*		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).
10.54*		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).
10.55*		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).
10.56*		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).
10.57*		Second Amendment to Restricted Stock Award Agreement between Alon USA GP, LLC and Alan Moret, dated September 2, 2015 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on September 8, 2015, SEC File No. 001-32567).
10.58*		Restricted Stock Award Agreement between Alon USA Energy, Inc. and Paul Eisman, dated May 11, 2015 (incorporated by reference to Exhibit 10.3 to Form 8-K filed by the Company on May 15, 2015, SEC File No. 001-32567).
10.59		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).
10.60		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).
10.61		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).
10.62		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).
10.63		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).
10.64		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).
10.65†		Second Amended and Restated Supply and Offtake Agreement, dated February 1, 2015 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 8, 2015, SEC File No. 001-32567).
10.66†		Second Amended and Restated Supply and Offtake Agreement by and between Alon USA, LP and J. Aron & Company, dated February 1, 2015 (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on May 8, 2015, SEC File No. 001-32567).
10.67†		Amended and Restated Supply and Offtake Agreement by and between J. Aron & Company and Alon Supply, Inc., dated February 1, 2015 (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 8, 2015, SEC File No. 001-32567).

Table of Contents



Exhibit No.		Description of Exhibit
10.68		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).
10.69		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).
10.70		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).
10.71		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).
10.72		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).
10.73		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).
10.74		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).
10.75		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).
10.76		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).
10.77		Second Amendment to Second Amended and Restated Revolving Credit Agreement, dated May 6, 2015, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.4 to Form 10-Q filed by the Company on May 8, 2015, SEC File No. 001-32567).
10.78		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).
10.79		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).
10.80		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).
10.81		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).
10.82		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).
10.83		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).
10.84		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).
10.85		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.

Table of Contents



Exhibit No.		Description of Exhibit
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.
101		The following financial information from Alon USA Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2015, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statement of Stockholders’ Equity, (v) Consolidated Statements of Cash Flows and (vi) Notes to Consolidated Financial Statements.

___________


*	Identifies management contracts and compensatory plans or arrangements.


†	Filed under confidential treatment request.

Table of Contents

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, 2015 and 2014		F-4
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013		F-5
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2015, 2014, and 2013		F-6
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013		F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013		F-8
Notes to Consolidated Financial Statements		F-9

Table of Contents

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, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2015, 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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas

February 26, 2016

F-2

Table of Contents

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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) 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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) 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, 2015 and 2014, 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, 2015, and our report dated February 26, 2016 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Dallas, Texas

February 26, 2016

F-3

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands, except per share data)



	As of December 31,
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	234,127		$	214,961
Accounts and other receivables, net	119,171			153,859
Income tax receivable	3,741			9,196
Inventories	105,515			122,803
Deferred income tax asset	13,786			11,228
Prepaid expenses and other current assets	28,275			26,315
Total current assets	504,615			538,362
Equity method investments	42,811			25,376
Property, plant and equipment, net	1,380,202			1,372,344
Goodwill	62,885			101,913
Other assets, net	185,625			153,649
Total assets	$	2,176,138		$	2,191,644
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	315,721		$	292,217
Accrued liabilities	93,780			104,391
Current portion of long-term debt	16,420			15,089
Total current liabilities	425,921			411,697
Other non-current liabilities	165,935			182,659
Long-term debt	539,542			539,368
Deferred income tax liability	380,580			384,142
Total liabilities	1,511,978			1,517,866
Commitments and contingencies (Note 21)
Stockholders’ equity:
Preferred stock, par value $0.01, 15,000,000 shares authorized; 0 and 68,180 shares issued and outstanding at December 31, 2015 and 2014, respectively	—			682
Common stock, par value $0.01, 150,000,000 shares authorized; 70,960,461 and 69,606,944 shares issued and outstanding at December 31, 2015 and 2014, respectively	710			696
Additional paid-in capital	526,035			517,127
Accumulated other comprehensive loss, net of tax	(28,808		)	(8,458		)
Retained earnings	141,201			126,851
Total stockholders’ equity	639,138			636,898
Non-controlling interest in subsidiaries	25,022			36,880
Total equity	664,160			673,778
Total liabilities and equity	$	2,176,138		$	2,191,644

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

F-4

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands, except per share data)



	Year Ended December 31,
	2015			2014			2013
Net sales (1)	$	4,338,152		$	6,779,456		$	7,046,381
Operating costs and expenses:
Cost of sales	3,515,406			6,002,270			6,325,088
Direct operating expenses	255,534			281,686			287,752
Selling, general and administrative expenses	200,195			170,139			168,172
Depreciation and amortization	126,494			124,063			125,494
Total operating costs and expenses	4,097,629			6,578,158			6,906,506
Gain on disposition of assets	1,914			274			9,558
Loss on impairment of goodwill	(39,028		)	—			—
Operating income	203,409			201,572			149,433
Interest expense	(79,826		)	(111,143		)	(94,694		)
Equity earnings of investees	6,669			1,678			5,309
Other income, net	417			674			218
Income before income tax expense	130,669			92,781			60,266
Income tax expense	48,282			22,913			12,151
Net income	82,387			69,868			48,115
Net income attributable to non-controlling interest	29,636			31,411			25,129
Net income available to stockholders	$	52,751		$	38,457		$	22,986
Earnings per share, basic	$	0.76		$	0.56		$	0.33
Weighted average shares outstanding, basic (in thousands)	69,772			68,985			63,538
Earnings per share, diluted	$	0.75		$	0.55		$	0.32
Weighted average shares outstanding, diluted (in thousands)	70,714			69,373			64,852
Cash dividends per share	$	0.55		$	0.53		$	0.38

_________________


(1)	Includes excise taxes on sales by the retail segment of $77,860, $75,409 and $73,597 for the years ended December 31, 2015, 2014 and 2013, respectively.

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

F-5

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)



	Year Ended December 31,
	2015			2014			2013
Net income	$	82,387		$	69,868		$	48,115
Other comprehensive income (loss):
Postretirement benefit plans:
Unrealized gain (loss) arising during the year related to:
Net actuarial gain (loss)	357			(16,498		)	15,610
Curtailment	—			—			126
(Gain) loss reclassified to earnings:
Amortization of net actuarial loss (1)	4,226			3,466			4,071
Amortization of prior service credit (1)	(364		)	(364		)	(51		)
Net gain (loss), before tax	4,219			(13,396		)	19,756
Income tax expense (benefit)	1,540			(4,559		)	7,224
Net gain (loss), net of tax	2,679			(8,837		)	12,532
Interest rate derivatives designated as cash flow hedges:
Unrealized holding loss arising during period	(1,276		)	(1,292		)	—
Loss reclassified to earnings - interest expense	338			54			—
Net loss, before tax	(938		)	(1,238		)	—
Income tax benefit	(343		)	(458		)	—
Net loss, net of tax	(595		)	(780		)	—
Commodity contracts designated as cash flow hedges:
Unrealized holding gain (loss) arising during period	6,070			50,288			(9,475		)
Gain reclassified to earnings - cost of sales	—			—			(22,021		)
Amortization of unrealized (gain) loss on de-designated cash flow hedges - cost of sales	(41,948		)	15,572			—
Net gain (loss), before tax	(35,878		)	65,860			(31,496		)
Income tax expense (benefit)	(13,276		)	24,358			(11,644		)
Net gain (loss), net of tax	(22,602		)	41,502			(19,852		)
Total other comprehensive income (loss), net of tax	(20,518		)	31,885			(7,320		)
Comprehensive income	61,869			101,753			40,795
Comprehensive income attributable to non-controlling interest	29,468			34,239			24,877
Comprehensive income attributable to stockholders	$	32,401		$	67,514		$	15,918

_________________


(1)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost, as further discussed in Note 14. 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

Table of Contents

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, 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
Other comprehensive loss, net of tax	—			—		—			(7,068		)	—			(7,068		)	(252		)	(7,320		)
Balance at December 31, 2013	682			686		509,170			(37,515		)	124,936			597,959			27,445			625,404
Stock compensation expense	—			9		7,915			—			—			7,924			(428		)	7,496
Dividends	—			—		—			—			(36,483		)	(36,483		)	(1,134		)	(37,617		)
Dividends of common stock on preferred stock	—			1		42			—			(59		)	(16		)	—			(16		)
Distributions to non-controlling interest in the Partnership	—			—		—			—			—			—			(23,242		)	(23,242		)
Net income	—			—		—			—			38,457			38,457			31,411			69,868
Other comprehensive income, net of tax	—			—		—			29,057			—			29,057			2,828			31,885
Balance at December 31, 2014	682			696		517,127			(8,458		)	126,851			636,898			36,880			673,778
Stock compensation expense	—			13		8,217			—			—			8,230			(1,436		)	6,794
Dividends	—			—		—			—			(38,387		)	(38,387		)	(415		)	(38,802		)
Dividends of common stock on preferred stock	—			—		10			—			(14		)	(4		)	—			(4		)
Preferred stock conversion	(682		)	1		681			—			—			—			—			—
Distributions to non-controlling interest in the Partnership	—			—		—			—			—			—			(39,475		)	(39,475		)
Net income	—			—		—			—			52,751			52,751			29,636			82,387
Other comprehensive loss, net of tax	—			—		—			(20,350		)	—			(20,350		)	(168		)	(20,518		)
Balance at December 31, 2015	$	—		$	710	$	526,035		$	(28,808	)	$	141,201		$	639,138		$	25,022		$	664,160

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

F-7

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands)

