ALJ Alon Usa Energy Common Stick

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)

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“ Distillates ” Primarily diesel, kerosene and jet fuel, as well as light cycle oil.

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

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

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PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES.

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

Company Overview

In this Annual Report, the words “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 the Partnership (NYSE: ALDW), which owns a crude oil refinery in Big Spring, Texas, with a crude oil throughput capacity of 73,000 bpd 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 own a majority interest in a renewable fuels facility in California, with a throughput capacity of 3,000 bpd. 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 .

On January 2, 2017, we, Delek, HoldCo, Parent Merger Sub and Astro Merger Sub entered into the Merger Agreement pursuant to which (i) Parent Merger Sub will, upon the terms and subject to the conditions thereof, merger with and into Delek (the “Parent Merger”), with Delek surviving as a wholly owned subsidiary of Holdco and (ii) Astro Merger Sub will, upon the terms and subject to the conditions thereof, merge with and into Alon (the “Astro Merger” and, together with the Parent Merger, the “Mergers”), with Alon surviving.

In the Parent Merger, each issued and outstanding share of common stock of Delek, par value $0.01 per share (“Delek Common Stock”), or fraction thereof, will be converted into the right to receive one validly issued, fully paid and non-assessable share of Holdco common stock, par value $0.01 per share (“New Common Stock”) or such fraction thereof equal to the fractional share of Delek Common Stock, upon the terms and subject to the conditions set forth in the Merger Agreement.

In the Astro Merger, each issued and outstanding share of common stock of Alon, par value $0.01 per share (“Alon Common Stock”), other than Alon Common Stock held by Delek or any subsidiary of Delek, will be converted into the right to receive 0.504 validly issued, fully paid and non-assessable shares of New Common Stock, upon the terms and subject to the conditions set forth in the Merger Agreement (the “New Stock Issuance”).

The completion of the Mergers is subject to satisfaction or waiver of certain customary closing conditions and is expected to close in the first half of 2017.

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;

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•	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 in Item 8, “Financial Statements and Supplementary Data,” of 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. Our refining and marketing segment also includes our majority ownership interest in a renewable fuels facility in California, which has a throughput capacity of 3,000 bpd. We primarily 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.

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, 2016 , 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 priced in Midland, Texas (“Midland”), which has generally traded at a discount to Cushing, Oklahoma (“Cushing”) prices.

Our Big Spring refinery produces ultra-low sulfur gasoline, ultra-low sulfur diesel, jet fuel, petrochemicals, liquefied petroleum gas, 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 2016, this refinery achieved a liquid recovery of 100.0% .

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 been added to alleviate those constraints. The lower price of crude during 2015 and 2016 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 2016 , our Big Spring refinery’s total refinery throughput was comprised of 43.4% WTS, 51.7% WTI Midland and 4.9% 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, Medallion and Navigator pipelines.

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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, Texas, and Phoenix, Arizona, 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 . Asphalt produced at the Big Spring refinery is sold to our asphalt segment at prices substantially determined by reference to the cost of crude and Rocky Mountain asphalt, which is intended to approximate bulk wholesale market prices.

Petrochemicals, Liquefied Petroleum Gas 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 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 639 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 2016 , we sold 315.9 million gallons of gasoline and 87.1 million gallons of diesel as branded fuels, which represented 58% of the gasoline and 25% 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 2016 , we sold 153.7 million gallons of gasoline and 26.3 million gallons of diesel to our retail convenience stores, which represented 28% of the gasoline and 8% 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 2016 , we sold 139.9 million gallons of gasoline and 245.4 million gallons of diesel as unbranded fuels, which were largely sold through our physically integrated system. These unbranded fuel sales represented 26% 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. The petrochemical feedstocks and 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 21 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, (2) deliver products to 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.

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Product Terminals

We primarily utilize three product terminals in Big Spring, Abilene, and Wichita Falls, Texas to market transportation fuels produced at our Big Spring refinery, as well as a terminal in Duncan, Oklahoma. 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 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 101.8% in 2016.

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 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.

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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.

On March 1, 2016, we acquired control of the California renewable fuels facility, which initially provides for us to receive approximately 77% of earnings and distributions of the facility. We increased our original 32% ownership and obtained control of the California renewable fuels facility after certain operational milestones were achieved. Our share of earnings and distributions will change upon the achievement of certain cash distribution milestones. In each case following the achievement of cash distribution milestones and assuming no further dilution to any of the members in the facility, our share of earnings and distributions will be reduced to approximately 57% and then be increased to approximately 62%, at which time the percentage will become fixed.

The facility utilizes existing equipment at our southern California refinery and newly installed equipment to convert approximately 3,000 barrels per day of tallow and other feedstocks into renewable fuels, which are drop-in replacements for petroleum-based fuels. These fuels provide the same performance as conventional, petroleum-based fuels. The facility generates environmental credits in the form of renewable identification numbers and California low-carbon fuels standards credits, as well as the blender’s tax credits, when effective. Our California renewable fuels facility began operations in February 2016.

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/Terminals

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 one of our largest customers 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 the identification of prospective purchasers of refined products on J. Aron’s behalf.

For additional information on our Supply and Offtake Agreements, see Note 10 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.

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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. Through our asphalt facilities, we are marketing a number of different product formulations, including both polymer modified asphalt and ground tire rubber 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 and Rocky Mountain asphalt, 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

As of December 31, 2016 , we operated 306 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.

As of December 31, 2016 , we had 296 retail convenience store sites that offer various grades of gasoline and diesel under the Alon brand name.

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. Substantially all of the merchandise sales at our convenience store sites are sold under the 7-Eleven brand name.

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 may have a 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 Tesoro. 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, 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.

Asphalt

We compete in the asphalt market with various refiners including Valero, Tesoro, U.S. Oil, 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 Chevron, Murphy USA, Sunoco LP (Stripes® brand), Alimentation Couche-Tard Inc. (Circle K® brand and CST brand), Tesoro 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, H-E-B, Kroger, Sam’s Club 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.

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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 approximately $32 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 2013-2016 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 2016, we were able to meet 79% 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 gasoline 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. Distillates produced at the Krotz Springs refinery are not subject to the requirements of the RFS-2 program.

In February 2017, the Krotz Springs refinery received approval from the EPA for a small refinery exemption from the requirements of the renewable fuel standard for the 2016 calendar year. As a result, we expect to record a reduction in RINs expense of $29.0 million in the first quarter of 2017, based on a weighted average RINs price per gallon of $0.58.

On December 14, 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. On December 12, 2016, the EPA published a final rule in the Federal Register establishing the renewable fuel volume mandates for 2017, and the biomass-based diesel mandate for 2018. The volumes included in the EPA’s final rules 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 authorities to lower the volumes, but its decision to do so in the December 14, 2015 final rule has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In addition, in the December 14, 2015 final rule, 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 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 purchase of cap-and-trade allowances or capital expenditures to increase efficiency of our operations and reduce GHG emissions from both stationary and non-stationary sources at our California refineries and possibly our other California terminals.

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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. The cost to purchase GHG reduction credits are passed through as a surcharge within the California market-place.

In September 2016, the Governor of California signed into law SB 32, requiring the State to reduce its GHG emissions to at least 40% below 1990 levels by 2030. The law does not specify how California will achieve these additional reductions, but it may require further reductions in GHG emissions from our California refineries and our other California terminals.

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 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 September 2016, approximately 95% 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 expect the costs and controls or civil penalties to be comparable to other settling refineries. The civil penalty will likely exceed $100,000 and other 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 that continue until the consent decree is terminated.

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.

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. Settlement discussions with the EPA are ongoing, and the costs of any such settlement or enforcement, if finalized, are not expected to be material.

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Remediation Efforts . We are currently remediating historical soil and groundwater contamination at our Big Spring refinery and terminals system. We spent $1.0 million in 2016 for remediation costs, and we estimate an additional $0.8 million will be spent during 2017 . We are also remediating historical soil and groundwater contamination at the Abilene, Southlake and Wichita Falls, Texas, 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, California, 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 2016 , a total of $1.5 million was spent for all four of these remediation projects of which our portion was $0.9 million. We estimate that an additional $2.2 million will be spent in 2017 with our portion being $1.5 million.

We have an environmental insurance policy related to our Long Beach refinery, which expires in 2017, that 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 $0.2 million in 2016 for remediation costs and we estimate an additional $0.6 million will be spent during 2017.

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 $0.9 million in 2016 for these remediation costs, and we estimate that an additional $0.9 million will be spent during 2017 .

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 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. Under the PMPA, the refiner permits a distributor to use a trademark in connection with the sale or distribution of motor fuel. 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.

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Employees

As of December 31, 2016 , we had approximately 2,830 employees. Approximately 640 employees worked in our refining and marketing segment, of which approximately 490 were employed at our refineries and approximately 150 were employed at our corporate offices in Dallas, Texas. Approximately 90 employees worked in our asphalt segment and approximately 2,100 employees worked in our retail segment.

Approximately 210 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, 2016 , we were the lessee under a number of cancelable and non-cancelable leases for certain properties. For additional information on our leases, see Note 22 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 substantially all of our properties 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. This discussion excludes our retail assets and the California renewable fuels facility, which have different coverages and deductibles.

We maintain third-party liability insurance policies that cover third-party claims with a $300 million limit, except for our California renewable fuels facility that has a $350 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, 2017, and their business experience during at least the past five years are set forth below.

Name		Age		Position
Alan Moret		62		Interim Chief Executive Officer
Shai Even		48		Senior Vice President and Chief Financial Officer
Claire A. Hart		61		Senior Vice President
Michael Oster		45		Senior Vice President of Mergers and Acquisitions
Jimmy C. Crosby		57		Senior Vice President of Refining
James Ranspot		46		Senior Vice President, General Counsel and Secretary
Scott Rowe		58		Senior Vice President of Asphalt Marketing
Jeff Brorman*		48		Vice President of Refining — Big Spring
Gregg Byers*		62		Vice President of Refining — Krotz Springs
Kyle McKeen*		53		President and Chief Executive Officer of Alon Brands
Josef Lipman*		71		President and Chief Executive Officer of SCS

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

Alan Moret was appointed Interim Chief Executive Officer in January 2017. Mr. Moret served as our Senior Vice President of Supply from August 2008 to January 2017. 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.

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

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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 President, Chief Financial Officer and 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.

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 operations 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.

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.

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ITEM 1A. RISK FACTORS.

The occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report on Form 10-K or in any other of our filings with the SEC could have a material adverse effect on our business, financial position, results of operations and cash flows. In evaluating an investment in any of our securities, you should consider carefully, among other things, the factors and the specific risks set forth below. This Annual Report on Form 10-K contains forward-looking statements that involve risks and uncertainties. See “Forward-Looking Statements” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of the factors that could cause actual results to differ materially from those projected.

Risks Related to the Mergers

The ability of Delek and Alon to complete the Mergers is subject to a number of conditions, including the absence of antitrust or other challenges from governmental entities, which could delay or cause us to abandon the Mergers.

In connection with Delek’s acquisition of approximately 48% of Alon’s common stock in May 2015, Notification and Report Forms required by the Hart-Scott-Rodino Antitrust Improvements Act (“HSR Act”) were filed with the Department of Justice and the Federal Trade Commission. The Federal Trade Commission granted early termination of the applicable HSR Act waiting period to the parties in May 2015 and renewed this antitrust approval in May 2016. However, this antitrust approval expires on May 2, 2017. If the Alon Merger is not completed prior to May 2, 2017, an additional antitrust filing with the Department of Justice and Federal Trade Commission will be required. If an additional antitrust filing is required, we cannot assure that this antitrust approval will be granted on terms and conditions acceptable to Delek and Alon, if at all. In addition, we cannot assure you that a challenge to the Mergers will not be made or that, if a challenge is made, it will not succeed.

Regardless of whether an additional antitrust filing is required upon expiration of the existing antitrust approval, completion of the Mergers is subject to the fulfillment of a number of other conditions which make the completion and timing of the transaction uncertain. These conditions include, among others, conditions that the New Delek share issuance proposal be approved by the affirmative vote of a majority of the votes cast by holders of shares of Delek common stock present in person or represented by proxy and entitled to vote at the Delek special meeting; that the Alon merger proposal be approved by the affirmative vote of the holders of the majority of the outstanding shares of Alon common stock and the affirmative vote of the holders of a majority of the issued and outstanding shares of Alon common stock beneficially owned by the holders of Alon common stock other than the Delek, HoldCo, Delek Merger Sub, Alon Merger Sub and their affiliates; the registration statement on Form S-4 registering the shares of New Delek common stock to be issued in connection with the transaction, be declared effective by the SEC and no stop order suspending effectiveness of the registration be in effect; the NYSE approve the listing of such shares for trading on the NYSE; and no order, decree or injunction of any court or agency of competent jurisdiction or law be in effect that enjoins or otherwise prohibits the Mergers. These conditions may not be fulfilled, and if this occurs, the Mergers may not be completed. In addition, if the Mergers are not completed by October 2, 2017, either Delek or Alon may choose not to proceed with the Mergers, and the parties can mutually decide to terminate the merger agreement at any time prior to the consummation of the Mergers, before or after stockholder approval. In addition, Delek or Alon may elect to terminate the merger agreement in certain other circumstances.

