Attached files

file filename
EX-21.1 - SUBSIDIARY LIST - Alon USA Energy, Inc.alj-ex211_2014xlistofsubsi.htm
EXCEL - IDEA: XBRL DOCUMENT - Alon USA Energy, Inc.Financial_Report.xls
EX-31.2 - CERTIFICATION - Alon USA Energy, Inc.alj-ex312_20141231xq4.htm
EX-32.1 - CERTIFICATION - Alon USA Energy, Inc.alj-ex321_20141231xq4.htm
EX-23.1 - AUDITOR CONSENT - Alon USA Energy, Inc.alj-ex231_2014xconsent.htm
EX-31.1 - CERTIFICATION - Alon USA Energy, Inc.alj-ex311_20141231xq4.htm

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
þ
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2014
OR
o
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
FOR THE TRANSITION PERIOD FROM __________TO __________ 
Commission file number: 001-32567
ALON USA ENERGY, INC.
(Exact name of Registrant as specified in its charter)
Delaware
(State of incorporation)
 
74-2966572
(I.R.S. Employer Identification No.)
 
 
 
12700 Park Central Dr., Suite 1600, Dallas, Texas
(Address of principal executive offices)
 
75251
(Zip Code)
Registrant’s telephone number, including area code: (972) 367-3600
Securities registered pursuant to Section 12 (b) of the Act:
Title of each class
 
Name of each exchange on which registered
 
 
 
Common Stock, par value
$0.01 per share
 
New York Stock Exchange
Securities registered pursuant to Section 12 (g) of the Act: Series A Preferred Stock, par value $0.01 per share
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o
Accelerated filer þ
Non-accelerated filer o
Smaller reporting company o
 
 
(Do not check if a smaller reporting company)
 
Indicate by check whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value for the registrant’s common stock held by non-affiliates as of June 30, 2014, the last day of the registrant’s most recently completed second fiscal quarter was $327,903,310.
The number of shares of the Registrant’s common stock, par value $0.01 per share, outstanding as of March 1, 2015, was 69,772,369.
Documents incorporated by reference: Proxy statement of the registrant relating to the registrant’s 2015 annual meeting of stockholders, which is incorporated into Part III of this Form 10-K.
 
 



TABLE OF CONTENTS

 
Page
 
 
 
 
 

PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES.
Statements in this Annual Report on Form 10-K, including those in Items 1 and 2, “Business and Properties,” and Item 3, “Legal Proceedings,” that are not historical in nature should be deemed forward-looking statements that are inherently uncertain. See “Forward-Looking Statements” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of forward-looking statements and of factors that could cause actual outcomes and results to differ materially from those projected.
Company Overview
In this Annual Report, the words “Alon,” “we,” “our” and “us” refer to Alon USA Energy, Inc. and its consolidated subsidiaries or to Alon USA Energy, Inc. or an individual subsidiary, and not to any other person. Generally, the words “we,” “our” and “us” include Alon USA Partners, LP and its subsidiaries (the “Partnership”) as consolidated subsidiaries of Alon USA Energy, Inc. unless when used in disclosures of transactions or obligations between the Partnership and Alon USA Energy, Inc., or its other subsidiaries.
We are an independent refiner and marketer of petroleum products, operating primarily in the South Central, Southwestern and Western regions of the United States. We own 100% of the general partner and 81.6% of the limited partner interests in Alon USA Partners, LP (NYSE: ALDW), which owns a crude oil refinery in Big Spring, Texas, with a crude oil throughput capacity of 73,000 barrels per day (“bpd”). In addition, we directly own crude oil refineries in Krotz Springs, Louisiana, with a crude oil throughput capacity of 74,000 bpd and in California with a crude oil throughput capacity of 70,000 bpd. In 2014 and 2013, we did not process crude oil in California. 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 in Central and West Texas and New Mexico.
We were incorporated in 2000 under Delaware law. Our principal executive offices are located at 12700 Park Central Drive, Suite 1600, Dallas, Texas 75251, and our telephone number is (972) 367-3600. Our website can be found at www.alonusa.com.
Our stock trades on the New York Stock Exchange under the trading symbol “ALJ.” Until recently, we relied on a “controlled company” exemption from the rules and regulations of the New York Stock Exchange because more than 50% of our common stock was controlled by Alon Israel Oil Company, Ltd. (“Alon Israel”). In February 2015, Alon Israel sold a sufficient number of shares to cause their ownership to fall below 50%. As a result, a majority of our board of directors must be comprised of directors deemed independent by February 2016. Alon Israel, an Israeli limited liability company, is the largest services and trade company in Israel. Alon Israel entered the gasoline marketing and convenience store business in Israel in 1989 and has grown to become a leading marketer of petroleum products and one of the largest operators of retail gasoline and convenience stores in Israel. Alon Israel is a controlling shareholder of Alon Holdings Blue Square-Israel Ltd. (“Blue Square”), a leading retailer in Israel, which is listed on the New York Stock Exchange and the Tel Aviv Stock Exchange, and Blue Square is a controlling shareholder of Dor-Alon Energy in Israel (1988) Ltd. (“Dor-Alon”), a leading Israeli marketer, developer and operator of gas stations and shopping centers, which is listed on the Tel Aviv Stock Exchange.
We file annual, quarterly and current reports and proxy statements, and file or furnish other information, with the Securities Exchange Commission (“SEC”). Our SEC filings are available to the public at the SEC’s website at www.sec.gov. In addition, we make our SEC filings available, free of charge, through our website at 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 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;
Corporate Governance Guidelines; and
Code of Business Conduct and Ethics.
Business
Our presentation of segment data reflects our following three operating segments: (i) refining and marketing, (ii) asphalt and (iii) retail. Additional information regarding our operating segments and properties is presented in the notes to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.