	Year Ended December 31,
	2015			2014			2013
Cash flows from operating activities:
Net income	$	82,387		$	69,868		$	48,115
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	126,494			124,063			125,494
Stock compensation	9,953			7,496			7,015
Deferred income taxes	5,906			5,961			8,278
Equity earnings of investees, net of dividends	(2,274		)	—			(3,266		)
Amortization of debt issuance costs	3,595			3,759			4,496
Amortization of original issuance discount	6,273			6,306			4,300
Write-off of unamortized debt issuance costs	—			558			1,871
Write-off of unamortized original issuance discount	—			391			1,871
Gain on disposition of assets	(1,914		)	(274		)	(9,558		)
Loss on impairment of goodwill	39,028			—			—
Unrealized gain on commodity swaps	(7,937		)	(3,778		)	(3,085		)
Changes in operating assets and liabilities:
Accounts and other receivables, net	18,369			77,658			(19,053		)
Income tax receivable	5,455			6,857			(15,547		)
Inventories	17,288			4,983			55,149
Prepaid expenses and other current assets	(1,960		)	(7,686		)	8,410
Other assets, net	(11,782		)	(27,506		)	6,042
Accounts payable	(37,179		)	(68,482		)	1,726
Accrued liabilities	(14,170		)	3,733			(2,794		)
Other non-current liabilities	(11,467		)	(10,249		)	(57,231		)
Net cash provided by operating activities	226,065			193,658			162,233
Cash flows from investing activities:
Capital expenditures	(101,195		)	(88,429		)	(68,513		)
Capital expenditures for turnarounds and catalysts	(35,348		)	(62,473		)	(8,617		)
Dividends from investees, net of equity earnings	—			1,472			—
Contribution to equity method investment	(15,161		)	(597		)	(1,403		)
Proceeds from disposition of assets	2,889			41,032			27,092
Acquisition of retail stores	(11,196		)	—			—
Net cash used in investing activities	(160,011		)	(108,995		)	(51,441		)
Cash flows from financing activities:
Dividends paid to stockholders	(38,387		)	(36,483		)	(24,081		)
Dividends paid to non-controlling interest	(415		)	(1,134		)	(886		)
Distributions paid to non-controlling interest in the Partnership	(39,475		)	(23,242		)	(31,746		)
Equity issuance costs	—			—			(1,012		)
Inventory agreement transactions	40,138			24,200			25,200
Deferred debt issuance costs	(2,139		)	(2,284		)	(4,264		)
Revolving credit facilities, net	(5,000		)	(40,000		)	51,000
Additions to long-term debt	14,049			145,000			150,000
Payments on long-term debt	(15,659		)	(160,258		)	(151,575		)
Proceeds from issuance of warrants	—			—			13,230
Payments for purchases of hedges on convertible debt	—			—			(28,455		)
Net cash used in financing activities	(46,888		)	(94,201		)	(2,589		)
Net increase (decrease) in cash and cash equivalents	19,166			(9,538		)	108,203
Cash and cash equivalents, beginning of period	214,961			224,499			116,296
Cash and cash equivalents, end of period	$	234,127		$	214,961		$	224,499
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$	70,556		$	106,065		$	85,329
Cash paid for income tax, net of refunds	$	35,976		$	10,957		$	18,184
Supplemental disclosure of non-cash activities:
Capital expenditures included in accounts payable and accrued liabilities	$	21,011		$	—		$	6,161

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

F-8

Table of Contents

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,” “our” and “us” or like terms refer to Alon USA Energy, Inc. and its consolidated subsidiaries or to Alon USA Energy, Inc. or an individual subsidiary. Generally, the words “we,” “our” and “us” include Alon USA Partners, LP and its consolidated 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 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 a sour crude oil refinery located in Big Spring, Texas, a light sweet crude oil refinery located in Krotz Springs, Louisiana, and heavy crude oil refineries located in Paramount, Bakersfield and Long Beach, California (the “California refineries”). Our California refineries have not processed crude oil since 2012 due to the high cost of crude oil relative to product yield and low asphalt demand. We refine crude oil into petroleum products, including various grades of gasoline, diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum-based products, which are marketed primarily in the South Central, Southwestern and Western regions of the United States. We are also shipping and selling gasoline into wholesale markets in the Southern and Eastern United States.

We own the Big Spring refinery and its integrated wholesale marketing operations through the Partnership. We market transportation fuels produced at the Big Spring refinery in Central and West Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in these regions as our “physically integrated system” because we primarily supply our customers in this region with motor fuels produced at our Big Spring refinery and distributed through a network of pipelines and terminals that we own or access through leases or long-term throughput agreements.

We sell motor fuels under the Alon brand through various terminals to supply 633 Alon branded retail sites, including our retail segment convenience stores. In addition we sell motor fuels through our wholesale distribution network on an unbranded basis. In 2015, we sold 1,026.6 million gallons of motor fuels through our branded and unbranded motor fuels network.

We market transportation fuel production from our Krotz Springs refinery through bulk sales, exchange and wholesale channels. The bulk sales and exchange arrangements are entered into with various oil companies and trading companies and are transported to markets on the Mississippi River and the Atchafalaya River as well as to the Southern and Eastern United States through the Colonial Pipeline. We are also shipping and selling gasoline into certain wholesale markets in the Southern and Eastern United States through the Colonial Pipeline.

We own a 32% interest in a renewable fuels project that is located at our California refineries. The project converts tallow into renewable fuels. As of December 31, 2015, our investment in this project was $15,148, which is recorded under the equity method of accounting and included as part of total assets in the refining and marketing segment data.

Asphalt Segment. We own or operate 11 asphalt terminals located in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Washington (Richmond Beach), Arizona (Phoenix and Flagstaff) as well as asphalt terminals in which we own a 50% interest located in Fernley, Nevada, and Brownwood, Texas. The operations in which we have a 50% interest are recorded under the equity method of accounting and the investments are included as part of total assets in the asphalt segment data.

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 market asphalt primarily as paving asphalt to road and materials manufacturers and as ground tire rubber polymer modified or emulsion asphalt to highway construction/maintenance contractors. Sales of asphalt are seasonal with the majority of sales occurring between May and October.

Retail Segment. Our retail segment operates 309 convenience stores located in Central and West Texas and New Mexico. These convenience stores typically offer various grades of gasoline and diesel under the Alon brand name and food products, food service, tobacco products, non-alcoholic and alcoholic beverages, general merchandise as well as money orders to the public, primarily under the 7-Eleven brand name. Substantially all of the motor fuel sold through our retail segment is supplied by our Big Spring refinery.

In August 2015, we acquired 14 retail stores in the Albuquerque, New Mexico area for $11,196, which included property, plant and equipment and related inventories.

F-9

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)


(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 consolidated subsidiaries. All significant intercompany balances and transactions have been eliminated.


(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, blending materials, RINs and other raw materials, inclusive of transportation costs, which include costs associated with our crude oil and product pipelines. 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.

Cost of sales for the year ended December 31, 2015 includes proceeds from insurance recoveries of $10,868 related to a business interruption insurance claim at our Krotz Springs refinery.

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.

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 on debt, 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. Original issuance discount and debt issuance costs are amortized over the term of the related debt using the effective interest method.

F-10

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)


(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. We perform ongoing credit evaluations of our customers and require letters of credit, prepayments or other collateral or guarantees as management deems appropriate. Allowance for doubtful accounts is based on a combination of current sales and specific identification methods.

Credit risk is minimized as a result of the ongoing credit assessment of our customers and a lack of concentration in our customer base. Credit losses are charged to allowance for doubtful accounts when deemed uncollectible. Our allowance for doubtful accounts is reflected as a reduction of accounts receivable in the consolidated balance sheets.


(g)	Inventories

Crude oil, refined products, blendstocks and asphalt (including crude oil consignment inventory) are stated at the lower of cost or market. Cost is determined using the last-in, first-out (“LIFO”) inventory valuation method and market is determined using current estimated selling prices. Under the LIFO valuation method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. An inventory write-down to market value results in a non-cash accounting adjustment, decreasing the value of our inventory and increasing our cost of sales. Such charges are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods.

Materials and supplies are stated at average cost. Cost for retail merchandise inventories is determined under the retail inventory method and cost for retail 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 the 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 on the consolidated statements 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.

F-11

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

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. The useful lives used to determine depreciation for our assets are as follows:



Refining facilities	3 – 20 years
Pipelines and terminals	5 – 25 years
Retail	5 – 40 years
Other	3 – 15 years

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. The future cash flows and fair values used in this assessment are estimates based on management’s judgment and assumptions. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs of disposition.


(k)	Asset Retirement Obligations

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 (Note 13).


(l)	Turnarounds and Catalysts Costs

Our refinery units require regular major maintenance and repairs that are commonly referred to as “turnarounds.” Catalysts used in certain refinery process units are typically replaced in conjunction with planned turnarounds. We record the turnaround and catalysts costs as deferred charges in other assets in the consolidated balance sheets. We amortize the deferred costs on a straight-line basis over the period of time estimated until the next turnaround occurs (generally 3 to 5 years), beginning the month after the completion of the turnaround. The amortization of deferred turnaround and catalysts costs are presented in depreciation and amortization in our 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.

F-12

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)


(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, 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 17).


(o)	Environmental Expenditures

Environmental expenditures are recorded to expense 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. These estimates are 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. Estimates are updated to reflect changes in factual information, available technology or applicable laws and regulations (Note 21).

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


(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 19).


(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 interest rate derivatives and 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 December 31, of each year as the measurement date for plan assets and obligations for all of our defined pension and postretirement 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 goodwill impairment testing purposes.