Any delay in completing the Mergers may reduce or eliminate the expected benefits from the transaction.

The Mergers are subject to a number of conditions beyond Delek’s and Alon’s control that may prevent, delay or otherwise materially adversely affect its completion. Delek and Alon cannot predict whether and when these other conditions will be satisfied. There can be no assurance that either Delek or Alon or both parties will waive any condition to closing that is not satisfied. Furthermore, the requirements for obtaining the required clearances and approvals and the time required to satisfy any other conditions to the closing could delay the completion of the Mergers for a significant period of time or prevent the transaction from occurring. Any delay in completing the Mergers could cause Delek not to realize some or all of the benefits that it expects to achieve if the Mergers are successfully completed within the expected timeframe.

Failure to complete the Mergers could negatively impact the stock prices and the future business and financial results of Delek and Alon.

If the Mergers are not completed, the ongoing businesses of Delek or Alon may be adversely affected and Delek and Alon will be subject to several risks, including the following:

•	being required, under certain circumstances, to pay a termination fee of $20 million, in the case of a payment by Delek to Alon, and $15 million, in the case of a payment by Alon to Delek;

•	having to pay certain costs relating to the proposed Merger, such as legal, accounting, financial advisor, filing, printing and mailing fees; and

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•	the focus of management of each of the companies on the Mergers instead of on pursuing other opportunities that may be beneficial to each company.

If the Mergers do not occur, Delek and Alon may incur these costs without realizing any of the benefits of the Mergers being completed. In addition, if the Mergers are not completed, Delek and/or Alon may experience negative reactions from the financial markets and from their respective customers and employees. Delek and/or Alon could also be subject to litigation related to any failure to complete the Mergers or to enforcement proceedings commenced against Delek or Alon to perform their respective obligations under the merger agreement. If the Mergers are not completed, Delek and Alon cannot assure their respective stockholders that these risks will not materialize or will not materially affect the business, financial results and stock prices of Alon or Delek.

The Merger Agreement contains provisions that could discourage a potential competing acquiror from making a competing acquisition proposal.

The Merger Agreement contains “no shop” provisions that, subject to limited exceptions, restrict the ability of Alon to initiate, solicit, knowingly encourage or facilitate competing third-party proposals of offers to acquire all or a significant part of Alon. Further, even if the board of directors of Alon withdraws or modifies its recommendation of the Alon merger proposal, it will still be required to submit the matter to a vote of the Alon stockholders at the Alon special meeting unless the merger agreement is terminated in accordance with its terms. In addition, Delek generally has an opportunity to offer to modify the terms of the Alon Merger and the merger agreement in response to any competing acquisition proposals (as defined in the merger agreement) that may be made before the board of directors of Alon may withdraw or modify its recommendation. In some circumstances, upon termination of the merger agreement, one of the parties may be required to pay a termination fee to the other party. Delek is subject to similar “no shop provisions” with respect to competing third-party proposals to acquire all or a significant part of Delek.

These provisions could discourage a potential competing acquiror from considering or proposing an acquisition, even if it were prepared to pay consideration with a higher per share cash or market value than that market value proposed to be received or realized in the Mergers, or might result in a potential competing acquiror proposing to pay a lower price than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances.

The Mergers will involve substantial costs.

Delek and Alon have incurred and expect to continue to incur substantial costs and expenses relating directly to the Mergers, including fees and expenses payable to financial advisors, other professional fees and expenses, insurance premium costs, fees and costs relating to integration planning activities, regulatory filings and notices, SEC filing fees, printing and mailing costs and other transaction-related costs, fees and expenses. If the Mergers are not completed, Delek and Alon will have incurred substantial expenses and devoted substantial management time for which no ultimate benefit will have been received by either company.

The pendency of the Mergers and related uncertainty could adversely affect the relationships of Delek and Alon with employees, customers, commercial partners, financing parties and other third parties.

Uncertainty about the effect of the Mergers on employees, customers, commercial partners and other third parties may have an adverse effect on Alon and Delek. These uncertainties may cause customers, suppliers, commercial partners, financing parties and others that deal with Alon or Delek to seek to change, delay or defer decisions with respect to existing or future business relationships. Retention, hiring and motivation of certain current and prospective employees by Alon or Delek may be challenging while the Mergers are pending, as they may experience uncertainty about their future roles with Alon or Delek. If key employees, customers, suppliers, commercial partners, financing parties and other third parties terminate or change, or seek to terminate or change, their existing relationships with Alon or Delek, Alon’s business or Delek’s business, and the combined company’s business as a result, could be harmed.

The consummation of the Alon Merger may permit counterparties to other agreements to terminate those agreements.

Alon is party to certain agreements that give the counterparties to such agreements, including investors and commercial partners, certain rights, including notice, consent and other rights in connection with “change of control” transactions or otherwise, that may give rise to a default by Alon under the agreements or a right by the counterparty to terminate the agreement. Under certain of these agreements, the Alon Merger may constitute a “change of control” or otherwise give rise to consent or termination rights and, therefore, the counterparties may assert their rights in connection with the Alon Merger and claim a default of the agreement by Alon and/or terminate the agreements, which may adversely affect business and operations of Delek and the value of the New Delek common stock following the Mergers.

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Legal proceedings against Delek or Alon could result in an injunction preventing the completion of the Mergers or a judgment resulting in the payment of damages.

If any litigation challenging the Mergers are brought and not resolved, the lawsuits could prevent or delay completion of the Mergers and result in substantial costs to Delek and Alon, including any costs associated with the indemnification of its respective directors and officers. One condition to closing the Mergers is that no order, decree or injunction of any court or agency of competent jurisdiction be in effect that enjoins, prohibits or makes illegal consummation of any of the transactions, and no legal proceeding by any governmental authority with respect to the Mergers or other transactions be pending that seeks to restrain, enjoin, prohibit or delay consummation of the Mergers or imposes any material restrictions on the transactions contemplated by the merger agreement. If any lawsuit is filed challenging the Mergers and is successful in obtaining an injunction preventing the parties to the merger agreement from consummating the Mergers, such injunction may delay or prevent the Mergers. As such, if plaintiffs are successful in obtaining an injunction prohibiting the consummation of the Mergers or the other transactions contemplated by the merger agreement, then such injunction may prevent the Mergers from being completed, or from being completed within the expected timeframe.

The defense or settlement of any legal proceedings or future litigation could be time-consuming and expensive, divert the attention of Delek management and/or Alon management away from their regular business, and, if any one of these legal proceedings or any future litigation is adversely resolved against either Delek or Alon, could have a material adverse effect on their respective financial condition, results of operations or liquidity of Delek or the combined company if resolved after the Mergers are completed.

Until the completion of the Mergers or the termination of the Merger Agreement in accordance with its terms, in consideration of the agreements made by the parties in the Merger Agreement, Delek and Alon are each prohibited from entering into certain transactions and taking certain actions that might otherwise be beneficial to Delek or Alon and their respective stockholders.

Until the Merger is completed, the Merger Agreement restricts each of Delek and Alon from taking specified actions without the consent of the other party, and requires each of Delek and Alon to operate in the ordinary and usual course of business consistent with past practice. Alon is subject to a number of customary interim operating covenants relating to, among other things, its capital expenditures, incurrence of indebtedness, entry into or amendment of certain types of agreements, equity grants and changes in director, employee, independent contractor and consultant compensation. These restrictions may prevent Delek and/or Alon from making appropriate changes to their respective businesses or pursuing attractive business opportunities that may arise prior to the completion of the Mergers.

Risks Related to the Business

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. 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;

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•	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;

•	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 WTI. 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.

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Midland crude discounts, compared to WTI-Cushing, could contract, which would adversely affect our profitability.

Over the last three years, pipeline capacity additions and expansions have significantly increased takeaway capacity from the Permian Basin. Meanwhile, the lower crude price environment in 2015 and 2016 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.

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.

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Competition in the asphalt industry is intense, and an increase in competition in the markets in which we sell our asphalt products could adversely affect our earnings and profitability.

Our asphalt business competes with other refiners and with regional and national asphalt marketing companies. Many of these competitors are larger, more diverse companies with greater resources, providing them advantages in obtaining crude oil and other blendstocks and in competing through bidding processes for asphalt supply contracts.

We compete in large part on our ability to deliver specialized asphalt products which we produce under proprietary technology licenses. Recently, demand for these specialized products has increased due to new specification requirements by state and federal governments. If we were to lose our rights under our technology licenses, or if competing technologies for specialized products are developed by our competitors, our profitability could be adversely affected.

Competition in the retail industry is intense, and an increase in competition in the markets in which our retail businesses operate could adversely affect our earnings and profitability.

Our retail operations compete with numerous convenience stores, gasoline service stations, supermarket chains, drug stores, fast food operations and other retail outlets. Increasingly, national high-volume grocery and dry-goods retailers, such as 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 motor 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 expenditures, 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

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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.

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 and other 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.

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. 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.

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

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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 one of our largest customers 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.

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 September 2016, approximately 95% 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 expect the costs of controls or civil penalties to be comparable to other settling refiners. The civil penalty will likely exceed $100,000 and other 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 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

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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 approximately $32 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 the warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has adopted regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act, such as rules that require a reduction in GHG emissions from motor vehicles. Another rule requires facilities already subject to the Prevention of Significant Deterioration and Title V operating permitting programs that increase their GHG emissions by 75,000 tons per year to limit GHG emissions through control technology, known as “Best Available Control Technology.” The EPA has also adopted rules that require specified large GHG emission sources in the United States, including petroleum refineries, to monitor and report GHG emissions on an annual basis.

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.

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 $6.6 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 $35.6 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.

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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.

The renewable fuels standards program may reduce demand for the petroleum fuels we produce and could result in significant compliance costs, 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 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 2013-2016 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. The Krotz Springs refinery sells substantially all of its gasoline 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. Distillates produced at the Krotz Springs refinery are not subject to the requirements of the RFS-2 program. Our total RINs costs for 2016 and 2015 were $51.0 million and $35.1 million , respectively.

On December 14, 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. On December 12, 2016, the EPA published a final rule in the Federal Register establishing the renewable fuel volume mandates for 2017, and the biomass-based diesel mandate for 2018. The volumes included in the EPA’s final rules 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 authorities to lower the volumes, but its decision to do so in the December 14, 2015 final rule has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In addition, in the December 14, 2015 final rule, 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 of new EPA fuel economy standards, or other factors, it could have an adverse effect on our business, results of operations and cash flows.

Loss of or reductions to tax incentives for biodiesel production may have a material adverse effect on the earnings, profitability and cash flows relating to our California renewable fuels facility.

The biodiesel industry has historically been substantially aided by federal and state tax incentives. One tax incentive program that has been significant to our California renewable fuels facility is the federal blender’s tax credit. The blender’s tax credit provided a $1.00 refundable tax credit per gallon of pure biodiesel, or B100, to the first blender of biodiesel with petroleum-based diesel fuel. The blender’s tax credit came into existence on January 1, 2005, and had been continuously reinstated until it expired on December 31, 2009 and was re-enacted in December 2010, retroactively for all of 2010 and prospectively for 2011. Since that time, the blender’s tax credit has expired on several occasions, only to be reinstated on a retroactive basis. Most recently, the blender’s tax credit expired on December 31, 2016. Congress has not taken action to reinstate the blender’s tax credit.

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It is uncertain what action, if any, Congress may take with respect to reinstating the blender’s tax credit or when such action might be effective. If Congress does not reinstate the credit, it may result in a material adverse effect on the earnings, profitability and cash flows relating to our California renewable fuels facility.

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,

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fires, explosions, pipeline ruptures and spills, waterborne transportation accidents, third-party interference and mechanical 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 substantially all of our properties 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.

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This discussion excludes our retail assets and the California renewable fuels facility, which have different coverages and deductibles.

We maintain third-party liability insurance policies that cover third-party claims with a $300 million limit, except for our California renewable fuels facility that has a $350 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 standards for determining the required controls applicable to these systems are mandated by credit card issuers and administered by the Payment Card Industry Security Standards Counsel 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 comply with the Payment Card Industry Data Security Standards (PCI-DSS) 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 for violations of the PCI-DSS. 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.

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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, 2016 , we employed approximately 210 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 not currently scheduled for trial. Due to the uncertainties of litigation, we cannot predict with certainty the ultimate resolution of this lawsuit.

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ITEM 4. MINE SAFTETY DISCLOSURES

None.

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PART II

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

Market Information

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

The following table sets forth the quarterly high and low sales prices of our common stock 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
2016
Fourth Quarter		$	11.94			$	6.98			$	0.15
Third Quarter		8.74				5.86				0.15
Second Quarter		11.75				5.92				0.15
First Quarter		15.09				9.20				0.15
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

_______________________

(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.