Refining and Marketing
Our refining and marketing segment includes a sour crude oil refinery located in Big Spring, Texas, a light sweet crude oil refinery located in Krotz Springs, Louisiana and heavy crude oil refineries located in Paramount, Bakersfield and Long Beach, California (“California refineries”). Our California refineries did not process crude oil in 2014 and 2013 due to the high cost of crude oil relative to product yield and low asphalt demand. Our refineries have a combined crude oil throughput capacity of approximately 217,000 bpd. We refine crude oil into petroleum products, including various grades of gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt, and other petroleum-based products, which are marketed primarily in the South Central, Southwestern and Western United States.
Alon USA Partners, LP (NYSE: ALDW)
Alon owns the Big Spring refinery and wholesale marketing operations through the Partnership. On November 26, 2012, the Partnership completed its initial public offering of 11,500,000 common units representing limited partner interests. As of December 31, 2014, the common units held by the public represent 18.4% of the Partnership’s common units outstanding. We own the remaining 81.6% of the Partnership’s common units and Alon USA Partners GP, LLC (the “General Partner”), our wholly-owned subsidiary, owns 100% of the non-economic general partner interest in the Partnership. The Partnership is consolidated within our refining and marketing segment.
Big Spring Refinery
Our Big Spring refinery has a crude oil throughput capacity of 73,000 bpd and is located on 1,306 acres in the Permian Basin in West Texas. In industry terms, our Big Spring refinery is characterized as a “cracking refinery,” which generally refers to a refinery utilizing vacuum distillation and catalytic cracking processes in addition to basic distillation, naphtha reforming and hydrotreating processes, to produce higher light product yields through the conversion of heavier fuel oils into gasoline, light distillates and intermediate products. Major processing units at our Big Spring refinery include fluid catalytic cracking, naphtha reforming, vacuum distillation, hydrotreating and alkylation units.
Our Big Spring refinery’s complexity allows us the flexibility to process a variety of crudes into higher-value refined products. Our Big Spring refinery has the capability to process substantial volumes of high-sulfur, or sour, crude oils to produce a high percentage of light, high-value refined products. Our refinery is also capable of processing significant volumes of light, sweet crude as market conditions dictate. All of the crude oil processed at our refinery is West Texas crude oil based on Midland pricing, which has typically traded at a discount to Cushing pricing.
Our Big Spring refinery produces ultra-low sulfur gasoline, ultra-low sulfur diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum products. This refinery typically converts approximately 90% of its feedstock into finished products such as gasoline, diesel, jet fuel and petrochemicals, with the remaining 10% primarily converted to asphalt and liquefied petroleum gas.
Big Spring Refinery Raw Material Supply
West Texas crudes have typically been transported to Cushing for sale. However, new pipeline takeaway capacity has allowed West Texas crude to also be transported directly to the Texas Gulf Coast. Logistical and infrastructure constraints in the Permian Basin have limited the ability of oil producers to transport their growing production to Cushing or the Gulf Coast. The resulting oversupply of West Texas crudes at Midland has depressed Midland-priced crudes. The Big Spring refinery is the closest refinery to Midland, Texas, which allows us to eliminate the cost of transporting crude supply to and from Cushing. Our close proximity to Midland allows us to source West Texas Sour (“WTS”) and West Texas Intermediate (“WTI”) Midland crudes, both of which traded at a considerable discount to WTI Cushing over the last few years. Additionally, the Big Spring refinery has the ability to source locally-trucked crudes, which enables us to better control quality and to eliminate the cost of transporting the crude supply from Midland. During 2014, our Big Spring refinery’s total refinery throughput was comprised of 46% WTS, 49% WTI Midland and 5% blendstocks.
Our Big Spring refinery receives WTS and WTI crude oil from local gathering systems and regional common carrier pipelines, such as the Mesa Interconnect, Centurion and Navigator pipelines.
Other feedstocks, including butane, isobutane and asphalt blending components, are delivered by truck and railcar. A majority of the natural gas we use to run the refinery is delivered by a pipeline in which we own a 63.0% interest.
J. Aron and Company (“J. Aron”), through arrangements with various oil companies, is currently the largest single crude supplier to our Big Spring refinery.