F-13

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)


(u)	New Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard that provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. This standard is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. The standard allows for either full retrospective adoption or modified retrospective adoption. In August 2015, the FASB updated the guidance to include a one-year deferral of the effective date for the new revenue standard, making the requirements of the standard effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are evaluating the guidance to determine the method of adoption and the impact this standard will have on our consolidated financial statements.

In February 2015, the FASB issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the way certain decisions are made related to substantive rights, related parties, and decision making fees when applying the variable interest entity consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. The adoption of this guidance will not have a material effect on our financial position or results of operations.

In April 2015, the FASB issued an accounting standards update simplifying the presentation of debt issuance costs. The new standard requires that certain costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. In August 2015, the FASB updated the guidance to clarify that debt issuance costs related to line-of-credit arrangements would not be impacted by the updated standard. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. We adopted this standard and applied the changes retrospectively to the prior period. The adoption of this standard resulted in the reclassification of $9,230 of unamortized debt issuance costs from other non-current assets to long-term debt on the consolidated balance sheets at December 31, 2014.

In July 2015, the FASB issued an accounting standards update simplifying the measurement of certain inventory. This updated standard simplifies the measurement of inventory by requiring certain inventory to be measured at the lower of cost or net realizable value. The amendments in this accounting standards update are effective for interim and annual periods beginning after December 15, 2016. This accounting standards update does not apply to the subsequent measurement of inventory measured using the LIFO or retail inventory methods, therefore the adoption of this guidance will not have a material effect on our financial position or results of operations.

In November 2015, the FASB issued an accounting standards update simplifying the presentation of income taxes. This updated standard eliminates the current requirement to present deferred tax liabilities and assets as current and non-current in a classified balance sheet. Instead, all deferred tax assets and liabilities will be required to be classified as non-current. The requirements from the updated standard are effective for interim and annual periods beginning after December 31, 2016, and early adoption is permitted. We are evaluating the guidance to determine the impact this standard will have on our consolidated financial statements.


(3)	Alon USA Partners, LP

The Partnership (NYSE: ALDW) is a publicly-traded limited partnership that owns the assets and conducts the operations of the Big Spring refinery and the associated integrated wholesale marketing operations. The limited partner interests of the Partnership are represented as common units outstanding. As of December 31, 2015, the 11,510,039 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 general partner interest in the Partnership, which is a non-economic interest.

The limited partner interests in the Partnership not owned by us are reflected in the consolidated statements of operations in net income attributable to non-controlling interest and in our consolidated balance sheets 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.

F-14

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

Partnership Distributions

The Partnership has adopted a policy pursuant to which it will distribute all of the available cash generated each quarter, as defined in the partnership agreement, 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.

During the years ended December 31, 2015, 2014 and 2013, the Partnership paid the following aggregate cash distributions:



	Cash Available for Distribution per Unit (1)		Distributions Per Unit		Total Distribution Amount		Distributions Paid to Non-Controlling Interest
2015	$	2.81	$	3.43	$	214,405	$	39,475
2014	2.54		2.02		126,262		23,242
2013	2.37		2.76		172,506		31,746

_______________________


(1)	Represents the aggregate cash available for distribution per unit attributable to the period indicated. This represents the difference between cash available for distribution and distributions paid in the table above.


(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. 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.

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, gain (loss) on disposition of assets and loss on impairment of goodwill. Intersegment sales are intended to approximate wholesale market prices. Consolidated totals presented are after intersegment eliminations.

Total assets of each segment consist of net property, plant and equipment, inventories, cash and cash equivalents, accounts and other receivables, goodwill 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, 2015, 2014 and 2013 are presented below:



	Refining and Marketing		Asphalt			Retail			Corporate			Consolidated Total
Year ended December 31, 2015
Net sales to external customers	$	3,305,762	$	257,955		$	774,435		$	—		$	4,338,152
Intersegment sales (purchases)	358,194		(31,198		)	(326,996		)	—			—
Depreciation and amortization	107,619		4,892			12,431			1,552			126,494
Operating income (loss)	178,081		2,363			25,230			(2,265		)	203,409
Total assets	1,822,924		106,015			231,078			16,121			2,176,138
Turnarounds, catalysts and capital expenditures	108,777		3,385			18,993			5,388			136,543



	Refining and Marketing		Asphalt			Retail			Corporate			Consolidated Total
Year ended December 31, 2014
Net sales to external customers	$	5,382,360	$	457,412		$	939,684		$	—		$	6,779,456
Intersegment sales (purchases)	555,622		(59,615		)	(496,007		)	—			—
Depreciation and amortization	104,676		4,747			12,241			2,399			124,063
Operating income (loss)	204,609		(25,597		)	25,665			(3,105		)	201,572
Total assets (1)	1,851,344		110,139			215,038			15,123			2,191,644
Turnarounds, catalysts and capital expenditures	125,621		5,777			16,748			2,756			150,902



	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)	1,870,441		154,143			197,714			12,726			2,235,024
Turnarounds, catalysts and capital expenditures	48,889		9,425			17,935			881			77,130

_________________

(1)


(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 are our only assets and liabilities measured at fair value on a recurring basis.

F-15

Table of Contents

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, 2015 and 2014:



	Level 1		Level 2		Level 3		Total
As of December 31, 2015
Assets:
Commodity contracts (swaps)	$	—	$	14,799	$	—	$	14,799
Fair value hedges of consigned inventory	—		33,797		—		33,797
Liabilities:
Commodity contracts (futures and forwards)	592		—		—		592
Interest rate swaps	—		2,176		—		2,176

As of December 31, 2014
Assets:
Commodity contracts (swaps)	$	—	$	42,740	$	—	$	42,740
Fair value hedges of consigned inventory	—		24,903		—		24,903
Liabilities:
Commodity contracts (futures and forwards)	333		—		—		333
Interest rate swaps	—		1,238		—		1,238

The following table sets forth our non-recurring fair value measurements, by input level, in the consolidated balance sheets as of December 31, 2015:



	Level 1		Level 2		Level 3		Total		Total Losses
As of December 31, 2015
Goodwill (1)	$	—	$	—	$	62,885	$	62,885	$	(39,028	)

_________________


(1)	Goodwill with a carrying amount of $101,913 was written down to its implied fair value of $62,885, resulting in an impairment charge of $39,028, which has been included in earnings for the year ended December 31, 2015.


(6)	Derivative Financial Instruments

We selectively utilize crude oil and refined product commodity derivative contracts to reduce the risk associated with potential price changes on committed obligations as well as to reduce earnings volatility. We also utilize interest rate swaps to manage our exposure to interest rate risk. 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.

Mark to Market

We have certain contracts that serve as economic hedges, which are derivatives used for risk management but not designated as hedges for financial accounting purposes. All economic hedge transactions are recorded at fair value and any changes in fair value between reporting periods are recognized in earnings.

We have contracts that are used to fix prices on forecasted purchases of inventory, which we refer to as futures and forwards. Futures represent trades executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. 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.

We also have economic hedges in the form of swap contracts that fix price differentials between different types of crude oil and refined products that we use or produce at our refineries. At December 31, 2015, these swap contracts had aggregate volumes of 8,490 thousand barrels of crude oil and refined products with contract terms through December 2016.

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.

We have certain commodity contracts associated with the Supply and Offtake Agreements discussed in Note 9 that have been accounted for as fair value hedges, which had purchase volumes of 669 thousand barrels of crude oil as of December 31, 2015.

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 hedged item. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the hedged item. If, during the term of the derivative, the hedge is determined to be no longer highly effective, hedge accounting is

F-16

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

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, 2015, we did not have any commodity swap contracts accounted for as cash flow hedges. In January 2015, we elected to de-designate certain commodity swap contracts that were previously designated as cash flow hedges. During the year ended December 31, 2015, we reclassified gains of $41,948 from other comprehensive income (“OCI”) into cost of sales related to these de-designated cash flow hedges that settled in 2015. During the year ended December 31, 2014, we reclassified losses of $15,572 from OCI into cost of sales related to previously de-designated cash flow hedges that settled in 2014.

Related to commodity swap cash flow hedges in OCI, we recognized unrealized gains (losses) of $(35,878), $65,860 and $(31,496) for the years ended December 31, 2015, 2014 and 2013, respectively.

Interest Rate Derivatives. We have interest rate swap agreements, maturing March 2019, that effectively fix the variable LIBOR interest component of the term loans within the Alon Retail Credit Agreement, as defined in Note 15. These interest rate swaps have been accounted for as cash flow hedges. The aggregate notional amount under these agreements covers approximately 75% of the outstanding principal of these term loans throughout the duration of the interest rate swaps. As of December 31, 2015, the outstanding principal of these term loans was $105,967. The interest rate swaps lock in an average fixed interest rate of 1.43% in 2016; 2.22% in 2017; 2.89% in 2018 and 3.06% in 2019.

Related to these interest rate swap cash flow hedges in OCI, we recognized unrealized losses of $938 and $1,238 for the years ended December 31, 2015 and 2014, respectively.

For the years ended December 31, 2015 and 2014, there was no hedge ineffectiveness recognized in income. For the year ended December 31, 2013, there was $1,879 of hedge ineffectiveness recognized on commodity swap cash flow hedges in cost of sales. For the years ended December 31, 2015, 2014 and 2013, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.

As of December 31, 2015, we have net unrealized losses of $2,176 classified in OCI related to cash flow hedges. Assuming interest rates remain unchanged, unrealized losses of $571 will be reclassified from OCI into earnings over the next twelve-month period as the underlying transactions occur.