On February 23, 2017 , our board of directors approved the regular quarterly cash dividend of $0.15 per share on our common stock, payable on March 17, 2017 , to holders of record at the close of business on March 9, 2017 .

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 21, 2017, there were 40 common stockholders of record.

Recent Sales of Unregistered Securities

In June 2012, Alon amended a shareholder agreement among Alon, Jeff Morris, a former executive, and two of our subsidiaries Alon Assets, Inc. (“Alon Assets”) and Alon Operating, Inc. (“Alon Operating”), pursuant to which the non-voting shares of Alon Assets and Alon Operating held by Mr. Morris could be exchanged for shares of our common stock in quarterly installments over a five-year period. In November 2012, Alon Assets and Alon Operating were merged, with Alon Assets being the surviving entity.

The following issuances of shares of our common stock occurred during the December 31, 2016 fiscal year pursuant to the agreement described above:

		Exchange Date		Number of Shares Issued
Jeff D. Morris		January 11, 2016		116,347
		April 11, 2016		116,347
		July 11, 2016		116,347
		October 11, 2016		116,347

The issuances of the shares of common stock to Mr. Morris reflected above were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

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Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

Stockholder Return Performance Graph

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

The following performance graph compares the cumulative total stockholder return on our 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, 2011 to December 31, 2016 , 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.

	12/2011				12/2012				12/2013				12/2014				12/2015				12/2016
Alon	$	100.00			$	210.76			$	197.24			$	156.68			$	189.75			$	155.55
S&P 500	100.00				116.00				153.58				174.60				177.01				198.18
Peer Group	100.00				192.03				273.97				273.86				364.52				346.41

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ITEM 6. SELECTED FINANCIAL DATA.

The following table sets forth selected historical consolidated financial data as of and for each of the five years ending December 31, 2016 . The selected historical consolidated statement of operations data for the years ended December 31, 2016 , 2015 and 2014 , and the selected consolidated balance sheet data as of December 31, 2016 and 2015 , 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, 2013 and 2012 , and the selected consolidated balance sheet data as of December 31, 2014 , 2013 and 2012 , 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,
		2016				2015				2014				2013				2012
		(dollars in thousands, except per share data)
STATEMENTS OF OPERATIONS DATA:
Net sales		$	3,913,404			$	4,338,152			$	6,779,456			$	7,046,381			$	8,017,741
Loss on impairment of goodwill (1)		—				(39,028		)		—				—				—
Operating income (loss)		(67,410		)		203,409				201,572				149,433				269,475
Net income (loss) available to stockholders		(82,805		)		52,751				38,457				22,986				79,134
Earnings (loss) per share, basic		$	(1.17	)		$	0.76			$	0.56			$	0.33			$	1.29
Weighted average shares outstanding, basic		70,739				69,772				68,985				63,538				57,501
Earnings (loss) per share, diluted		$	(1.17	)		$	0.75			$	0.55			$	0.32			$	1.24
Weighted average shares outstanding, diluted		70,739				70,714				69,373				64,852				63,917
Cash dividends per common share		$	0.60			$	0.55			$	0.53			$	0.38			$	0.16
BALANCE SHEET DATA:
Cash and cash equivalents		$	136,302			$	234,127			$	214,961			$	224,499			$	116,296
Working capital		40,647				78,694				126,665				60,863				87,242
Total assets		2,110,159				2,176,138				2,191,644				2,235,024				2,211,061
Total debt		527,966				555,962				554,457				602,132				574,504
Total debt less cash and cash equivalents		391,664				321,835				339,496				377,633				458,208
Total equity		582,413				664,160				673,778				625,404				621,186

_________________

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

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

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

Forward-Looking Statements

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

Forward-looking statements reflect our current expectations 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:

•	the possibility that the Mergers may not be consummated in a timely manner, or at all;

•	the diversion of management in connection with the Mergers and our ability to realize the anticipated benefits of the Mergers;

•	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;

•

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;

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•	the effects of seasonality on demand for our products;

•	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 own a majority interest in a renewable fuels facility in California, with a throughput capacity of 3,000 bpd. 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 306 convenience stores which also market motor fuels in Central and West Texas and New Mexico.

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. Our refining and marketing segment also includes our majority ownership interest in a renewable fuels facility in California, which has a throughput capacity of 3,000 bpd. We primarily 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 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 639 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.

We are the majority owner of a renewable fuels facility in California that began commercial production in February 2016 and converts tallow and vegetable oils into renewable fuels. The produced renewable fuels are drop-in replacements for petroleum-based fuels. The renewable fuels facility generates both state and federal environmental credits as well as the federal blender’s tax credit, when effective.

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.

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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. Through our asphalt facilities, we are marketing a number of different product formulations, including both polymer modified asphalt and ground tire rubber 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 by our Big Spring refinery is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude and Rocky Mountain asphalt, 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.”

2016 Operational and Financial Highlights

Our operational and financial highlights for 2016 include the following:

•	Operating loss for 2016 was $(67.4) million , compared to operating income of $203.4 million in 2015 .

•	Combined refinery average throughput for 2016 was 139,243 bpd, compared to a combined refinery average throughput of 140,036 bpd in 2015 .

The Big Spring refinery average throughput for 2016 was 71,363 bpd compared to 74,906 bpd for 2015 . The reduced throughput at our Big Spring refinery during 2016 was the result of a reformer regeneration during the first quarter of 2016 and third quarter of 2016. Additionally, throughput was reduced as a result of a catalyst replacement for our diesel hydrotreater unit in the first quarter of 2016 and unplanned downtime during the second quarter of 2016 due to a power outage caused by inclement weather, which affected multiple units.

The Krotz Springs refinery average throughput for 2016 was 67,880 bpd compared to 65,130 bpd for 2015 . During 2016, the Krotz Springs refinery throughput was impacted by our election to reduce the crude rate in order to optimize the refinery yield, as well as maintenance that was performed on the fluid catalytic cracking unit during the second quarter of 2016. During 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 $8.28 per barrel in 2016 , compared to $14.43 per barrel in 2015 . This decrease in operating margin was primarily due to a lower Gulf Coast 3/2/1 crack spread, a narrowing of the WTI Cushing to WTI Midland spread and increased RINs costs, partially offset by a widening of the WTI Cushing to WTS spread and an increased benefit from the contango market environment which reduced the cost of crude.

•

Refinery operating margin at the Krotz Springs refinery was $3.06 per barrel in 2016 compared to $7.02 per barrel for 2015 . This decrease in operating margin was primarily due to a lower Gulf Coast 2/1/1 high sulfur diesel crack spread, a narrowing of both the WTI Cushing to WTI Midland and the LLS to WTI Cushing spreads and increased RINs costs, partially offset by an increased benefit from the contango market environment which reduced the cost of crude.

•	The average Gulf Coast 3/2/1 crack spread was $12.64 per barrel for 2016 compared to $17.02 per barrel for 2015 . The average Gulf Coast 2/1/1 high sulfur diesel crack spread for 2016 was $7.95 per barrel compared to $10.81 per barrel for 2015 .

•

The average WTI Cushing to WTI Midland spread for 2016 was $0.15 per barrel compared to $0.39 per barrel for 2015 . The average WTI Cushing to WTS spread for 2016 was $0.73 per barrel compared to $(0.06) per barrel for 2015 . The average LLS to WTI Cushing spread for 2016 was $1.70 per barrel compared to $3.73 per barrel for 2015 . The average Brent to WTI Cushing spread for 2016 was $0.21 per barrel compared to $3.54 per barrel for 2015 . The average Brent to LLS spread for 2016 was $(1.45) per barrel compared to $0.14 per barrel for 2015 .

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•	The average RINs cost effect on the Big Spring refinery operating margin was $0.55 per barrel for 2016 , compared to $0.42 per barrel for 2015 . The average RINs cost effect on the Krotz Springs refinery operating margin was $1.48 per barrel for 2016 , compared to $0.99 per barrel for 2015 .

•	The contango environment in 2016 created an average cost of crude benefit of $1.24 per barrel compared to an average cost of crude benefit of $1.01 per barrel for 2015 .

•	We are the majority owner of a renewable fuels facility in California that began commercial production in February 2016. Through the facility, we generated an operating margin of $68.67 per barrel from an average of 2,275 barrels per day of throughput for 2016 . Our statements of operations include operating income of $24.1 million in 2016 related to the facility’s operations.

•	Asphalt margins in 2016 were $98.80 per ton compared to $105.70 per ton in 2015 .

•	Retail fuel margins decreased to 19.8 cents per gallon in 2016 from 21.3 cents per gallon in 2015 . Retail fuel sales volume increased to 209.0 million gallons in 2016 from 199.1 million gallons in 2015 . Merchandise margins decreased to 31.2% in 2016 from 31.9% in 2015 . Merchandise sales decreased to $324.4 million in 2016 from $328.5 million in 2015 .

•	During 2016, we paid cash dividends on our common stock totaling $0.60 per share, compared to $0.55 per share in 2015.

•	During 2016, the Partnership generated cash available for distribution of $0.40 per unit, compared to $2.81 per unit in 2015.

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 and inclusive of RINs costs). 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. Additionally, we have the ability to source locally produced crude at Big Spring by truck, which enables us to better control quality and eliminate the cost of transporting our crude supply from Midland. 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

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Cushing less WTI Midland spread will favorably influence the operating margin for both our Big Spring and Krotz Springs refineries. Alternatively, a narrowing of this differential will have an adverse effect on our operating margins.

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 discount in LLS relative to Brent 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.

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Factors Affecting Comparability

Our financial condition and operating results over the three-year period ended December 31, 2016 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, 2016, throughput at the Big Spring refinery was reduced as a result of a reformer regeneration during the first quarter of 2016 and third quarter of 2016. Additionally, throughput was reduced as a result of a catalyst replacement for our diesel hydrotreater unit in the first quarter of 2016 and unplanned downtime during the second quarter of 2016 due to a power outage caused by inclement weather, which affected multiple units. During 2016, the Krotz Springs refinery throughput was impacted by our election to reduce the crude rate in order to optimize the refinery yield, as well as maintenance that was performed on the fluid catalytic cracking unit during the second quarter of 2016.

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.

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.

California Renewable Fuels Facility

Our California renewable fuels facility began operations in February 2016. The facility converts approximately 3,000 barrels per day of tallow and other feedstocks into renewable fuels, which are replacements for petroleum-based fuels. Our California renewable fuels facility generates environmental credits in the form of renewable identification numbers, California low-carbon fuels standards credits as well as the blender’s tax credits, when effective, which are all recorded in net sales as part of our refining and marketing segment. For the year ended December 31, 2016, our statements of operations include operating income of $24.1 million related to the facility’s operations.

Certain Derivative Impacts

Included in cost of sales for the years ended December 31, 2016 , 2015 and 2014 are realized and unrealized gains on commodity swaps of $0.4 million , $59.2 million and $4.7 million, respectively.

Impairment of Goodwill

The volatility in the crude price environment during 2015 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. As a result, we have delayed planned projects within the California refining reporting unit, which had a negative effect on the timing of future cash flows. We recognized a goodwill impairment loss of $39.0 million related to our California refining reporting unit for the year ended December 31, 2015, which is included in our refining and marketing segment.

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.

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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. Also included in net sales are environmental credits in the form of RINs, California low-carbon fuel standards credits and blender’s tax credits generated at our California renewable fuels facility. 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.

Depreciation and amortization. Depreciation and amortization represents an allocation of the cost of capital assets to expense within the consolidated statements of operations. The cost is expensed based on the straight-line method over the estimated useful life of the related asset. Depreciation and amortization also includes deferred turnaround and catalyst replacement costs. Turnaround and catalyst replacement costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround.

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.

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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, 2016 , 2015 and 2014 . 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,
	2016				2015				2014
	(dollars in thousands, except per share data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	3,913,404			$	4,338,152			$	6,779,456
Operating costs and expenses:
Cost of sales	3,376,803				3,515,406				6,002,270
Direct operating expenses	262,706				255,534				281,686
Selling, general and administrative expenses (2)	194,078				200,195				170,139
Depreciation and amortization (3)	145,577				126,494				124,063
Total operating costs and expenses	3,979,164				4,097,629				6,578,158
Gain (loss) on disposition of assets	(1,650		)		1,914				274
Loss on impairment of goodwill (4)	—				(39,028		)		—
Operating income (loss)	(67,410		)		203,409				201,572
Interest expense	(69,717		)		(79,826		)		(111,143		)
Equity earnings of investees	9,813				6,669				1,678
Other income, net	692				417				674
Income (loss) before income tax expense (benefit)	(126,622		)		130,669				92,781
Income tax expense (benefit)	(46,789		)		48,282				22,913
Net income (loss)	(79,833		)		82,387				69,868
Net income attributable to non-controlling interest	2,972				29,636				31,411
Net income (loss) available to stockholders	$	(82,805	)		$	52,751			$	38,457
Earnings (loss) per share, basic	$	(1.17	)		$	0.76			$	0.56
Weighted average shares outstanding, basic (in thousands)	70,739				69,772				68,985
Earnings (loss) per share, diluted	$	(1.17	)		$	0.75			$	0.55
Weighted average shares outstanding, diluted (in thousands)	70,739				70,714				69,373
Cash dividends per share	$	0.60			$	0.55			$	0.53
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	59,516			$	226,065			$	193,658
Investing activities	(94,129		)		(160,011		)		(108,995		)
Financing activities	(63,212		)		(46,888		)		(94,201		)
OTHER DATA:
Adjusted EBITDA (5)	$	90,322			$	374,103			$	327,713
Capital expenditures (6)	58,644				101,195				88,429
Capital expenditures for turnarounds and catalysts	29,806				35,348				62,473

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	As of December 31,
	2016				2015
	(dollars in thousands)
BALANCE SHEET DATA (end of period):
Cash and cash equivalents	$	136,302			$	234,127
Working capital	40,647				78,694
Total assets	2,110,159				2,176,138
Total debt	527,966				555,962
Total debt less cash and cash equivalents	391,664				321,835
Total equity	582,413				664,160

(1)	Includes excise taxes on sales by the retail segment of $81,602 , $77,860 and $75,409 for the years ended December 31, 2016 , 2015 and 2014 , respectively.

(2)	Includes corporate headquarters selling, general and administrative expenses of $738 , $713 and $705 for the years ended December 31, 2016 , 2015 and 2014 , respectively, which are not allocated to our three operating segments.

(3)	Includes corporate depreciation and amortization of $2,710 , $1,552 and $2,399 for the years ended December 31, 2016 , 2015 and 2014 , 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)	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.

(6)	Includes corporate capital expenditures of $3,348 , $5,388 and $2,756 for the years ended December 31, 2016 , 2015 and 2014 , respectively, which are not allocated to our three operating segments.

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REFINING AND MARKETING SEGMENT
	Year Ended December 31,
	2016				2015				2014
	(dollars in thousands, except per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	3,240,170			$	3,663,956			$	5,937,982
Operating costs and expenses:
Cost of sales	2,905,470				3,034,531				5,329,605
Direct operating expenses	237,053				227,517				241,833
Selling, general and administrative expenses	68,210				79,022				56,004
Depreciation and amortization	124,304				107,619				104,676
Total operating costs and expenses	3,335,037				3,448,689				5,732,118
Gain (loss) on disposition of assets	(2,079		)		1,842				(1,255		)
Loss on impairment of goodwill (2)	—				(39,028		)		—
Operating income (loss)	$	(96,946	)		$	178,081			$	204,609
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin – Big Spring (3)	$	8.28			$	14.43			$	16.69
Refinery operating margin – Krotz Springs (3)	3.06				7.02				7.57
California renewable fuels operating margin (4)	68.67				N/A				N/A
Refinery direct operating expense – Big Spring (5)	3.73				3.62				4.39
Refinery direct operating expense – Krotz Springs (5)	3.78				4.03				4.12
California renewable fuels direct operating expense (5)	22.12				N/A				N/A
Capital expenditures	$	48,672			$	73,429			$	63,148
Capital expenditures for turnarounds and catalysts	29,806				35,348				62,473
PRICING STATISTICS:
Crack spreads (3/2/1) (per barrel):
Gulf Coast	$	12.64			$	17.02			$	14.52
Crack spreads (2/1/1) (per barrel):
Gulf Coast high sulfur diesel	$	7.95			$	10.81			$	9.76
WTI Cushing crude oil (per barrel)	$	43.24			$	48.68			$	93.10
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland	$	0.15			$	0.39			$	6.93
WTI Cushing less WTS	0.73				(0.06		)		6.04
LLS less WTI Cushing	1.70				3.73				3.85
Brent less WTI Cushing	0.21				3.54				6.19
Brent less LLS	(1.45		)		0.14				3.45
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	1.34			$	1.56			$	2.49
Gulf Coast ultra-low sulfur diesel	1.32				1.58				2.71
Gulf Coast high sulfur diesel	1.18				1.45				2.59
Natural gas (per MMBtu)	2.55				2.63				4.26

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THROUGHPUT AND PRODUCTION DATA: BIG SPRING REFINERY	Year Ended December 31,
	2016						2015						2014
	bpd			%			bpd			%			bpd			%
Refinery throughput:
WTS crude	31,000			43.4			33,647			44.9			30,323			45.9
WTI crude	36,862			51.7			38,632			51.6			32,429			49.1
Blendstocks	3,501			4.9			2,627			3.5			3,281			5.0
Total refinery throughput (6)	71,363			100.0			74,906			100.0			66,033			100.0
Refinery production:
Gasoline	35,220			49.4			37,519			50.0			32,932			49.7
Diesel/jet	25,739			36.1			27,651			36.8			23,252			35.1
Asphalt	2,767			3.9			2,639			3.5			2,716			4.1
Petrochemicals	3,872			5.4			4,579			6.1			3,756			5.7
Other	3,740			5.2			2,678			3.6			3,565			5.4
Total refinery production (7)	71,338			100.0			75,066			100.0			66,221			100.0
Refinery utilization (8)				96.1	%					99.0	%					97.2	%

THROUGHPUT AND PRODUCTION DATA: KROTZ SPRINGS REFINERY	Year Ended December 31,
	2016						2015						2014
	bpd			%			bpd			%			bpd			%
Refinery throughput:
WTI crude	19,990			29.4			22,408			34.4			28,373			40.3
Gulf Coast sweet crude	42,835			63.2			38,699			59.4			39,636			56.4
Blendstocks	5,055			7.4			4,023			6.2			2,336			3.3
Total refinery throughput (6)	67,880			100.0			65,130			100.0			70,345			100.0
Refinery production:
Gasoline	33,706			48.8			30,193			45.5			32,925			45.9
Diesel/jet	26,346			38.1			27,259			41.0			30,060			41.9
Heavy Oils	1,238			1.8			1,165			1.8			1,146			1.6
Other	7,801			11.3			7,781			11.7			7,579			10.6
Total refinery production (7)	69,091			100.0			66,398			100.0			71,710			100.0
Refinery utilization (8)				84.9	%					91.3	%					91.9	%

THROUGHPUT AND PRODUCTION DATA: CALIFORNIA RENEWABLE FUELS FACILITY	Year Ended December 31,
	2016						2015						2014
	bpd			%			bpd			%			bpd			%
Throughput:
Tallow/vegetable oils	2,275			100.0			—			—			—			—
Total throughput (6)	2,275			100.0			—			—			—			—
Production:
Renewable diesel	1,998			89.0			—			—			—			—
Renewable jet	149			6.6			—			—			—			—
Naphtha	99			4.4			—			—			—			—
Total production (7)	2,246			100.0			—			—			—			—

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(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 the refinery’s throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margins to these crack spreads to assess our operating performance relative to other participants in our industry.

The refinery operating margin for the years ended December 31, 2016, 2015 and 2014 excludes realized and unrealized gains on commodity swaps of $367 , $59,215 and $4,660, respectively. The refinery operating margin for the year ended December 31, 2015 also excludes insurance recoveries of $10,868.

The refinery operating margin for the Big Spring refinery and the Krotz Springs refinery excludes $3,941 related substantially to inventory adjustments for the year ended December 31, 2015.

(4)	The operating margin for our California renewable fuels facility is a per barrel measurement calculated by dividing the facility’s margin between net sales and cost of sales by the facility’s throughput volumes. Included in net sales are environmental credits in the form of RINs, California low-carbon fuel standards credits and blender’s tax credits generated by the facility.

(5)	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.

(6)	Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process. Total throughput for the California renewable fuels facility represents the total barrels per day of tallow and vegetable oils used by the facility for the period following March 1, 2016.

(7)

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. Total production for the California renewable fuels facility represents the barrels per day of various products produced from processing tallow and vegetable oils through the facility’s units for the period following March 1, 2016.

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

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ASPHALT SEGMENT
	Year Ended December 31,
	2016				2015				2014
	(dollars in thousands, except per ton data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	248,988			$	257,955			$	457,412
Operating costs and expenses:
Cost of sales (1) (2)	190,047				212,166				431,931
Direct operating expenses	25,653				28,017				39,853
Selling, general and administrative expenses	10,796				10,517				7,874
Depreciation and amortization	5,044				4,892				4,747
Total operating costs and expenses	231,540				255,592				484,405
Gain on disposition of assets	—				—				1,396
Operating income (loss) (5)	$	17,448			$	2,363			$	(25,597	)
KEY OPERATING STATISTICS:
Blended asphalt sales volume (tons in thousands) (3)	522				451				516
Non-blended asphalt sales volume (tons in thousands) (4)	85				59				65
Blended asphalt sales price per ton (3)	$	398.84			$	486.34			$	571.18
Non-blended asphalt sales price per ton (4)	146.36				231.00				397.91
Asphalt margin per ton (5)	98.80				105.70				43.86
Capital expenditures	$	3,001			$	3,385			$	5,777

(1)	Net sales and cost of sales include asphalt purchases sold as part of the supply and offtake arrangement of $28,354 , $24,988 and $136,818 for the years ended December 31, 2016 , 2015 and 2014 , 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 excludes losses of $1,032 and $8,118 for the years ended December 31, 2016 and 2015 , respectively, resulting from a price adjustment related to asphalt inventory. These losses are included in operating income (loss) of the asphalt segment.

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RETAIL SEGMENT
	Year Ended December 31,
	2016				2015				2014
	(dollars in thousands, except per gallon data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	731,743			$	774,435			$	939,684
Operating costs and expenses:
Cost of sales (2)	588,783				626,903				796,356
Selling, general and administrative expenses	114,334				109,943				105,556
Depreciation and amortization	13,519				12,431				12,241
Total operating costs and expenses	716,636				749,277				914,153
Gain on disposition of assets	429				72				134
Operating income	$	15,536			$	25,230			$	25,665
KEY OPERATING STATISTICS:
Number of stores (end of period) (3)	306				309				295
Retail fuel sales (thousands of gallons)	208,963				199,147				192,582
Retail fuel sales (thousands of gallons per site per month) (3)	59				58				57
Retail fuel margin (cents per gallon) (4)	19.8				21.3				21.6
Retail fuel sales price (dollars per gallon) (5)	$	1.95			$	2.24			$	3.20
Merchandise sales	$	324,434			$	328,505			$	322,262
Merchandise sales (per site per month) (3)	$	88			$	91			$	91
Merchandise margin (6)	31.2		%		31.9		%		31.4		%
Capital expenditures	$	5,630			$	18,993			$	16,748

(1)	Includes excise taxes on sales of $81,602 , $77,860 and $75,409 for the years ended December 31, 2016 , 2015 and 2014 , 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, 2016 , we had 306 retail convenience stores of which 296 sold fuel. 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.

The 14 retail convenience stores acquired in 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.

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Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

Net Sales

Consolidated . Net sales for the year ended December 31, 2016 were $3,913.4 million , compared to $4,338.2 million for the year ended December 31, 2015 , a decrease of $424.8 million , or 9.8% . This decrease was primarily due to lower refined product prices.

Refining and Marketing Segment . Net sales for our refining and marketing segment were $3,240.2 million for the year ended December 31, 2016 , compared to $3,664.0 million for the year ended December 31, 2015 , a decrease of $423.8 million , or 11.6% . This decrease was primarily due to lower refined product prices, partially offset by the operations of our California renewable fuels facility.

The average per gallon price of Gulf Coast gasoline for the year ended December 31, 2016 decreased $0.22 , or 14.1% , to $1.34 , compared to $1.56 for the year ended December 31, 2015 . The average per gallon price of Gulf Coast ultra-low sulfur diesel for the year ended December 31, 2016 decreased $0.26 , or 16.5% , to $1.32 , compared to $1.58 for the year ended December 31, 2015 . The average per gallon price for Gulf Coast high sulfur diesel for the year ended December 31, 2016 decreased $0.27 , or 18.6% , to $1.18 , compared to $1.45 for the year ended December 31, 2015 .

Asphalt Segment. Net sales for our asphalt segment were $249.0 million for the year ended December 31, 2016 , compared to $258.0 million for the year ended December 31, 2015 , a decrease of $9.0 million , or 3.5% . This decrease was primarily due to lower asphalt sales prices, partially offset by increased asphalt sales volumes. The average blended asphalt sales price decreased 18.0% to $398.84 per ton for the year ended December 31, 2016 from $486.34 per ton for the year ended December 31, 2015 . The average non-blended asphalt sales price decreased 36.6% to $146.36 per ton for the year ended December 31, 2016 from $231.00 per ton for the year ended December 31, 2015 . The asphalt sales volume increased 19.0% to 607 thousand tons for the year ended December 31, 2016 from 510 thousand tons for the year ended December 31, 2015 .