The following tables present the effect of derivative instruments on the consolidated balance sheets:



	As of December 31, 2015
	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	$	292	Accrued liabilities	$	884
Commodity contracts (swaps)	Accounts receivable	14,799			—
Total derivatives not designated as hedging instruments		15,091			884

Derivatives designated as hedging instruments:
Interest rate swaps		—		Other non-current liabilities	2,176
Fair value hedges of consigned inventory	Other assets	33,797			—
Total derivatives designated as hedging instruments		33,797			2,176
Total derivatives		$	48,888		$	3,060

F-17

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)



	As of December 31, 2014
	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	$	7,168	Accrued liabilities	$	7,501
Commodity contracts (swaps)	Accounts receivable	6,809			—
Commodity contracts (swaps)	Other assets	11,622			—
Total derivatives not designated as hedging instruments		25,599			7,501

Derivatives designated as hedging instruments:
Commodity contracts (swaps)	Accounts receivable	$	24,309		$	—
Interest rate swaps		—		Other non-current liabilities	1,238
Fair value hedges of consigned inventory	Other assets	24,903			—
Total derivatives designated as hedging instruments		49,212			1,238
Total derivatives		$	74,811		$	8,739

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

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, 2015
Commodity contracts (swaps)	$	(35,878	)	Cost of sales	$	41,948			$	—
Interest rate swaps	(938		)	Interest expense	(338		)		—
Total derivatives	$	(36,816	)		$	41,610			$	—

For the Year Ended December 31, 2014
Commodity contracts (swaps)	$	65,860		Cost of sales	$	(15,572	)		$	—
Interest rate swaps	(1,238		)	Interest expense	(54		)		—
Total derivatives	$	64,622			$	(15,626	)		$	—

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	)

Derivatives in fair value hedging relationships:



		Gain (Loss) Recognized in Income
		Year Ended December 31,
	Location	2015		2014		2013
Fair value hedges of consigned inventory (1)	Interest expense	$	8,894	$	28,242	$	(1,619	)
Total derivatives		$	8,894	$	28,242	$	(1,619	)

_________________


(1)	Changes in the fair value hedges are substantially offset in earnings by changes in the hedged items.

F-18

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

Derivatives not designated as hedging instruments:



		Gain (Loss) Recognized in Income
		Year Ended December 31,
	Location	2015			2014			2013
Commodity contracts (futures and forwards)	Cost of sales	$	(6,302	)	$	(18,950	)	$	8,359
Commodity contracts (swaps)	Cost of sales	17,267			20,232			4,964
Total derivatives		$	10,965		$	1,282		$	13,323

Offsetting Assets and Liabilities

Our derivative 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, 2015 and 2014:



	Gross Amounts of Recognized Assets/ Liabilities		Gross Amounts offset in the Statement of Financial Position			Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not offset in the Statement of Financial Position					Net Amount
	Gross Amounts of Recognized Assets/ Liabilities		Gross Amounts offset in the Statement of Financial Position					Financial Instruments			Cash Collateral Pledged		Net Amount
As of December 31, 2015
Derivative Assets:
Commodity contracts (futures and forwards)	$	1,112	$	(820	)	$	292	$	(292	)	$	—	$	—
Commodity contracts (swaps)	39,739		(24,940		)	14,799		—			—		14,799
Fair value hedges of consigned inventory	33,797		—			33,797		—			—		33,797
Derivative Liabilities:
Commodity contracts (futures and forwards)	$	1,704	$	(820	)	$	884	$	(292	)	$	—	$	592
Commodity contracts (swaps)	24,940		(24,940		)	—		—			—		—
Interest rate swaps	2,206		(30		)	2,176		—			—		2,176

As of December 31, 2014
Derivative Assets:
Commodity contracts (futures and forwards)	$	8,508	$	(1,340	)	$	7,168	$	(7,168	)	$	—	$	—
Commodity contracts (swaps)	49,204		(6,464		)	42,740		—			—		42,740
Fair value hedges of consigned inventory	24,903		—			24,903		—			—		24,903
Derivative Liabilities:
Commodity contracts (futures and forwards)	$	8,841	$	(1,340	)	$	7,501	$	(7,168	)	$	—	$	333
Commodity contracts (swaps)	6,464		(6,464		)	—		—			—		—
Interest rate swaps	1,238		—			1,238		—			—		1,238

Compliance Program Market Risk

We are obligated by government regulations to blend a certain percentage of biofuels into the products that we produce and 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 renewable identification number, or 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. Alternatively, if we have a RINs surplus, some of those RINs could be sold. Any such sales would be subject to our normal credit evaluation process.

F-19

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

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 RINs 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 $35,062, $27,110 and $14,917 for the years ended December 31, 2015, 2014 and 2013, respectively. These amounts are reflected in cost of sales in the consolidated statements of operations.


(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 years ended December 31, 2015, 2014 and 2013. The allowance for doubtful accounts is reflected as a reduction of accounts and other receivables in the consolidated balance sheets.

Accounts and other receivables, net consisted of the following:



	As of December 31,
	2015			2014
Trade accounts receivable	$	98,164		$	99,207
Other receivables	21,724			55,413
Allowance for doubtful accounts	(717		)	(761		)
Total accounts and other receivables, net	$	119,171		$	153,859

The following table sets forth the allowance for doubtful accounts for the years ended December 31, 2015, 2014 and 2013:



	Balance at Beginning of Period		Additions Charged to Expense	Deductions		Balance at End of Period
2015	$	761	126	(170	)	$	717
2014	$	461	300	—		$	761
2013	$	583	175	(297	)	$	461


(8)	Inventories

Carrying value of inventories consisted of the following:



	As of December 31,
	2015		2014
Crude oil, refined products, asphalt and blendstocks	$	42,123	$	48,027
Crude oil consignment inventory (Note 9)	2,928		18,350
Materials and supplies	26,940		22,269
Store merchandise	28,475		27,418
Store fuel	5,049		6,739
Total inventories	$	105,515	$	122,803

Reductions of inventory volumes during 2015 and 2013 resulted in a liquidation of LIFO inventory layers. The liquidations increased cost of sales by $11,371 and $1,455 during 2015 and 2013, respectively. There were no liquidations of LIFO inventory layers during 2014.

At December 31, 2015, the market value of refined products, asphalt and blendstock inventories was lower than LIFO costs by $836. At December 31, 2014, the market value of refined products, asphalt and blendstock inventories exceeded LIFO costs by $7,713. The market value of crude oil inventories exceeded LIFO costs, net of the fair value hedged items, by $18,521 and $17,754 at December 31, 2015 and 2014, respectively.

F-20

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)


(9)	Inventory Financing Agreements

We have 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 for the Big Spring and Krotz Springs refineries have initial terms that expire in May 2021, and the Supply and Offtake Agreement for the California refineries has initial terms that expire in May 2019. J. Aron may elect to terminate the Supply and Offtake Agreements for the Big Spring and Krotz Springs refineries prior to the expiration of the initial term beginning in May 2018 and upon each anniversary thereof, on six months prior notice. We may elect to terminate at the Big Spring and Krotz refineries in May 2020 on six months prior notice. J. Aron may elect to terminate the Supply and Offtake Agreement for the California refineries prior to the expiration of the initial term beginning in May 2016 and upon each anniversary thereof, on six months prior notice. We may elect to terminate at the California refineries 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 then current market prices.

Associated with the Supply and Offtake Agreements, we have designated fair value hedges of our inventory purchase commitments with J. Aron and crude oil inventory consigned to J. Aron (“crude oil consignment inventory”). Additionally, financing charges related to the Supply and Offtake Agreements are recorded as interest expense in the consolidated statements of operations.

In connection with the Supply and Offtake Agreement for our Krotz Springs refinery, we have granted a security interest to J. Aron in all of its accounts and inventory to secure its obligations to J. Aron. In addition, we have granted a security interest in all of its real property and equipment to J. Aron to secure its obligations under a commodity hedge and sale agreement in lieu of posting cash collateral and being subject to cash margin calls.

At December 31, 2015 and 2014, we had net current receivables of $8,385 and net current payables of $46,303, respectively, with J. Aron for sales and purchases, and a consignment inventory receivable representing a deposit paid to J. Aron of $26,179 and $26,179, respectively. At December 31, 2015 and 2014, we had non-current liabilities for the original financing of $23,771 and $39,060, respectively, net of the related fair value hedges.

Additionally, we had net current payables of $328 and $4,212 at December 31, 2015 and 2014, 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,
	2015			2014
Refining facilities	$	1,915,924		$	1,839,367
Pipelines and terminals	43,443			43,439
Retail	209,921			181,552
Other	23,377			17,988
Property, plant and equipment, gross	2,192,665			2,082,346
Accumulated depreciation	(812,463		)	(710,002		)
Property, plant and equipment, net	$	1,380,202		$	1,372,344

Depreciation expense for the years ended December 31, 2015, 2014 and 2013 was $103,358, $106,623 and $107,845, respectively.

Acquisition of Assets

In August 2015, we acquired 14 retail stores in the Albuquerque, New Mexico area, which increased our Retail property, plant and equipment balance by $10,210.

Disposition of Assets

In January 2014, we sold our Willbridge, Oregon asphalt terminal for $40,000. The terminal was included in our asphalt segment and allocated goodwill of $4,030. For the year ended December 31, 2014, a pre-tax gain of $1,943 was recognized and has been included in gain on disposition of assets in our consolidated statements of operations.