Retail Segment. Net sales for our retail segment were $731.7 million for the year ended December 31, 2016 , compared to $774.4 million for the year ended December 31, 2015 , a decrease of $42.7 million , or 5.5% . This decrease was primarily due to lower merchandise sales and lower retail fuel sales prices related to reduced drilling activity in the Permian Basin, partially offset by increased retail fuel sales volumes. Merchandise sales decreased 1.2% to $324.4 million for the year ended December 31, 2016 from $328.5 million for the year ended December 31, 2015 . The average retail fuel sales price decreased 12.9% to $1.95 per gallon for the year ended December 31, 2016 from $2.24 per gallon for the year ended December 31, 2015 . Retail fuel sales volumes increased 5.0% to 209.0 million gallons for the year ended December 31, 2016 from 199.1 million gallons for the year ended December 31, 2015 .

Cost of Sales

Consolidated . Cost of sales for the year ended December 31, 2016 were $3,376.8 million , compared to $3,515.4 million for the year ended December 31, 2015 , a decrease of $138.6 million , or 3.9% . This decrease was primarily due to lower crude oil prices.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $2,905.5 million for the year ended December 31, 2016 , compared to $3,034.5 million for the year ended December 31, 2015 , a decrease of $129.0 million , or 4.3% . This decrease was primarily due to lower crude oil prices, partially offset by the operations of our California renewable fuels facility. The average price of WTI Cushing decreased 11.2% to $43.24 per barrel for the year ended December 31, 2016 from $48.68 per barrel for the year ended December 31, 2015 .

Asphalt Segment . Cost of sales for our asphalt segment were $190.0 million for the year ended December 31, 2016 , compared to $212.2 million for the year ended December 31, 2015 , a decrease of $22.2 million , or 10.5% . This decrease was primarily due to lower cost of purchased asphalt, partially offset by higher asphalt sales volumes and reduced losses related to asphalt inventory price adjustments.

Retail Segment. Cost of sales for our retail segment were $588.8 million for the year ended December 31, 2016 , compared to $626.9 million for the year ended December 31, 2015 , a decrease of $38.1 million , or 6.1% . This decrease was primarily due to lower retail fuel costs, partially offset by increased retail fuel sales volumes.

Direct Operating Expenses

Consolidated . Direct operating expenses for the year ended December 31, 2016 were $262.7 million , compared to $255.5 million for the year ended December 31, 2015 , an increase of $7.2 million , or 2.8% . This increase was primarily due to the operations of our California renewable fuels facility.

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Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the year ended December 31, 2016 were $237.1 million , compared to $227.5 million for the year ended December 31, 2015 , an increase of $9.6 million , or 4.2% . This increase was primarily due to the operations of our California renewable fuels facility.

Asphalt Segment. Direct operating expenses for our asphalt segment for the year ended December 31, 2016 were $25.7 million , compared to $28.0 million for the year ended December 31, 2015 , a decrease of $2.3 million , or 8.2% . This decrease was primarily due to lower fixed operating costs, which was the result of realignment of our asphalt terminal activities to asphalt sales volumes.

Selling, General and Administrative Expenses

Consolidated . SG&A expenses for the year ended December 31, 2016 were $194.1 million , compared to $200.2 million for the year ended December 31, 2015 , a decrease of $6.1 million , or 3.0% .

Refining and Marketing Segment . SG&A expenses for our refining and marketing segment for the year ended December 31, 2016 were $68.2 million , compared to $79.0 million for the year ended December 31, 2015 , a decrease of $10.8 million , or 13.7% . This decrease was primarily due to reduced employee related costs.

Asphalt Segment . SG&A expenses for our asphalt segment for the year ended December 31, 2016 were $10.8 million , compared to $10.5 million for the year ended December 31, 2015 , an increase of $0.3 million , or 2.9% .

Retail Segment . SG&A expenses for our retail segment for the year ended December 31, 2016 were $114.3 million , compared to $109.9 million for the year ended December 31, 2015 , an increase of $4.4 million , or 4.0% .

Depreciation and Amortization

Depreciation and amortization for the year ended December 31, 2016 was $145.6 million , compared to $126.5 million for the year ended December 31, 2015 , an increase of $19.1 million , or 15.1% . This increase was primarily due to increased amortization of turnaround and catalyst replacement costs during the year ended December 31, 2016 resulting from the completion of the planned major turnaround at the Krotz Springs refinery during the fourth quarter of 2015 as well as the depreciation related to our California renewable fuels facility.

Operating Income (Loss)

Consolidated . Operating loss for the year ended December 31, 2016 was $(67.4) million , compared to operating income of $203.4 million for the year ended December 31, 2015 , a decrease of $270.8 million . This decrease was primarily due to lower refinery operating margins and the impacts of commodity swaps, partially offset by the operations of our California renewable fuels facility and the goodwill impairment charge of $39.0 million from 2015.

Refining and Marketing Segment. Operating loss for our refining and marketing segment was $(96.9) million for the year ended December 31, 2016 , compared to operating income of $178.1 million for the year ended December 31, 2015 , a decrease of $275.0 million . This decrease was primarily due to lower refinery operating margins and the impacts of commodity swaps, partially offset by the operations of our California renewable fuels facility and the goodwill impairment charge of $39.0 million from 2015. During the year ended December 31, 2016, we recorded gains on commodity swaps of $0.4 million , compared to $59.2 million for the year ended December 31, 2015 .

Refinery operating margin at the Big Spring refinery was $8.28 per barrel for the year ended December 31, 2016 , compared to $14.43 per barrel for the year ended December 31, 2015 . This decrease in operating margin was primarily due to a lower Gulf Coast 3/2/1 crack spread, a narrowing of the WTI Cushing to WTI Midland spread and increased RINs costs, partially offset by a widening of the WTI Cushing to WTS spread and an increased benefit from the contango market environment which reduced the cost of crude. The average Gulf Coast 3/2/1 crack spread decreased 25.7% to $12.64 per barrel for the year ended December 31, 2016 , compared to $17.02 per barrel for the year ended December 31, 2015 . The average WTI Cushing to WTI Midland spread for the year ended December 31, 2016 was $0.15 per barrel, compared to $0.39 per barrel for the year ended December 31, 2015 . The average WTI Cushing to WTS spread for the year ended December 31, 2016 was $0.73 per barrel, compared to $(0.06) per barrel for the year ended December 31, 2015 . The average Brent to WTI Cushing spread for the year ended December 31, 2016 was $0.21 per barrel, compared to $3.54 per barrel for the year ended December 31, 2015 . The contango environment for the year ended December 31, 2016 created an average cost of crude benefit of $1.24 per barrel compared to an average cost of crude benefit of $1.01 per barrel for the year ended December 31, 2015 . The average RINs cost effect on the Big Spring refinery operating margin was $0.55 per barrel for the year ended December 31, 2016 , compared to $0.42 per barrel for the year ended December 31, 2015 .

Refinery operating margin at the Krotz Springs refinery was $3.06 per barrel for the year ended December 31, 2016 , compared to $7.02 per barrel for the year ended December 31, 2015 . This decrease in operating margin was primarily due to a lower Gulf Coast 2/1/1 high sulfur diesel crack spread, a narrowing of both the WTI Cushing to WTI Midland and the LLS to

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WTI Cushing spreads and increased RINs costs, partially offset by an increased benefit from the contango market environment which reduced the cost of crude. The average Gulf Coast 2/1/1 high sulfur diesel crack spread decreased 26.5% to $7.95 per barrel for the year ended December 31, 2016 , compared to $10.81 per barrel for the year ended December 31, 2015 . The average LLS to WTI Cushing spread for the year ended December 31, 2016 was $1.70 per barrel, compared to $3.73 per barrel for the year ended December 31, 2015 . The average Brent to LLS spread for the year ended December 31, 2016 was $(1.45) per barrel, compared to $0.14 per barrel for the year ended December 31, 2015 . The average RINs cost effect on the Krotz Springs refinery operating margin was $1.48 per barrel for the year ended December 31, 2016 , compared to $0.99 per barrel for the year ended December 31, 2015 .

Asphalt Segment. Operating income for our asphalt segment was $17.4 million for the year ended December 31, 2016 , compared to $2.4 million for the year ended December 31, 2015 , an increase of $15.0 million . This increase was primarily due to reduced asphalt inventory price adjustments, higher asphalt sales volumes and lower direct operating expenses, partially offset by lower asphalt margins. During the year ended December 31, 2016, we recorded a loss of $(1.0) million resulting from a price adjustment related to asphalt inventory, compared to a loss of $(8.1) million for the year ended December 31, 2015. Asphalt margins for the year ended December 31, 2016 were $98.80 per ton, compared to $105.70 per ton for the year ended December 31, 2015 .

Retail Segment. Operating income for our retail segment was $15.5 million for the year ended December 31, 2016 , compared to $25.2 million for the year ended December 31, 2015 , a decrease of $9.7 million , or 38.5% . This decrease was primarily due to lower retail fuel margins, lower merchandise sales, lower merchandise margins and increased SG&A expenses primarily related the addition of 14 stores during 2015. Retail fuel margins were 19.8 cents per gallon for the year ended December 31, 2016 , compared to 21.3 cents per gallon for the year ended December 31, 2015 . Merchandise margins were 31.2% for the year ended December 31, 2016 , compared to 31.9% for the year ended December 31, 2015 .

Interest Expense

Interest expense was $69.7 million for the year ended December 31, 2016 , compared to $79.8 million for the year ended December 31, 2015 , a decrease of $10.1 million , or 12.7% . This decrease was primarily due to the effect of crude oil prices moving further into contango on our supply and offtake agreements.

Income Tax Expense (Benefit)

Income tax benefit was $(46.8) million for the year ended December 31, 2016 , compared to income tax expense of $48.3 million for the year ended December 31, 2015 . This change in income taxes resulted from the change in pre-tax income to pre-tax loss. Our effective tax rate was 37.0% for the year ended December 31, 2016 , compared to an effective tax rate of 36.9% for the year ended December 31, 2015 .

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 as well as the proportional share of income from our California renewable fuels facility attributable to the non-affiliate owners. Net income attributable to non-controlling interest was $3.0 million for the year ended December 31, 2016 , compared to $29.6 million for the year ended December 31, 2015 , a decrease of $26.6 million , or 89.9% .

Net Income (Loss) Available to Stockholders

Net loss available to stockholders was $(82.8) million for the year ended December 31, 2016 , compared to net income available to stockholders of $52.8 million for the year ended December 31, 2015 , a decrease of $135.6 million . This decrease was attributable to the factors discussed above.

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 .

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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. 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.

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. 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.

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.

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.

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 asphalt sales volumes.

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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.

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.

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.

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.

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.

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. 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 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 an average cost of crude benefit of $1.01 per barrel compared to the backwardated environment creating an average 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.

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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. 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. 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% . 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% .

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.

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.

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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, 2016 , our total cash and cash equivalents were $136.3 million and we had total debt of $528.0 million .

Cash Flows

The following table sets forth our consolidated cash flows for the years ended December 31, 2016 , 2015 and 2014 :

	Year Ended December 31,
	2016				2015				2014
	(dollars in thousands)
Cash provided by (used in):
Operating activities	$	59,516			$	226,065			$	193,658
Investing activities	(94,129		)		(160,011		)		(108,995		)
Financing activities	(63,212		)		(46,888		)		(94,201		)
Net increase (decrease) in cash and cash equivalents	$	(97,825	)		$	19,166			$	(9,538	)

Cash Flows Provided by Operating Activities

Net cash provided by operating activities for the year ended December 31, 2016 was $59.5 million , compared to $226.1 million for the year ended December 31, 2015 . The decrease in cash provided by operating activities of $166.6 million was primarily due to reduced net income (loss) after adjusting for non-cash items of $168.8 million , increased cash used for inventories of $42.2 million , increased cash used for other non-current liabilities of $0.8 million , increased cash used for prepaid expenses and other current assets of $6.2 million and reduced cash collected on accounts receivable of $66.6 million . These changes were partially offset by reduced cash used for accounts payable and accrued liabilities of $88.0 million and reduced cash used for other non-current assets of $30.0 million .

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 .

Cash Flows Used In Investing Activities

Net cash used in investing activities was $94.1 million for the year ended December 31, 2016 , compared to $160.0 million for the year ended December 31, 2015 . The decrease in cash used in investing activities of $65.9 million was primarily due to a decrease in capital expenditures and capital expenditures for turnarounds and catalysts of $48.1 million , which is related to the completion of planned major turnaround at our Krotz Springs refinery during 2015, as well as reduced contributions to our equity method investments of $15.2 million and reduced cash used for acquisitions of $3.6 million , partially offset by reduced cash proceeds from the disposition of assets of $1.0 million .

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.

Cash Flows Used In Financing Activities

Net cash used in financing activities was $63.2 million for the year ended December 31, 2016 , compared to $46.9 million for the year ended December 31, 2015 . The increase in cash used in financing activities of $16.3 million was primarily due to increased net payments on debt related transactions of $29.8 million and reduced cash provided on our RINs financing transactions of $18.9 million , partially offset by reduced payments to shareholders and non-controlling interests of $31.1 million and reduced cash used for debt issuance costs of $1.3 million .