(11)	Goodwill

The following table provides a summary of changes to our goodwill balance by segment for the years ended December 31, 2015 and 2014:



	Refining and Marketing			Asphalt			Retail		Total
Balance at December 31, 2013	$	39,028		$	16,726		$	50,189	$	105,943
Disposition of assets with allocated goodwill	—			(4,030		)	—		(4,030		)
Balance at December 31, 2014	39,028			12,696			50,189		101,913
Impairment of goodwill	(39,028		)	—			—		(39,028		)
Balance at December 31, 2015	$	—		$	12,696		$	50,189	$	62,885

During the year ended December 31, 2014, we sold our Willbridge, Oregon asphalt terminal, which was allocated goodwill of $4,030 at the time of disposition.


(12)	Other Assets, Net

Other assets, net consisted of the following:



	As of December 31,
	2015		2014
Deferred turnaround and catalyst costs	$	87,469	$	60,753
Environmental receivables (Note 21)	2,648		3,030
Intangible assets, net	14,505		7,647
Receivable from supply and offtake agreements (Note 9)	26,179		26,179
Commodity contracts	—		11,622
Fair value hedges of consigned inventory (Note 9)	33,797		24,903
Other, net	21,027		19,515
Total other assets	$	185,625	$	153,649

F-21

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)


(13)	Accrued Liabilities and Other Non-Current Liabilities

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



	As of December 31,
	2015		2014
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes	$	35,375	$	47,071
Employee costs	25,202		13,297
Commodity contracts	884		7,501
Accrued finance charges	1,789		1,826
Environmental accrual (Note 21)	7,880		8,189
Other	22,650		26,507
Total accrued liabilities	$	93,780	$	104,391

Other Non-Current Liabilities:
Pension and other postemployment benefit liabilities, net	$	49,054	$	52,135
Environmental accrual (Note 21)	38,482		43,546
Asset retirement obligations	10,906		12,328
Consignment inventory obligations (Note 9)	57,568		63,963
Interest rate swaps	2,176		1,238
Other	7,749		9,449
Total other non-current liabilities	$	165,935	$	182,659

The following table summarizes the activity relating to the asset retirement obligations for the years ended December 31, 2015 and 2014:



	As of December 31,
	2015			2014
Balance at beginning of year	$	12,328		$	12,468
Accretion expense	775			651
Revisions in estimated cash flows	(2,128		)	—
Retirements	(213		)	(791		)
Additions	144			—
Balance at end of year	$	10,906		$	12,328

Revisions in estimated cash flows include changes in expected inflationary rates partially offset by increased tank retirement costs. Retirements include $707 related to the disposal of the Willbridge, Oregon asphalt terminal in January 2014 (Note 10).


(14)	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
	2015			2014
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	129,053		$	106,028
Service cost	3,985			3,424
Interest cost	5,022			4,952
Actuarial (gain) loss	(5,959		)	17,801
Benefits paid	(3,272		)	(3,152		)
Projected benefit obligations at end of year	$	128,829		$	129,053
Change in plan assets:
Fair value of plan assets at beginning of year	$	84,893		$	73,918
Actual gain (loss) on plan assets	(468		)	7,904
Employer contribution	5,675			6,223
Benefits paid	(3,272		)	(3,152		)
Fair value of plan assets at end of year	$	86,828		$	84,893
Reconciliation of funded status:
Fair value of plan assets at end of year	$	86,828		$	84,893
Less projected benefit obligations at end of year	128,829			129,053
Under-funded status at end of year	$	(42,001	)	$	(44,160	)

The pre-tax amounts related to the defined benefit plans recognized in the consolidated balance sheets as of December 31, 2015 and 2014 were as follows:



	Pension Benefits
	2015			2014
Amounts recognized in the consolidated balance sheets:
Pension benefit liability	$	(42,001	)	$	(44,160	)

The pre-tax amounts in accumulated other comprehensive loss as of December 31, 2015 and 2014 that have not yet been recognized as components of net periodic benefit cost were as follows:



	Pension Benefits
	2015			2014
Net actuarial loss	$	(42,091	)	$	(44,660	)
Prior service credit	225			276
Total	$	(41,866	)	$	(44,384	)

F-22

Table of Contents

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 loss as of December 31, 2015 are expected to be recognized as components of net periodic benefit cost during the year ending December 31, 2016:



	Pension Benefits
Amortization of prior service credit	$	(51	)
Amortization of net actuarial loss	3,278
Total	$	3,227

As of December 31, 2015 and 2014, 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,
	2015		2014
Projected benefit obligation	$	128,829	$	129,053
Accumulated benefit obligation	119,031		118,931
Fair value of plan assets	86,828		84,893

The weighted-average assumptions used to determine benefit obligations at December 31, 2015, 2014 and 2013 were as follows:



	Pension Benefits
	2015		2014		2013
Discount rate	4.45	%	3.95	%	4.75	%
Rate of compensation increase	3.00	%	2.50	%	3.00	%

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, 2015, 2014 and 2013 were as follows:



	Pension Benefits
	2015		2014		2013
Discount rate	3.95	%	4.75	%	4.00	%
Expected return on plan assets	8.50	%	8.60	%	8.60	%
Rate of compensation increase	2.50	%	3.00	%	3.00	%

Our overall expected long-term rate of return on assets is 8.50%. 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,
	2015			2014			2013
Components of net periodic benefit cost:
Service cost	$	3,985		$	3,424		$	3,962
Interest cost	5,022			4,952			4,408
Amortization of prior service credit	(51		)	(51		)	(51		)
Expected return on plan assets	(6,329		)	(5,478		)	(4,628		)
Recognized net actuarial loss	3,408			2,432			4,071
Net periodic benefit cost	$	6,035		$	5,279		$	7,762

F-23

Table of Contents

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, 2015 and 2014 was as follows:



	Pension Benefits
	Plan Assets
	2015		2014
Asset Category:
Equity securities	76.9	%	79.3	%
Debt securities	12.5	%	10.0	%
Real estate investment trust	10.6	%	10.7	%
Total	100.0	%	100.0	%

The fair value of our pension assets by category as of December 31, 2015 and 2014 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, 2015
Equity securities:
U.S. companies	$	52,800	$	—	$	—	$	52,800
International companies	13,957		—		—		13,957
Debt securities:
Preferred securities	3,770		—		—		3,770
Bond securities	—		7,067		—		7,067
Real estate securities	9,234		—		—		9,234
Total	$	79,761	$	7,067	$	—	$	86,828
Year ended December 31, 2014
Equity securities:
U.S. companies	$	55,322	$	—	$	—	$	55,322
International companies	11,991		—		—		11,991
Debt securities:
Preferred securities	3,492		—		—		3,492
Bond securities	—		5,039		—		5,039
Real estate securities	9,049		—		—		9,049
Total	$	79,854	$	5,039	$	—	$	84,893

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 $5,675 and $6,223 to the pension plan for the years ended December 31, 2015 and 2014, respectively, and expect to contribute $4,725 to the pension plan in 2016. There were no employee contributions to the plans.

The benefits expected to be paid in each year 2016 – 2020 are $4,324; $5,342; $5,160; $5,570 and $5,970, respectively. The aggregate benefits expected to be paid in the five years from 2021 – 2025 are $35,370. The expected benefits are based on the same assumptions used to measure our benefit obligation at December 31, 2015 and include estimated future employee service.

F-24

Table of Contents

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 non-unionized participant contributions up to 3% of compensation. For unionized employees at our Big Spring refinery, we match individual participant contributions up to 8% of compensation. For the years ended December 31, 2015 and 2014, our total contributions to the 401(k) savings plan were $3,340 and $3,186, 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, 2015 and 2014, our contributions were $1,100 and $1,011, 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 met eligibility requirements in the plan documents. This plan is closed to new participants. 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 $7,633 and $8,624 at December 31, 2015 and 2014, respectively.

As of December 31, 2015, the total accumulated postretirement benefit obligation under the postretirement medical plan was $7,633.


(15)	Indebtedness

Debt consisted of the following:



	As of December 31,
	2015		2014
Term loan credit facilities	$	256,519	$	259,851
Alon USA, LP Credit Facility	55,000		60,000
Convertible senior notes	129,623		123,217
Retail credit facilities	114,820		111,389
Total debt (1)	555,962		554,457
Less: Current portion	16,420		15,089
Total long-term debt	$	539,542	$	539,368

_________________


(1)	We adopted ASU 2015-03 for the year-ended December 31, 2015 and applied the changes retrospectively to the prior period presented, see Note 2.


(a)	Alon USA Energy, Inc.

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 the aggregate principal amount of $150,000, which mature in September 2018. Interest on the Convertible Notes is payable in arrears in March and September of each year. 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 Convertible Notes do not contain any maintenance financial covenants.

F-25

Table of Contents

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). 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.

The $150,000 principal amount of the Convertible Notes was separated 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 long-term debt and additional paid-in capital in the consolidated balance sheets.

For the years ended December 31, 2015, 2014 and 2013, interest expense on the Convertible Notes’ contractual coupon rates was $4,500, $4,500 and $1,313, respectively. The amounts charged to interest expense for amortization of the original issuance discount on the Convertible Notes for the years ended December 31, 2015, 2014 and 2013 were $5,674, $5,208 and $1,455, respectively.

As of December 31, 2015, the if-converted value of the Convertible Notes exceeded the outstanding principal by $6,299.