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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 RINs financing transactions of $15.9 million , partially offset by increased payments to shareholders and non-controlling interests of $17.4 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, 2016 , the adjusted conversion rate was 73.171 shares of our common stock per each $1 (in thousands) principal amount of Convertible Notes, equivalent to a per share conversion price of approximately $13.67 , to reflect cash dividend adjustments. As of December 31, 2016 , 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, 2016 , the if-converted value of the Convertible Notes did not exceed the outstanding principal balance.

Convertible Note Hedge Transactions

In connection with the Convertible Notes offering, we also entered into convertible note hedge transactions with respect to our common stock (the “Purchased Options”) with the initial purchasers of the Convertible Notes (the “Hedge Counterparties”). We paid an aggregate amount of $28.5 million to the Hedge Counterparties for the Purchased Options. The Purchased Options allow us to purchase up to 10,975,665 shares of our common stock, subject to customary anti-dilution adjustments, that underlie the Convertible Notes sold in the offering. As of December 31, 2016, the Purchased Options had an adjusted strike price of $13.67 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 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.

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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 10,975,665 shares of our common stock, subject to customary anti-dilution adjustments. As of December 31, 2016 , the Warrants had an adjusted strike price of $18.57 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.

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, 2016 and 2015 , we had outstanding letters of credit under this facility of $57.7 million and $60.6 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 4,033,333 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, 2016 and 2015 , the Alon Energy Term Loan had an outstanding balance, net of unamortized issuance costs, of $11.6 million and $16.7 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 incur at an annual rate equal LIBOR plus 2.50% . At December 31, 2016 and 2015, the 2015 Term Loan had an outstanding balance, net of unamortized issuance costs, of $2.1 million and $2.7 million , respectively.

2016 Term Loan . In December 2016, we entered into a $35.0 million secured term loan (“2016 Term Loan”). The 2016 Term Loan requires quarterly principal repayments, commencing December 2018 until maturity in December 2020. The 2016 Term Loan bears interest at a rate equal to LIBOR plus a margin of 3.75% per annum. The 2016 Term Loan is secured by a lien on certain of our asphalt terminals. The 2016 Term Loan contains certain restrictive covenants, including maintenance financial covenants. At December 31, 2016, the 2016 Term Loan had an outstanding balance, net of unamortized issuance costs, of $34.2 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, 2016 , the interest rate was 9.25% per annum.

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, 2016 and 2015 , the Partnership Term Loan had an outstanding balance, net of unamortized issuance costs and issuance discount, of $236.3 million and $237.1 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.

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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.

At December 31, 2016 , there were no outstanding borrowings under our Revolving Credit Facility, compared to borrowings of $55.0 million at December 31, 2015 . At December 31, 2016 and 2015 , we had letters of credit outstanding of $100.6 million and $48.6 million , respectively, under the Alon USA, LP Credit Facility.

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 in 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 convenience retail stores in New Mexico.

Borrowings under the Alon Retail Credit Agreement bear interest at the 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, 2016 , the applicable margin was 2.50% 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, 2016 and 2015 , the Alon Retail Credit Agreement had $96.9 million and $104.5 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 agreements with maintenance financial covenants. At December 31, 2016 , 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 2017 is $79.7 million . This amount does not include expenditures related to the Krotz Springs refinery’s alkylation unit project.

The following table summarizes our expected capital expenditures for 2017 by operating segment (dollars in thousands):

	Refining and Marketing				Asphalt				Retail				Corporate				Consolidated Total
Sustaining maintenance and turnarounds and catalysts	$	39,570			$	5,675			$	5,665			$	2,406			$	53,316
Growth/profit improvement	9,330				—				250				—				9,580
Regulatory projects	16,819				—				—				—				16,819
Total	$	65,719			$	5,675			$	5,915			$	2,406			$	79,715

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.

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Contractual Obligations

Information regarding our known contractual obligations of the types described below as of December 31, 2016 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		$	16,414			$	514,608			$	15,961			$	—			$	546,983
Operating lease obligations		35,134				44,360				17,388				31,652				128,534
Pipelines and terminals agreements (1)		43,425				59,597				33,869				8,930				145,821
Other commitments (2)		3,741				7,482				4,676				—				15,899
Total obligations		$	98,714			$	626,047			$	71,894			$	40,582			$	837,237

_____________________

(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, 2016 , 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.

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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, 2016 and net periodic pension expense for the year ending December 31, 2017 (in thousands):

		0.25-Percentage Point Change
Expected rate of return:
Effect on net periodic pension expense		$	227
Discount rate:
Effect on net periodic pension expense		606
Effect on projected benefit obligation		5,090

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, 2016 , for those payments we considered fixed or reliably determinable, payments were discounted at a 2.62% 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.

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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.

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.

Goodwill is evaluated for impairment at a reporting unit level. At December 31, 2016 , we had two reporting units with goodwill: California asphalt and Retail operations. Goodwill and indefinite-lived intangible assets are measured for impairment by initially performing either a qualitative evaluation or a two-step quantitative test. Under the qualitative approach, we analyze the following factors to determine if events and circumstances have affected the fair value of goodwill and indefinite-lived intangible assets: (1) macroeconomic conditions, (2) industry and market considerations, (3) overall financial performance and cost factors, (4) our business plan for future periods and (5) estimated results of future operations.

If we determine that it is more likely than not that the asset value may be impaired, we use the quantitative approach to assess the asset’s fair value and the amount of the impairment. Under the quantitative approach, we calculate the fair value of the asset using the following assumptions: (1) our projected revenues, expenses and cash flows, (2) an estimated weighted average cost of capital, (3) assumed discount rates depending on the asset (4) a tax rate and (5) market prices for comparable assets. These assumptions are consistent with those which hypothetical market participants would use. If the asset’s carrying value exceeds its fair value calculated using the quantitative approach, we will record an impairment charge for the difference in fair value and carrying value.

Based on our annual testing, there were no impairments of our goodwill and indefinite-lived assets in 2016.

It is possible that in future periods our goodwill or our indefinite-lived assets could be impaired. Depending on the severity of the changes in the key factors underlying our valuations, such losses could be significant.

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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 (loss) available to stockholders to Adjusted EBITDA for the years ended December 31, 2016 , 2015 and 2014 :

	Year Ended December 31,
	2016				2015				2014
	(dollars in thousands)
Net income (loss) available to stockholders	$	(82,805	)		$	52,751			$	38,457
Net income attributable to non-controlling interest	2,972				29,636				31,411
Income tax expense (benefit)	(46,789		)		48,282				22,913
Interest expense	69,717				79,826				111,143
Depreciation and amortization	145,577				126,494				124,063
Loss on impairment of goodwill	—				39,028				—
(Gain) loss on disposition of assets	1,650				(1,914		)		(274		)
Adjusted EBITDA	$	90,322			$	374,103			$	327,713

Adjusted EBITDA does not exclude unrealized (gains) losses on commodity swaps of $14,799 , $(7,937) and $(3,778) for the years ended December 31, 2016, 2015 and 2014, respectively, which are included in net income (loss) available to stockholders. Additionally, Adjusted EBITDA does not exclude losses of $1,032 and $8,118 for the years ended December 31, 2016 and 2015 , respectively, resulting from a price adjustment related to asphalt inventory.

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

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

Commodity Price Risk

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

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

We maintain inventories of crude oil, refined products, asphalt and blendstocks, the values of which are subject to wide fluctuations in market prices driven by world economic conditions, regional and global inventory levels and seasonal conditions. At December 31, 2016 , the market value of our refined products, asphalt and blendstock inventories exceeded LIFO costs by $4.4 million . At December 31, 2016 , the market value of our crude oil inventories exceeded LIFO costs, net of the fair value hedged items, by $13.2 million .

As of December 31, 2016 , 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, the market value of product inventories would have exceeded LIFO costs by $3.8 million. If the market value of crude oil would have been $1.00 per barrel lower, the market value of crude oil inventories would have exceeded LIFO costs, net of the fair value hedged item, by $12.3 million.

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.

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The following table provides information about our derivative commodity instruments as of December 31, 2016 :

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)		257,609			$	52.04			$	—			$	13,405			$	13,805			$	400
Forwards-short (Crude)		(789,558	)		—				57.99				(45,787		)		(47,372		)		(1,585		)
Forwards-long (Gasoline)		26,205			64.97				—				1,702				1,806				104
Forwards-short (Gasoline)		(368,727	)		—				65.49				(24,146		)		(24,637		)		(491		)
Forwards-long (Distillate)		29,399			67.54				—				1,986				2,035				49
Forwards-short (Distillate)		(390,173	)		—				69.89				(27,269		)		(29,297		)		(2,028		)
Forwards-long (Jet)		80,382			62.93				—				5,058				5,364				306
Forwards-short (Jet)		(124,948	)		—				65.62				(8,199		)		(8,447		)		(248		)
Forwards-long (Slurry)		13,233			39.47				—				522				554				32
Forwards-long (Catfeed)		43,550			61.57				—				2,682				2,870				188
Forwards-short (Catfeed)		(191,508	)		—				61.57				(11,792		)		(12,620		)		(828		)
Forwards-long (Slop)		28,931			42.17				—				1,220				1,292				72
Forwards-short (Slop)		(20,291	)		—				44.26				(898		)		(949		)		(51		)
Forwards-short (Propane)		(55,000	)		—				25.72				(1,415		)		(1,630		)		(215		)
Forwards-long (Butane)		52,595			41.90				—				2,204				2,549				345
Forwards-long (Asphalt)		22,092			64.43				—				1,423				1,478				55
Forwards-short (Asphalt)		(192,332	)		—				52.17				(10,033		)		(10,513		)		(480		)
Futures-long (Crude)		761,000			52.66				—				40,077				40,881				804
Futures-short (Crude)		(21,000	)		—				52.83				(1,109		)		(1,128		)		(19		)
Futures-long (Gasoline)		402,000			66.95				—				26,914				28,212				1,298
Futures-short (Gasoline)		(55,000	)		—				66.49				(3,657		)		(3,860		)		(203		)
Futures-long (Distillate)		447,000			70.62				—				31,567				32,445				878
Futures-short (Distillate)		(5,000	)		—				83.72				(419		)		(363		)		56

Interest Rate Risk

As of December 31, 2016 , $396.8 million , excluding discounts and issuance costs, of our outstanding debt was subject to floating interest rates, of which $240.0 million was charged interest at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00%.

As of December 31, 2016 , we had interest rate swap contracts, maturing March 2019, that effectively fix the variable interest component on approximately $74.3 million of the outstanding principal of the term loans within the 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 $1.9 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.

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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 the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-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 were effective as of December 31, 2016 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 provide reasonable assurance 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 and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

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, 2016 .

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, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

None.

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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 2017 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”) or in an amendment to this Form 10-K 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 or in an amendment to this Form 10-K 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 or in an amendment to this Form 10-K 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 or in an amendment to this Form 10-K 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 or in an amendment to this Form 10-K 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 or in an amendment to this Form 10-K 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 or in an amendment to this Form 10-K 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 or in an amendment to this Form 10-K 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 or in an amendment to this Form 10-K is incorporated herein by reference.

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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
2.1		Agreement and Plan of Merger, dated as of January 2, 2017, by and among Alon USA Energy, Inc., Delek US Holdings, Inc., Dione Mergeco, Inc., Astro Mergeco, Inc., and Delek Holdco, Inc. (incorporated by reference to Exhibit 2.1 to Form 8-K filed by the Company on January 3, 2017, SEC File No. 001-32567).
2.2		First Amendment to Agreement and Plan of Merger, dated as of February 27, 2017, by and among Alon USA Energy, Inc., Delek US Holdings, Inc., Dione Mergeco, Inc., Astro Mergeco, Inc., and Delek Holdco, Inc.
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		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).

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Exhibit No.		Description of Exhibit
10.9		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).
10.10*		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).
10.11*		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).
10.12*		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).
10.13*		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).
10.14*		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).
10.15*		Second Amendment to Executive Employment Agreement, dated as of July 23, 2015, between Shai Even and Alon USA GP, LLC (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on July 30, 2015, SEC File No. 001-32567).
10.16*		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).
10.17*		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).
10.18*		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).
10.19*		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).
10.20*		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).
10.21*		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).
10.22*		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).
10.23*		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).
10.24*		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).
10.25*		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).
10.26*		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).
10.27*		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).
10.28*		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).
10.29*		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).

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Exhibit No.		Description of Exhibit
10.30†		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).
10.31*		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).
10.32*		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).
10.33*		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).
10.34*		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).
10.35*		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).
10.36*		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).
10.37*		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).
10.38*		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).
10.39*		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).
10.40*		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).
10.41*		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).
10.42*		Alon USA Energy, Inc. Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 12, 2017).
10.43*		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).
10.44*		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).
10.45*		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).
10.46		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).
10.47		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).
10.48		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).

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Exhibit No.		Description of Exhibit
10.49		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).
10.50		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).
10.51		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).
10.52†		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).
10.53		Amendment to Second Amended and Restated Supply and Offtake Agreement, dated as of January 13, 2017, between Alon Refining Krotz Springs, Inc. and J. Aron & Company.
10.54†		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).
10.55†		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).
10.56		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).
10.57		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).
10.58		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).
10.59		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).
10.60		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).
10.61		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).
10.62		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).
10.63		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).
10.64		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).
10.65		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).
10.66		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).
10.67		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).