The principal balance, unamortized discount, unamortized issuance costs and net carrying amount of the liability and equity components of the Convertible Notes as of December 31, 2015 and 2014 are as follows:



	As of December 31,
	2015			2014
Equity component, pretax (1)	$	30,365		$	30,365
Convertible Notes:
Principal balance	150,000			150,000
Less: Unamortized issuance discount	(18,028		)	(23,702		)
Less: Unamortized issuance costs	(2,349		)	(3,081		)
Convertible Notes, net	$	129,623		$	123,217

_________________

(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 allow us to purchase up to 10,144,050 shares of our common stock, subject to customary anti-dilution adjustments, that initially underlie the Convertible Notes sold in the offering. As of December 31, 2015, the Purchased Options had an adjusted strike price of $14.24 per share of our common stock. 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 of $17,987, which is net of tax of $10,468, have been included in additional paid-in capital on the consolidated balance sheets.

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.

F-26

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

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. The Warrants allow the Hedge Counterparties to purchase up to 10,144,050 shares of our common stock, subject to customary anti-dilution adjustments. As of December 31, 2015, the Warrants had an adjusted strike price of $19.35 per share of our common stock. The Warrants will be settled on a net-share basis and will expire in April 2019. The Warrants of $13,230 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.

Make-Whole Provision

In May 2015, Delek US Holdings, Inc. (“Delek”) acquired approximately 48% of our outstanding common stock from Alon Israel Oil Company, Ltd. (“Alon Israel”). Delek agreed to a one year standstill provision limiting Delek’s ability to acquire greater than 49.99% of our outstanding common stock, with additional ownership above this threshold subject to the approval of Alon’s independent directors. If Delek were to acquire greater than 50.00% of our outstanding common stock, which would qualify as a fundamental change, it could require us to render a make-whole payment to holders of our Convertible Notes. As of December 31, 2015, the make-whole payment would be approximately $23,000, assuming full conversion of the Convertible Notes. In the event of a conversion, the Purchased Options will cover our obligation to render payment under the make-whole provision. Under these circumstances, we could also be required to settle the outstanding Warrants, which had a value of approximately $35,000 as of December 31, 2015.

Letter of Credit Facilities. In December 2013, we entered into a Letter of Credit Facility (the “Alon Energy Letter of Credit Facility”). 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. (“Alon Assets”) 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 matures November 2017 and contains certain restrictive covenants including maintenance financial covenants.

At December 31, 2015 and 2014, we had outstanding letters of credit under this facility of $60,627 and $54,227, respectively.

Alon Energy Term Loan. In March 2014, we entered into a five-year Term Loan Agreement (“Alon Energy Term Loan”) for a principal amount of $25,000, maturing in March 2019. Repayments are monthly, commencing June 2014. Borrowings under this agreement incur interest at an annual rate equal to LIBOR plus a margin of 3.75%. We pledged 2,200,000 of the Partnership’s common units as collateral for the Alon Energy Term Loan. Additionally, Alon Assets guarantees all payments under the Alon Energy Term Loan. The Alon Energy Term Loan contains certain restrictive covenants including maintenance financial covenants.

At December 31, 2015 and 2014, the Alon Energy Term Loan had an outstanding balance, net of unamortized issuance costs, of $16,717 and $21,862, respectively.

2015 Term Loan Credit Facility. In August 2015, we entered into a $3,049 unsecured term loan (“2015 Term Loan”), which requires principal repayments of $51 monthly until maturity in August 2020. Borrowings under the 2015 Term Loan bear interest at LIBOR plus 2.50% per annum. At December 31, 2015, the outstanding balance, net of unamortized issuance costs, was $2,720.


(b)	Alon USA Partners, LP

Partnership Term Loan Credit Facility. In November 2012, the Partnership entered into a $250,000 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. Based on Eurodollar market rates at December 31, 2015, the interest rate was 9.25% per annum.

F-27

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

certain lease obligations and certain restricted payments. The Partnership Term Loan does not contain any maintenance financial covenants.

At December 31, 2015 and 2014, the Partnership Term Loan had an outstanding balance, net of unamortized issuance costs and issuance discount, of $237,082 and $237,989, respectively.

Revolving Credit Facility. We have a $240,000 revolving credit facility (the “Alon USA, LP Credit Facility”) that will mature in May 2019. 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 3.00% per annum.

Borrowings of $55,000 and $60,000 were outstanding under the Alon USA, LP Credit Facility at December 31, 2015 and 2014, respectively. At December 31, 2015 and 2014, outstanding letters of credit under the Alon USA, LP Credit Facility were $48,590 and $23,511, respectively.


(c)	Alon Refining Krotz Springs, Inc.

Senior Secured Notes. In October 2009, Alon Refining Krotz Springs, Inc. issued 13.50% senior secured notes (the “Senior Secured Notes”) in aggregate principal amount of $216,500 that matured in October 2014, with the entire principal amount due at maturity.

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. During 2014, we redeemed the remaining principal balance on the Senior Secured Notes. As a result of the prepayment of the Senior Secured Notes, write-offs of unamortized original issuance discount and debt issuance costs of $391 and $358, respectively, were charged to interest expense in the consolidated statements of operations for the year ended December 31, 2014.


(d)	Retail

Alon Retail Credit Agreement. In March 2014, Southwest Convenience Stores, LLC and Skinny’s LLC, (“Alon Retail”) entered into a credit agreement (“Alon Retail Credit Agreement”), maturing March 2019. The Alon Retail Credit Agreement includes an initial $110,000 term loan and a $10,000 revolving credit loan. The Alon Retail Credit Agreement also includes an accordion feature that provides for incremental term loans up to $30,000 to fund store rebuilds, new builds and acquisitions. In August 2015, we borrowed $11,000 using the accordion feature and amended the Alon Retail Credit Agreement to restore the undrawn amount of the accordion feature back to $30,000. The $11,000 incremental term loan was used to fund our acquisition of 14 retail stores in New Mexico (Note 1).

At December 31, 2015 and 2014, the Alon Retail Credit Agreement had $104,540 and $101,026, respectively, of outstanding term loans, net of unamortized issuance costs, and $10,000 and $10,000, respectively, outstanding under the revolving credit loan.

Other Retail Related Credit Facilities. At December 31, 2015 and 2014, we have other loans that mature in 2019 with outstanding balances of $280 and $363, respectively.


(e)	Financial Covenants

We have certain credit agreements that contain maintenance financial covenants. At December 31, 2015, we were in compliance with these covenants.

F-28

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)


(f)	Maturity of Long-Term Debt

The aggregate scheduled maturities of long-term debt for each of the five years subsequent to December 31, 2015 are as follows:



Year ended December 31,
2016	$	16,420
2017	16,414
2018	401,422
2019	148,741
2020	406
Total	$	583,403


(g)	Interest and Financing Expense

Interest and financing expense included the following:



	Year Ended December 31,
	2015			2014			2013
Interest expense on debt	$	33,162		$	37,850		$	54,191
Letters of credit and finance charges	40,058			65,156			32,286
Amortization of debt issuance costs	3,595			3,759			4,496
Write-off of debt issuance costs	—			558			1,871
Amortization of original issuance discount	6,273			6,306			4,300
Write-off of original issuance discount	—			391			1,871
Less: Capitalized interest	(3,262		)	(2,877		)	(4,321		)
Total interest expense	$	79,826		$	111,143		$	94,694


(16)	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 70,960,461 and 69,606,944 as of December 31, 2015 and 2014, respectively.

Amended Shareholder Agreement. In 2012, we signed agreements with the remaining non-controlling interest shareholders of Alon Assets, whereby the participants would exchange shares of Alon Assets for shares of our common stock. During 2015 and 2014, 557,589 and 659,289 shares of our common stock were issued in exchange for 3,006.20 and 3,524.49 shares of Alon Assets, respectively. At December 31, 2015, 698,083 shares of our common stock are available to be exchanged for all of the outstanding shares held by the non-controlling interest shareholder of Alon Assets.

We recognized compensation expense associated with the difference in value between the participants’ ownership of Alon Assets compared to our common stock of $2,274, $2,432 and $2,499 for the years ended December 31, 2015, 2014 and 2013, respectively. These amounts are included in selling, general and administrative expenses in the consolidated statements of operations.

F-29

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

For the years ended December 31, 2015, 2014 and 2013, activity in the number of common stock outstanding was as follows:



	Common Stock
	(in thousands)
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 stock conversions	6,160
Shares issued in connection with amended shareholder agreement	775
Balance as of December 31, 2013	68,641
Shares issued in connection with stock plans	304
Shares issued for payment of preferred stock dividends	3
Shares issued in connection with amended shareholder agreement	659
Balance as of December 31, 2014	69,607
Shares issued in connection with stock plans	693
Shares issued for payment of preferred stock dividends	1
Shares issued in connection with preferred stock conversions	101
Shares issued in connection with amended shareholder agreement	558
Balance as of December 31, 2015	70,960


(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. As of December 31, 2015 and 2014, we had zero and 68,180 shares of convertible preferred stock issued and outstanding, respectively.

Preferred Stock Conversions. As of December 31, 2012, we had 4,220,000 shares of 8.5% convertible preferred stock issued and outstanding. During the year ended December 31, 2013, certain holders converted 4,151,820 shares of preferred stock to 6,160,057 shares of our common stock. There were no conversions of preferred stock during the year ended December 31, 2014. The remaining 68,180 shares of our preferred stock outstanding as of December 31, 2014 were converted to 101,150 shares of our common stock during the year ended December 31, 2015.


(c)	Dividends

Common Stock Dividends. During the year ended December 31, 2015, we paid cash dividends on common stock totaling $0.55 per share, which reflects an increase to our regular quarterly cash dividend from $0.10 per share to $0.15 per share during the second quarter.

During the year ended December 31, 2014, we paid cash dividends on common stock totaling $0.53 per share, which included a special non-recurring dividend of $0.21 per share and an increase to our regular quarterly cash dividend from $0.06 per share to $0.10 per share during the third quarter.