65

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Exhibit No.		Description of Exhibit
10.68		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).
10.69		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).
10.70		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).
10.71		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).
10.72		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).
10.73		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, 2016, 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.

66

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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, 2016 and 2015		F-4
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014		F-5
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2016, 2015, and 2014		F-6
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014		F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014		F-8
Notes to Consolidated Financial Statements		F-9

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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, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2016, 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, 2016, 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 27, 2017 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas

February 27, 2017

F-2

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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, 2016, 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, 2016, 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, 2016 and 2015, 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, 2016, and our report dated February 27, 2017 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Dallas, Texas

February 27, 2017

F-3

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ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands, except per share data)

	As of December 31,
	2016				2015
ASSETS
Current assets:
Cash and cash equivalents	$	136,302			$	234,127
Accounts and other receivables, net	134,744				119,171
Income tax receivable	32,984				3,741
Inventories	130,502				105,515
Deferred income tax asset	14,858				13,786
Prepaid expenses and other current assets	36,761				28,275
Total current assets	486,151				504,615
Equity method investments	33,431				42,811
Property, plant and equipment, net	1,366,895				1,380,202
Goodwill	62,885				62,885
Other assets, net	160,797				185,625
Total assets	$	2,110,159			$	2,176,138
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	328,561			$	315,721
Accrued liabilities	100,529				93,780
Current portion of long-term debt	16,414				16,420
Total current liabilities	445,504				425,921
Other non-current liabilities	188,833				165,935
Long-term debt	511,552				539,542
Deferred income tax liability	381,857				380,580
Total liabilities	1,527,746				1,511,978
Commitments and contingencies (Note 22)
Stockholders’ equity:
Preferred stock, par value $0.01, 15,000,000 shares authorized; and no shares issued and outstanding at December 31, 2016 and 2015	—				—
Common stock, par value $0.01, 150,000,000 shares authorized; 71,578,093 and 70,960,461 shares issued and outstanding at December 31, 2016 and 2015, respectively	716				710
Additional paid-in capital	530,625				526,035
Accumulated other comprehensive loss, net of tax	(26,111		)		(28,808		)
Retained earnings	15,878				141,201
Total stockholders’ equity	521,108				639,138
Non-controlling interest in subsidiaries	61,305				25,022
Total equity	582,413				664,160
Total liabilities and equity	$	2,110,159			$	2,176,138

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ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands, except per share data)

	Year Ended December 31,
	2016				2015				2014
Net sales (1)	$	3,913,404			$	4,338,152			$	6,779,456
Operating costs and expenses:
Cost of sales	3,376,803				3,515,406				6,002,270
Direct operating expenses	262,706				255,534				281,686
Selling, general and administrative expenses	194,078				200,195				170,139
Depreciation and amortization	145,577				126,494				124,063
Total operating costs and expenses	3,979,164				4,097,629				6,578,158
Gain (loss) on disposition of assets	(1,650		)		1,914				274
Loss on impairment of goodwill	—				(39,028		)		—
Operating income (loss)	(67,410		)		203,409				201,572
Interest expense	(69,717		)		(79,826		)		(111,143		)
Equity earnings of investees	9,813				6,669				1,678
Other income, net	692				417				674
Income (loss) before income tax expense (benefit)	(126,622		)		130,669				92,781
Income tax expense (benefit)	(46,789		)		48,282				22,913
Net income (loss)	(79,833		)		82,387				69,868
Net income attributable to non-controlling interest	2,972				29,636				31,411
Net income (loss) available to stockholders	$	(82,805	)		$	52,751			$	38,457
Earnings (loss) per share, basic	$	(1.17	)		$	0.76			$	0.56
Weighted average shares outstanding, basic (in thousands)	70,739				69,772				68,985
Earnings (loss) per share, diluted	$	(1.17	)		$	0.75			$	0.55
Weighted average shares outstanding, diluted (in thousands)	70,739				70,714				69,373
Cash dividends per share	$	0.60			$	0.55			$	0.53

_________________

(1)	Includes excise taxes on sales by the retail segment of $81,602 , $77,860 and $75,409 for the years ended December 31, 2016 , 2015 and 2014 , respectively.

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ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

	Year Ended December 31,
	2016				2015				2014
Net income (loss)	$	(79,833	)		$	82,387			$	69,868
Other comprehensive income (loss):
Postretirement benefit plans:
Unrealized gain (loss) arising during the year related to:
Net actuarial gain (loss)	(3,931		)		357				(16,498		)
Curtailment	5,199				—				—
(Gain) loss reclassified to earnings:
Amortization of net actuarial loss (1)	3,878				4,226				3,466
Amortization of prior service credit (1)	(719		)		(364		)		(364		)
Net gain (loss), before tax	4,427				4,219				(13,396		)
Income tax expense (benefit)	1,616				1,540				(4,559		)
Net gain (loss), net of tax	2,811				2,679				(8,837		)
Interest rate derivatives designated as cash flow hedges:
Unrealized holding loss arising during period	(533		)		(1,276		)		(1,292		)
Loss reclassified to earnings - interest expense	753				338				54
Net gain (loss), before tax	220				(938		)		(1,238		)
Income tax expense (benefit)	80				(343		)		(458		)
Net gain (loss), net of tax	140				(595		)		(780		)
Commodity contracts designated as cash flow hedges:
Unrealized holding gain arising during period	—				6,070				50,288
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
Income tax expense (benefit)	—				(13,276		)		24,358
Net gain (loss), net of tax	—				(22,602		)		41,502
Total other comprehensive income (loss), net of tax	2,951				(20,518		)		31,885
Comprehensive income (loss)	(76,882		)		61,869				101,753
Comprehensive income attributable to non-controlling interest	3,226				29,468				34,239
Comprehensive income (loss) attributable to stockholders	$	(80,108	)		$	32,401			$	67,514

_________________

(1)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost, as further discussed in Note 15 . Net periodic benefit cost is reflected in direct operating expenses and selling, general and administrative expenses in the consolidated statements of operations.

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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, 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
Stock compensation expense	—				6				4,590				—				—				4,596				(54		)		4,542
Dividends	—				—				—				—				(42,518		)		(42,518		)		(401		)		(42,919		)
Acquisition of California renewable fuels facility	—				—				—				—				—				—				37,774				37,774
Distributions to non-controlling interest in the Partnership	—				—				—				—				—				—				(4,262		)		(4,262		)
Net income (loss)	—				—				—				—				(82,805		)		(82,805		)		2,972				(79,833		)
Other comprehensive income, net of tax	—				—				—				2,697				—				2,697				254				2,951
Balance at December 31, 2016	$	—			$	716			$	530,625			$	(26,111	)		$	15,878			$	521,108			$	61,305			$	582,413

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ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands)
	Year Ended December 31,
	2016				2015				2014
Cash flows from operating activities:
Net income (loss)	$	(79,833	)		$	82,387			$	69,868
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization	145,577				126,494				124,063
Stock compensation	7,352				9,953				7,496
Deferred income taxes	(2,650		)		5,906				5,961
Equity earnings of investees, net of dividends	(4,021		)		(2,274		)		—
Amortization of debt issuance costs	3,052				3,595				3,759
Amortization of original issuance discount	6,831				6,273				6,306
Write-off of unamortized debt issuance costs	—				—				558
Write-off of unamortized original issuance discount	—				—				391
(Gain) loss on disposition of assets	1,650				(1,914		)		(274		)
Loss on impairment of goodwill	—				39,028				—
Unrealized (gain) loss on commodity swaps	14,799				(7,937		)		(3,778		)
Changes in operating assets and liabilities:
Accounts and other receivables, net	(13,553		)		18,369				77,658
Income tax receivable	(29,243		)		5,455				6,857
Inventories	(24,925		)		17,288				4,983
Prepaid expenses and other current assets	(8,176		)		(1,960		)		(7,686		)
Other assets, net	18,261				(11,782		)		(27,506		)
Accounts payable	35,130				(37,179		)		(68,482		)
Accrued liabilities	1,548				(14,170		)		3,733
Other non-current liabilities	(12,283		)		(11,467		)		(10,249		)
Net cash provided by operating activities	59,516				226,065				193,658
Cash flows from investing activities:
Capital expenditures	(58,644		)		(101,195		)		(88,429		)
Capital expenditures for turnarounds and catalysts	(29,806		)		(35,348		)		(62,473		)
Dividends from investees, net of equity earnings	—				—				1,472
Contribution to equity method investment	—				(15,161		)		(597		)
Proceeds from disposition of assets	1,917				2,889				41,032
Acquisition of California renewable fuels facility	(7,596		)		—				—
Acquisition of retail stores	—				(11,196		)		—
Net cash used in investing activities	(94,129		)		(160,011		)		(108,995		)
Cash flows from financing activities:
Dividends paid to stockholders	(42,518		)		(38,387		)		(36,483		)
Dividends paid to non-controlling interest	(401		)		(415		)		(1,134		)
Distributions paid to non-controlling interest in the Partnership	(4,262		)		(39,475		)		(23,242		)
RINs financing transactions	21,199				40,138				24,200
Deferred debt issuance costs	(810		)		(2,139		)		(2,284		)
Revolving credit facilities, net	(55,000		)		(5,000		)		(40,000		)
Additions to long-term debt	35,000				14,049				145,000
Payments on long-term debt	(16,420		)		(15,659		)		(160,258		)
Net cash used in financing activities	(63,212		)		(46,888		)		(94,201		)
Net increase (decrease) in cash and cash equivalents	(97,825		)		19,166				(9,538		)
Cash and cash equivalents, beginning of period	234,127				214,961				224,499
Cash and cash equivalents, end of period	$	136,302			$	234,127			$	214,961
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$	61,584			$	70,556			$	106,065
Cash paid (refunds received) for income tax	$	(14,298	)		$	35,976			$	10,957
Supplemental disclosure of non-cash activity:
Capital expenditures included in accounts payable and accrued liabilities	$	—			$	21,011			$	—

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(1)	Description and Nature of Business

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(2)	Basis of Presentation and Certain Significant Accounting Policies

(a)	Basis of Presentation

(b)	Use of Estimates

(c)	Revenue Recognition

(d)	Cost Classifications

---

(e)	Cash and Cash Equivalents

(f)	Accounts Receivable

(g)	Inventories

(h)	Hedging Activity

(i)	Property, Plant and Equipment

---

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

(k)	Asset Retirement Obligations

(l)	Turnarounds and Catalysts Costs

(m)	Income Taxes

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(n)	Stock-Based Compensation

(o)	Environmental Expenditures

(p)	Earnings (Loss) Per Share

(q)	Other Comprehensive Income

(r)	Postretirement Benefits

(s)	Commitments and Contingencies

(t)	Goodwill and Intangible Assets

---

(u)	New Accounting Pronouncements

(3)	California Renewable Fuels Facility

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Current assets		$	19,060
Other assets		10,704
Property, plant and equipment		51,619
Current liabilities		(20,401		)
Fair value of net assets assumed		60,982
Non-controlling interest		(37,774		)
Fair value of net assets assumed, less non-controlling interest		$	23,208

(4)	Alon USA Partners, LP

	Cash Available for Distribution Per Unit (1)				Distributions Paid Per Unit				Total Distributions Paid				Distributions Paid to Non-Controlling Interest
2016	$	0.40			$	0.37			$	23,132			$	4,262
2015	2.81				3.43				214,405				39,475
2014	2.54				2.02				126,262				23,242

_______________________

(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.

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(5)	Segment Data

	Refining and Marketing				Asphalt				Retail				Corporate				Consolidated Total
Year ended December 31, 2016
Net sales to external customers	$	2,932,673			$	248,988			$	731,743			$	—			$	3,913,404
Intersegment sales (purchases)	307,497				(16,772		)		(290,725		)		—				—
Depreciation and amortization	124,304				5,044				13,519				2,710				145,577
Operating income (loss)	(96,946		)		17,448				15,536				(3,448		)		(67,410		)
Turnarounds, catalysts and capital expenditures	78,478				3,001				5,630				3,348				90,457

	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
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
Turnarounds, catalysts and capital expenditures	125,621				5,777				16,748				2,756				150,902

	December 31, 2016				December 31, 2015
Refining and marketing	1,739,840				1,822,924
Asphalt	111,941				106,015
Retail	241,272				231,078
Corporate	17,106				16,121
Total assets	$	2,110,159			$	2,176,138

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(6)	Fair Value

•	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.

	Level 1				Level 2				Level 3				Total
As of December 31, 2016
Assets:
Fair value hedges of consigned inventory	$	—			$	14,777			$	—			$	14,777
Liabilities:
Commodity contracts (futures and forwards)	1,561				—				—				1,561
Interest rate swaps	—				1,956				—				1,956
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

(1)	Goodwill with a carrying amount of $101,913 as of December 31, 2014 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.

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(7)	Derivative Financial Instruments

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			Gain (Loss) Recognized in Income
			Year Ended December 31,
	Location		2016				2015				2014
Fair value hedges of consigned inventory (1)	Interest expense		$	(19,020	)		$	8,894			$	28,242
Total derivatives			$	(19,020	)		$	8,894			$	28,242

_________________

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

			Gain (Loss) Recognized in Income
			Year Ended December 31,
	Location		2016				2015				2014
Commodity contracts (futures and forwards)	Cost of sales		$	5,451			$	(6,302	)		$	(18,950	)
Commodity contracts (swaps)	Cost of sales		367				17,267				20,232
Total derivatives			$	5,818			$	10,965			$	1,282

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(8)	Accounts and Other Receivables

	As of December 31,
	2016				2015
Trade accounts receivable	$	121,663			$	98,164
Other receivables	14,171				21,724
Allowance for doubtful accounts	(1,090		)		(717		)
Total accounts and other receivables, net	$	134,744			$	119,171

	Balance at Beginning of Period				Additions Charged to Expense				Deductions				Balance at End of Period
2016	$	717			$	373			$	—			$	1,090
2015	761				126				(170		)		717
2014	461				300				—				761

(9)	Inventories

	As of December 31,
	2016				2015
Crude oil, refined products, asphalt and blendstocks	$	57,021			$	42,123
Crude oil consignment inventory (Note 10)	11,708				2,928
Materials and supplies	27,826				26,940
Store merchandise	26,752				28,475
Store fuel	7,195				5,049
Total inventories	$	130,502			$	105,515

(10)	Inventory Financing Agreements

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(11)	Property, Plant and Equipment, Net

	As of December 31,
	2016				2015
Refining facilities	$	2,005,015			$	1,915,924
Pipelines and terminals	43,538				43,443
Retail	214,596				209,921
Other	26,657				23,377
Property, plant and equipment, gross	2,289,806				2,192,665
Accumulated depreciation	(922,911		)		(812,463		)
Property, plant and equipment, net	$	1,366,895			$	1,380,202

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(12)	Goodwill

		Refining and Marketing				Asphalt				Retail				Total
Balance at December 31, 2013		$	39,028			$	16,726			$	50,189			$	105,943
Decrease of goodwill (1)		—				(4,030		)		—				(4,030		)
Balance at December 31, 2014		39,028				12,696				50,189				101,913
Decrease of goodwill (2)		(39,028		)		—				—				(39,028		)
Balance at December 31, 2015		—				12,696				50,189				62,885
Increase of goodwill		—				—				—				—
Balance at December 31, 2016		$	—			$	12,696			$	50,189			$	62,885

________________

(1)	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.

(2)

The volatility in the crude price environment during 2015 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. As a result, we have delayed planned projects within the California refining reporting unit, which had a negative effect on the timing of future cash flows. We recognized a goodwill impairment loss of $39,028 related to our California refining reporting unit for the year ended December 31, 2015.

(13)	Other Assets, Net

	As of December 31,
	2016				2015
Deferred turnaround and catalyst costs	$	79,391			$	87,469
Environmental receivables (Note 22)	2,762				2,648
Intangible assets, net	18,962				14,505
Receivable from supply and offtake agreements (Note 10)	26,179				26,179
Fair value hedges of consigned inventory (Note 7)	14,777				33,797
Other, net	18,726				21,027
Total other assets	$	160,797			$	185,625

(14)	Accounts Payable, Accrued Liabilities and Other Non-Current Liabilities

(a)	Accounts Payable

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(b)	Accrued Liabilities and Other Non-Current Liabilities

(15)	Postretirement Benefits

(a)	Retirement Plans

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	Pension Benefits
	2016				2015
Amounts recognized in the consolidated balance sheets:
Pension benefit liability	$	(47,146	)		$	(42,001	)

	Pension Benefits
	2016				2015
Net actuarial loss	$	(42,692	)		$	(42,091	)
Prior service credit	174				225
Total	$	(42,518	)		$	(41,866	)

	Pension Benefits
Amortization of prior service credit	$	(51	)
Amortization of net actuarial loss	3,156
Total	$	3,105

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	Pension Benefits
	2016			2015			2014
Discount rate	4.45	%		3.95	%		4.75	%
Expected return on plan assets	8.50	%		8.50	%		8.60	%
Rate of compensation increase	3.00	%		2.50	%		3.00	%

	Pension Benefits
	Year Ended December 31,
	2016				2015				2014
Components of net periodic benefit cost:
Service cost	$	3,806			$	3,985			$	3,424
Interest cost	5,637				5,022				4,952
Amortization of prior service credit	(51		)		(51		)		(51		)
Expected return on plan assets	(6,997		)		(6,329		)		(5,478		)
Recognized net actuarial loss	3,278				3,408				2,432
Net periodic benefit cost	$	5,673			$	6,035			$	5,279

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	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, 2016
Equity securities:
U.S. companies	$	56,959			$	—			$	—			$	56,959
International companies	13,045				—				—				13,045
Debt securities:
Preferred securities	4,000				—				—				4,000
Bond securities	—				7,272				—				7,272
Real estate securities	8,367				—				—				8,367
Total	$	82,371			$	7,272			$	—			$	89,643
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

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(b)	Postretirement Medical Plan

(16)	Indebtedness

	As of December 31,
	2016				2015
Term loan credit facilities	$	284,233			$	256,519
Alon USA, LP Credit Facility	—				55,000
Convertible senior notes	136,602				129,623
Retail credit facilities	107,131				114,820
Total debt	527,966				555,962
Less: Current portion	16,414				16,420
Total long-term debt	$	511,552			$	539,542

(a)	Alon USA Energy, Inc.

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	As of December 31,
	2016				2015
Equity component, pretax (1)	$	30,365			$	30,365
Convertible Notes:
Principal balance	150,000				150,000
Less: Unamortized issuance discount	(11,848		)		(18,028		)
Less: Unamortized issuance costs	(1,550		)		(2,349		)
Convertible Notes, net	$	136,602			$	129,623

_________________

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(b)	Alon USA Partners, LP

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(c)	Alon Refining Krotz Springs, Inc.

(d)	Retail

(e)	Financial Covenants

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(f)	Maturity of Long-Term Debt

(g)	Interest and Financing Expense

	Year Ended December 31,
	2016				2015				2014
Interest expense on debt	$	33,204			$	33,162			$	37,850
Letters of credit and finance charges	30,815				40,058				65,156
Amortization of debt issuance costs	3,052				3,595				3,759
Write-off of debt issuance costs	—				—				558
Amortization of original issuance discount	6,831				6,273				6,306
Write-off of original issuance discount	—				—				391
Less: Capitalized interest	(4,185		)		(3,262		)		(2,877		)
Total interest expense	$	69,717			$	79,826			$	111,143

(17)	Stockholders' Equity

(a)	Common stock (share value in dollars)

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(b)	Preferred stock (share value in dollars)

(c)	Dividends

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(d)	Accumulated Other Comprehensive Loss

(18)	Stock-Based Compensation (share values in dollars)

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(19)	Income Taxes

	As of December 31,
	2016				2015
Deferred income tax assets:
Accounts receivable, allowance	$	197			$	198
Inventories	8,273				9,530
Accrued liabilities and other	1,564				1,605
Post-retirement benefits	16,623				18,437
Derivative instruments designated as cash flow hedges	721				800
Non-current accrued liabilities and other	20,970				24,383
Net operating loss carryover	23,923				21,212
Tax credits	1,141				1,150
Other	6,999				4,332
Deferred income tax assets	$	80,411			$	81,647
Deferred income tax liabilities:
Deferred gain on the Offering of the Partnership	$	50,115			$	50,178
Deferred charges	358				401
Unrealized gains	(1,208		)		4,645
Property, plant and equipment	369,406				370,225
Other non-current	16,233				11,631
Intangibles	12,506				11,361
Deferred income tax liabilities	$	447,410			$	448,441

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(20)	Earnings (Loss) Per Share

	Year Ended December 31,
	2016				2015				2014
Net income (loss) available to stockholders	$	(82,805	)		$	52,751			$	38,457
less: preferred stock dividends	—				15				59
Net income (loss) available to common stockholders	(82,805		)		52,736				38,398
Weighted average shares outstanding, basic	70,739				69,772				68,985
Dilutive common stock equivalents	—				942				388
Weighted average shares outstanding, diluted	70,739				70,714				69,373
Earnings (loss) per share, basic	$	(1.17	)		$	0.76			$	0.56
Earnings (loss) per share, diluted	$	(1.17	)		$	0.75			$	0.55

(21)	Related Party Transactions

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(22)	Commitments and Contingencies

(a)	Leases

(b)	Commitments

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(c)	Contingencies

(d)	Environmental

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Year ending December 31,
2017	$	3,909
2018	3,577
2019	2,756
2020	3,201
2021	2,788
2022 and thereafter	37,850
Discounted environmental liabilities, gross	54,081
Less: Discount applied	10,400
Discounted environmental liabilities	$	43,681

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(23)	Quarterly Information (unaudited)

(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 12) .

(24)	Subsequent Events

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EXHIBITS

Exhibit No.		Description of Exhibit
2.1		Agreement and Plan of Merger, dated as of January 2, 2017, by and among Alon USA Energy, Inc., Delek US Holdings, Inc., Dione Mergeco, Inc., Astro Mergeco, Inc., and Delek Holdco, Inc. (incorporated by reference to Exhibit 2.1 to Form 8-K filed by the Company on January 3, 2017, SEC File No. 001-32567).
2.2		First Amendment to Agreement and Plan of Merger, dated as of February 27, 2017, by and among Alon USA Energy, Inc., Delek US Holdings, Inc., Dione Mergeco, Inc., Astro Mergeco, Inc., and Delek Holdco, Inc.
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		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).
10.9		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).
10.10*		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).
10.11*		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).

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Exhibit No.		Description of Exhibit
10.12*		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).
10.13*		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).
10.14*		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).
10.15*		Second Amendment to Executive Employment Agreement, dated as of July 23, 2015, between Shai Even and Alon USA GP, LLC (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on July 30, 2015, SEC File No. 001-32567).
10.16*		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).
10.17*		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).
10.18*		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).
10.19*		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).
10.20*		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).
10.21*		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).
10.22*		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).
10.23*		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).
10.24*		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).
10.25*		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).
10.26*		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).
10.27*		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).
10.28*		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).
10.29*		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).
10.30†		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).
10.31*		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).
10.32*		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).

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Exhibit No.		Description of Exhibit
10.33*		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).
10.34*		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).
10.35*		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).
10.36*		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).
10.37*		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).
10.38*		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).
10.39*		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).
10.40*		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).
10.41*		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).
10.42*		Alon USA Energy, Inc. Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 12, 2017).
10.43*		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).
10.44*		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).
10.45*		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).
10.46		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).
10.47		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).
10.48		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).
10.49		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).
10.50		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).

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Exhibit No.		Description of Exhibit
10.51		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).
10.52†		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).
10.53		Amendment to Second Amended and Restated Supply and Offtake Agreement, dated as of January 13, 2017, between Alon Refining Krotz Springs, Inc. and J. Aron & Company.
10.54†		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).
10.55†		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).
10.56		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).
10.57		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).
10.58		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).
10.59		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).
10.60		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).
10.61		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).
10.62		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).
10.63		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).
10.64		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).
10.65		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).
10.66		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).
10.67		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).
10.68		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).
10.69		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).

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Exhibit No.		Description of Exhibit
10.70		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).
10.71		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).
10.72		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).
10.73		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, 2016, 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.

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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 27, 2017	By:	/s/ Alan Moret
			Alan Moret
			Interim 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 27, 2017	By:	/s/ Ezra Uzi Yemin
			Ezra Uzi Yemin
			Chairman of the Board
Date:	February 27, 2017	By:	/s/ Alan Moret
			Alan Moret
			Interim Chief Executive Officer
			(Principal Executive Officer)
Date:	February 27, 2017	By:	/s/ Shai Even
			Shai Even
			Senior Vice President and Chief Financial Officer
			(Principal Accounting Officer)
Date:	February 27, 2017	By:	/s/ David Wiessman
			David Wiessman
			Director
Date:	February 27, 2017	By:	/s/ Zalman Segal
			Zalman Segal
			Director
Date:	February 27, 2017	By:	/s/ Ron W. Haddock
			Ron W. Haddock
			Director
Date:	February 27, 2017	By:	/s/ Ilan Cohen
			Ilan Cohen
			Director
Date:	February 27, 2017	By:	/s/ Assaf Ginzburg
			Assaf Ginzburg
			Director
Date:	February 27, 2017	By:	/s/ Frederec Green
			Frederec Green
			Director
Date:	February 27, 2017	By:	/s/ Mark D. Smith
			Mark D. Smith
			Director
Date:	February 27, 2017	By:	/s/ Avigal Soreq
			Avigal Soreq
			Director

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Table of Contents

Date:	February 27, 2017	By:	/s/ William Kacal
			William Kacal
			Director
Date:	February 27, 2017	By:	/s/ Franklin Wheeler
			Franklin Wheeler
			Director