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 and an increase to regular quarterly cash dividend from $0.04 per share to $0.06 per share during the second quarter.

Additionally, the non-controlling interest shareholders of Alon Assets received aggregate cash dividends of $415, $1,134 and $886 during the years ended December 31, 2015, 2014, and 2013, respectively.

Preferred Stock Dividends. During the years ended December 31, 2015 and 2014, we issued 771 and 3,174 shares of our common stock in aggregate for payment of the 8.5% preferred stock dividend.

F-30

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)


(d)	Accumulated Other Comprehensive Loss

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



	Unrealized Gain (Loss) on Cash Flow Hedges			Postretirement Benefit Plans			Total
Balance at December 31, 2014	$	21,330		$	(29,788	)	$	(8,458	)
Other comprehensive income (loss) before reclassifications	3,405			(85		)	3,320
Amounts reclassified from accumulated other comprehensive income (loss)	(26,092		)	2,422			(23,670		)
Net current-period other comprehensive income (loss)	(22,687		)	2,337			(20,350		)
Balance at December 31, 2015	$	(1,357	)	$	(27,451	)	$	(28,808	)


(17)	Stock-Based Compensation (share values 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, 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, which vest over a period of three years, assuming continued service at vesting. In May 2015, we granted awards of 6,028 restricted shares at a grant date price of $16.59 per share. In May 2014, we granted awards of 4,965 restricted shares at a grant date price of $15.11 per share.

In August 2015, we granted awards of 69,980 restricted shares to certain executive officers at a grant date price of $21.00 per share. These August 2015 restricted shares will vest as follows: 50% in August 2016 and 50% in August 2019, assuming continued service at vesting.

In July 2015, we granted awards of 100,000 restricted shares to our CEO and President at a grant date price of $18.82 per share. These July 2015 restricted shares will fully vest in July 2016, assuming continued service at vesting.

In May 2015, we granted awards of 255,000 restricted shares to certain executive officers at a grant date price of $16.59 per share. These May 2015 restricted shares will fully vest in May 2016.

In August 2014, we granted awards of 69,980 restricted shares to certain executive officers at a grant date price of $13.65 per share. These August 2014 restricted shares are 50% vested as of December 31, 2015, with the remaining 50% vesting in August 2019, assuming continued service at vesting.

In May 2014, we granted awards of 255,000 restricted shares to certain executive officers at a grant date price of $15.11 per share. These May 2014 restricted shares are 50% vested as of December 31, 2015, with the remaining 50% vesting in May 2016, assuming continued service at vesting.

The following table summarizes the restricted share activity from December 31, 2013:



			Weighted Average Grant Date Fair Values
Non-vested Shares	Shares		(per share)
Non-vested at December 31, 2013	448,694		$	14.64
Granted	329,945		14.80
Vested	(134,640	)	16.95
Forfeited	—		—
Non-vested at December 31, 2014	643,999		$	14.24
Granted	431,008		17.82
Vested	(169,280	)	14.69
Forfeited	—		—
Non-vested at December 31, 2015	905,727		$	15.86

F-31

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

As of December 31, 2015, the remaining non-vested restricted shares are scheduled to vest over the next four years, assuming continued service, as follows: 830,073 shares in 2016; 3,664 shares in 2017; 2,010 shares in 2018; and 69,980 shares in 2019. Compensation expense for the restricted stock grants amounted to $7,369, $4,151 and $3,005 for the years ended December 31, 2015, 2014 and 2013, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations. The fair value of shares vested in 2015 was $2,992.

Partnership Restricted Units. Non-employee directors of the Partnership, who are designated by Alon’s directors, are awarded an annual grant of $25 in restricted common units, which vest over a period of three years, assuming continued service at vesting. During the year ended December 31, 2015, we granted awards of 3,489 restricted common units at an average grant date price of $21.50 per unit. During the year ended December 31, 2014, we granted awards of 4,083 restricted common units at an average grant date price of $18.38 per unit. Compensation expense for the Partnership’s restricted common unit grants amounted to $61 and $87 for the years ended December 31, 2015 and 2014, respectively. These amounts are included in selling, general and administrative expenses in the consolidated statements of operations.

Restricted Stock Units. In 2011, we granted 500,000 restricted stock units to our CEO and President 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 vested in March 2015. Compensation expense for the restricted stock units amounted to $249, $1,496 and $1,496 for the years ended December 31, 2015, 2014 and 2013, respectively. These amounts are included in selling, general and administrative expenses in the consolidated statements of operations.

Unrecognized Compensation. As of December 31, 2015, there was $4,578 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Plan, which is expected to be recognized over a weighted-average period of 0.7 years.


(18)	Income Taxes

Income tax expense included the following:



	Year Ended December 31,
	2015			2014			2013
Current:
Federal	$	44,694		$	15,171		$	1,348
State	(2,318		)	1,781			2,525
Total current	$	42,376		$	16,952		$	3,873
Deferred:
Federal	$	3,360		$	7,176		$	9,770
State	2,546			(1,215		)	(1,492		)
Total deferred	5,906			5,961			8,278
Income tax expense	$	48,282		$	22,913		$	12,151

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



	Year Ended December 31,
	2015			2014			2013
Computed expected tax expense	$	45,734		$	32,474		$	21,093
State and local income taxes, net of federal benefit	1,604			532			844
Tax effect of non-controlling interest in Partnership income	(10,272		)	(11,097		)	(8,927		)
Changes in non-deductible goodwill	13,660			1,411			—
Other, net	(2,444		)	(407		)	(859		)
Income tax expense	$	48,282		$	22,913		$	12,151

F-32

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

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,
	2015		2014
Deferred income tax assets:
Accounts receivable, allowance	$	198	$	198
Inventories	9,530		8,420
Accrued liabilities and other	1,605		1,718
Post-retirement benefits	18,437		19,627
Derivative instruments designated as cash flow hedges	800		(12,817		)
Non-current accrued liabilities and other	24,383		24,994
Net operating loss carryover	21,212		22,122
Tax credits	1,150		1,154
Other	4,332		3,484
Deferred income tax assets	$	81,647	$	68,900
Deferred income tax liabilities:
Deferred gain on the Offering of the Partnership	$	50,178	$	50,178
Deferred charges	401		469
Unrealized gains	4,645		2,346
Property, plant and equipment	364,321		375,330
Other non-current	17,535		3,316
Intangibles	11,361		10,175
Deferred income tax liabilities	$	448,441	$	441,814

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, 2015, we have net operating loss carryforwards for state and local income tax purposes of $398,027 which are available to offset future state taxable income in various years through 2033.

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, 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 2010 are closed to audit. In general, the state tax years open to audit range from 2010 to 2014. Our liability for unrecognized tax benefits and accrued interest did not increase during the year ended December 31, 2015, as there were no unrecognized tax benefits recorded in 2015.

F-33

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)


(19)	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. Diluted earnings per share includes the dilutive effect of granted stock appreciation rights, granted restricted common stock units, granted restricted common stock awards, 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, 2015, 2014 and 2013, is as follows (shares in thousands, per share value in dollars):



	Year Ended December 31,
	2015		2014		2013
Net income available to stockholders	$	52,751	$	38,457	$	22,986
less: preferred stock dividends	15		59		2,288
Net income available to common stockholders	52,736		38,398		20,698

Weighted average shares outstanding, basic	69,772		68,985		63,538
Dilutive common stock equivalents	942		388		1,314
Weighted average shares outstanding, diluted	70,714		69,373		64,852
Earnings per share, basic	$	0.76	$	0.56	$	0.33
Earnings per share, diluted	$	0.75	$	0.55	$	0.32

For the years ended December 31, 2015 and 2014, the weighted average number of diluted shares includes all potentially dilutive securities. For the year ended December 31, 2013, 4,509 common stock equivalents were excluded from the weighted average number of diluted shares outstanding as the effect of including such shares would be anti-dilutive.


(20)	Related Party Transactions

(a)Preferred Stock Conversions

During the years ended December 31, 2015 and 2013, 68,180 and 651,820 shares of 8.5% convertible preferred stock held by certain shareholders of Alon Israel were converted into 101,150 and 967,107 shares of our common stock, respectively. During the year ended December 31, 2014, there were no conversions of preferred stock. At December 31, 2015, no shares of preferred stock remained outstanding.

(b)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. During each of the years ended December 31, 2015, 2014 and 2013, $1,755 was paid to BSRE.

(c)Delek US Holdings, Inc.

In May 2015, Delek completed the purchase of approximately 48% of our outstanding common stock from Alon Israel. Including amounts prior to the transaction, we had purchases from Delek of $15,281, $5,486 and $25,888 for the years ended December 31, 2015, 2014 and 2013, respectively. Accounts payable includes a balance outstanding to Delek of $532 and $134 at December 31, 2015 and 2014, respectively.

F-34

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)


(21)	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 years. Certain long-term operating leases relating to buildings, land and pipelines include options to renew for additional periods. At December 31, 2015, minimum lease payments on operating leases were as follows:



Year ending December 31,
2016	$	27,290
2017	25,598
2018	17,891
2019	10,362
2020	8,270
2021 and thereafter	37,137
Total	$	126,548

Total rental expense was $40,811, $35,699 and $33,965 for the years ended December 31, 2015, 2014 and 2013, 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, which 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. Our minimum commitment under this agreement is $26,005 for 2016. 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 which is a $14,280 commitment for 2016. 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 Pipeline L.P. (“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 which is a $2,460 commitment for 2016.

We have entered into a transportation services agreement with Navigator BSG Transportation & Storage, LLC (“Navigator”), which provides for the construction and operation of a pipeline system to facilitate delivery of crude oil to the Big Spring refinery from a number of injection points in the area of the refinery. Shipments of crude oil pursuant to the agreement with Navigator are expected to commence in March 2016. The term of the agreement begins upon the commencement of shipments and continues for an initial period of ten years, with two additional five-year renewal terms exercisable at our sole option. Our minimum throughput commitment is 10,000 bpd which is a $1,798 commitment for 2016.

F-35

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

We have offtake agreements with two investment grade oil companies that provides for the sale, at market prices, of high sulfur distillate blendstock and light cycle oil, through June and September 2017. 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 preclude recovery. Attempts to reach a commercial arrangement to resolve the dispute have been unsuccessful to this point. This matter is currently scheduled for trial in June 2016. 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 are associated with 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 expired on March 1, 2015. However, 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 $46,362 ($7,880 current liability and $38,482 non-current liability) at December 31, 2015, and $51,735 ($8,189 current liability and $43,546 non-current liability) at December 31, 2014. Environmental liabilities with payments that are fixed or reliably determinable have been discounted to present value at a rate of 2.47%.

The table below summarizes our environmental liability accruals:



	As of December 31,
	2015		2014
Discounted environmental liabilities	$	43,526	$	46,150
Undiscounted environmental liabilities	2,836		5,585
Total accrued environmental liabilities	$	46,362	$	51,735

F-36

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

As of December 31, 2015, the estimated future payments of environmental obligations for which discounts have been applied are as follows:



Year ending December 31,
2016	$	5,487
2017	4,248
2018	3,671
2019	3,466
2020	3,300
2021 and thereafter	31,767
Discounted environmental liabilities, gross	51,939
Less: Discount applied	8,413
Discounted environmental liabilities	$	43,526

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 $623 and $784 and non-current receivables of $2,648 and $3,030 at December 31, 2015 and 2014, respectively.

We had an indemnification agreement with a prior owner for remediation expenses at the Bakersfield refinery. We have recorded current receivables of $0 and $3,350 at December 31, 2015 and 2014, respectively.


(22)	Quarterly Information (unaudited)

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



	Quarters
	First		Second			Third		Fourth (1)
2015
Net sales	$	1,103,240	$	1,301,341		$	1,151,204	$	782,367
Operating income (loss)	67,561		88,094			86,854		(39,100		)
Net income (loss)	34,055		47,862			52,376		(51,906		)
Net income (loss) available to stockholders	26,939		36,410			41,936		(52,534		)
Earnings (loss) per share:
Basic	$	0.39	$	0.52		$	0.60	$	(0.75	)
Diluted	$	0.38	$	0.50		$	0.58	$	(0.75	)

2014
Net sales	$	1,683,245	$	1,742,883		$	1,850,097	$	1,503,231
Operating income	38,960		18,932			94,005		49,675
Net income (loss)	8,375		(6,437		)	53,474		14,456
Net income (loss) available to stockholders	785		(7,517		)	38,482		6,707
Earnings (loss) per share:
Basic	$	0.01	$	(0.11	)	$	0.56	$	0.10
Diluted	$	0.01	$	(0.11	)	$	0.55	$	0.10

_______________________


(1)	During the three months ended December 31, 2015, we recognized a goodwill impairment loss of $39,028 related to our California refining reporting unit (Note 11).

F-37

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)


(23)	Subsequent Events

Dividend Declared

Partnership Distribution

On February 10, 2016, the board of directors of the General Partner declared a cash distribution to the Partnership’s common unitholders of $5,001, or $0.08 per common unit. The cash distribution will be paid on February 29, 2016 to unitholders of record at the close of business on February 22, 2016. The total cash distribution paid to non-affiliated common unitholders will be $921.

F-38

Table of Contents

EXHIBITS



Exhibit No.		Description of Exhibit
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 3.1 to Form 8-K, filed by the Company on February 4, 2016, 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 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).
4.4		Form of Certificate of Designation of the 8.5% 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).
4.5		Form of Certificate of Designation of the 8.5% 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		Form of Registration Rights Agreement among the Company and Subsidiary Shareholders (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on June 26, 2012, SEC File No. 001-32567).
10.8		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).
10.9		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).
10.10		Second Amendment, 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).
10.11		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).
10.12		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).
10.13		Second Amended and Restated Credit Agreement, dated as of March 14, 2014, among Southwest Convenience Stores, LLC, Skinny’s, LLC, as the Borrowers, Alon Brands, Inc., as a Guarantor, the lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender, LC Issuer, Syndication Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on March 26, 2014, SEC File No. 001-32567).

Table of Contents



Exhibit No.		Description of Exhibit
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 between Paul Eisman and Alon USA GP, LLC, dated May 11, 2015 (incorporated by reference to Exhibit 10.2 to Form 8-K filed by the Company on May 15, 2015, 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).
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*		First Amendment to Amended and Restated Employment Agreement dated May 12, 2015 between Alon P. Moret and Alon USA GP, LLC, dated May 11, 2015 (incorporated by reference to Exhibit 10.4 to Form 8-K filed by the Company on May 15, 2015, SEC File No. 001-32567).
10.31*		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).

Table of Contents



Exhibit No.		Description of Exhibit
10.32*		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).
10.33*		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).
10.34*		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).
10.35*		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).
10.36*		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).
10.37*		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).
10.38*		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).
10.39*		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).
10.40*		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).
10.41†		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).
10.42*		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).
10.43*		Second Amendment to Shareholder Agreement, dated May 12, 201 5 among Alon USA Energy, Inc., Alon Assets, Inc., Jeff Morris and Jeff Morris/IRA (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on May 15, 2015, SEC File No. 001-32567).
10.44*		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).
10.45*		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).
10.46*		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).
10.47*		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).
10.48*		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).
10.49*		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).
10.50*		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).
10.51*		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).
10.52*		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).

Table of Contents



Exhibit No.		Description of Exhibit
10.53*		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).
10.54*		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).
10.55*		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).
10.56*		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).
10.57*		Second Amendment to Restricted Stock Award Agreement between Alon USA GP, LLC and Alan Moret, dated September 2, 2015 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on September 8, 2015, SEC File No. 001-32567).
10.58*		Restricted Stock Award Agreement between Alon USA Energy, Inc. and Paul Eisman, dated May 11, 2015 (incorporated by reference to Exhibit 10.3 to Form 8-K filed by the Company on May 15, 2015, SEC File No. 001-32567).
10.59		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).
10.60		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).
10.61		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).
10.62		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).
10.63		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).
10.64		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).
10.65†		Second Amended and Restated Supply and Offtake Agreement, dated February 1, 2015 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 8, 2015, SEC File No. 001-32567).
10.66†		Second Amended and Restated Supply and Offtake Agreement by and between Alon USA, LP and J. Aron & Company, dated February 1, 2015 (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on May 8, 2015, SEC File No. 001-32567).
10.67†		Amended and Restated Supply and Offtake Agreement by and between J. Aron & Company and Alon Supply, Inc., dated February 1, 2015 (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 8, 2015, SEC File No. 001-32567).
10.68		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).
10.69		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).
10.70		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).
10.71		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).

Table of Contents



Exhibit No.		Description of Exhibit
10.72		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).
10.73		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).
10.74		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).
10.75		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).
10.76		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).
10.77		Second Amendment to Second Amended and Restated Revolving Credit Agreement, dated May 6, 2015, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.4 to Form 10-Q filed by the Company on May 8, 2015, SEC File No. 001-32567).
10.78		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).
10.79		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).
10.80		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).
10.81		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).
10.82		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).
10.83		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).
10.84		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).
10.85		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.
101		The following financial information from Alon USA Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2015, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statement of Stockholders’ Equity, (v) Consolidated Statements of Cash Flows and (vi) Notes to Consolidated Financial Statements.

____________


*	Identifies management contracts and compensatory plans or arrangements.


†	Filed under confidential treatment request.

Table of Contents

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:	February 26, 2016	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:	February 26, 2016	By:	/s/ Ezra Uzi Yemin
			Ezra Uzi Yemin
			Chairman of the Board

Date:	February 26, 2016	By:	/s/ David Wiessman
			David Wiessman
			Executive Director

Date:	February 26, 2016	By:	/s/ Paul Eisman
			Paul Eisman
			President and Chief Executive Officer

Date:	February 26, 2016	By:	/s/ Shai Even
			Shai Even
			Senior Vice President and Chief Financial Officer
			(Principal Accounting Officer)

Date:	February 26, 2016	By:	/s/ Jeff D. Morris
			Jeff D. Morris
			Director

Date:	February 26, 2016	By:	/s/ Ron W. Haddock
			Ron W. Haddock
			Director

Date:	February 26, 2016	By:	/s/ Yeshayahu Pery
			Yeshayahu Pery
			Director

Date:	February 26, 2016	By:	/s/ Zalman Segal
			Zalman Segal
			Director

Date:	February 26, 2016	By:	/s/ Ilan Cohen
			Ilan Cohen
			Director

Date:	February 26, 2016	By:	/s/ Assaf Ginzburg
			Assaf Ginzburg
			Director

Date:	February 26, 2016	By:	/s/ Frederec Green
			Frederec Green
			Director

Date:	February 26, 2016	By:	/s/ Mark D. Smith
			Mark D. Smith
			Director

Date:	February 26, 2016	By:	/s/ Avigal Soreq
			Avigal Soreq
			Director

Alon USA Energy, Inc. - FORM 10-K - February 26, 2016

Attached files

Alon USA Energy, Inc. Reports