3


Big Spring Refinery Production
Gasoline. We produce various grades of gasoline, ranging from 84 sub-octane regular unleaded to 91 octane premium unleaded. Gasoline produced at the Big Spring refinery complies with the U.S. Environmental Protection Agency’s (“EPA”) current ultra-low sulfur gasoline standard of 30 parts per million (“ppm”).
Distillates. All of the on-road specification diesel fuel we produce complies with the EPA’s ultra-low sulfur diesel standard of 15 ppm. Our jet fuel production conforms to the JP-8 grade military specifications.
Asphalt. Our asphalt facilities are capable of producing up to 30 different product formulations, including both polymer modified asphalt (“PMA”) and ground tire rubber (“GTR”) asphalt. Asphalt produced at the Big Spring refinery is transferred to our asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate bulk wholesale market prices.
Petrochemical Feedstocks and Other. We produce propane, propylene, certain aromatics, specialty solvents and benzene for use as petrochemical feedstocks, along with other by-products such as sulfur and carbon black oil. Our Big Spring refinery has a sulfur processing capability of approximately two tons per thousand bpd of crude oil capacity, which is above the average for cracking refineries and aids in our ability to produce low sulfur motor fuels while processing significant amounts of sour crude oil.
Big Spring Refinery Transportation Fuel Marketing
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 West and Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in these regions as our “physically integrated system” because our distributors in this region are supplied primarily with motor fuels produced at our Big Spring refinery and distributed through a network of pipelines and terminals which we either own or have access to through leases or long-term throughput agreements.
Branded Transportation Fuel Marketing. In 2014, we sold 58% of the gasoline and 29% of the diesel produced at our Big Spring refinery on a branded basis. We sell motor fuels under the Alon brand through various terminals to supply 644 locations, including our convenience stores. We provide 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.
Each branded location is required to participate in our Clean Team brand excellence program and utilize our payment card processing services. Under the Clean Team program, each branded location is graded quarterly by a third-party rating agency that specializes in convenience store assessment and reporting. Each location is graded on the physical appearance and condition of the store’s interior and exterior. The inspections also include evaluations of the customer service provided by employees.
In 2014, we sold 470.9 million gallons of branded motor fuel for distribution to our retail convenience stores and other retail distribution outlets. In 2014, approximately 90% of Alon’s branded marketing operations, including retail operations, were supplied by our Big Spring refinery. In 2014, the retail segment’s gasoline and diesel sales represented 27% and 8%, respectively, of our Big Spring refinery’s gasoline and diesel production.
Unbranded Transportation Fuel Marketing. In 2014, we sold 26% of the gasoline and a majority of the diesel produced at our Big Spring refinery on an unbranded basis. Including purchases for resell, in 2014, we sold 347.9 million gallons of gasoline and diesel as unbranded fuels, which were largely sold through our physically integrated system.
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 rack 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 traders and are transported through a product pipeline network or truck deliveries. Our petrochemical feedstock and other petroleum product production is sold to a wide customer base and is transported through truck and railcars.
Distribution Network and Distributor Arrangements. We sell motor fuel to our retail locations and to 25 third-party distributors, who then supply and sell to retail outlets. The supply agreements we maintain with our 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.


4


Alon Brand Licensing. We license the Alon brand and provide payment card processing services, advertising programs and loyalty and other marketing programs to 27 distributors supplying 73 additional stores not tied to a fuel supply agreement. In exchange for licensing fees, we license the Alon brand to distributors supplying geographic areas outside of our physically-integrated system. This licensing program allows us to expand the geographic footprint of the Alon brand, thereby increasing its recognition. Each licensee is also required to participate in our Clean Team brand excellence program and utilize our payment card processing services.
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 our Big Spring refinery. These pipelines provide us flexibility to optimize product flows into multiple regional markets. This product pipeline network can also (1) receive additional transportation fuel products from the Gulf Coast through the Delek product terminal and Magellan pipelines, (2) deliver and receive products to and from the Magellan system, our connection to the Group III, or mid-continent markets, and (3) deliver products to the New Mexico and Arizona markets through third-party systems.
Product Terminals
We primarily utilize five product terminals in Big Spring, Abilene, Orla, and Wichita Falls, Texas and Duncan, Oklahoma to market transportation fuels produced at our Big Spring refinery. All five of these terminals are physically integrated with our Big Spring refinery through the product pipelines we utilize. Three of these five terminals, Big Spring, Abilene and Wichita Falls, are equipped with truck loading racks. The other two terminals, Duncan, Oklahoma and Orla, Texas, are used for delivering shipments into third-party pipeline systems. We also have direct access to three other terminals located in El Paso, Texas and Tucson and Phoenix, Arizona.
California Refineries
Our California refineries historically operated as one integrated refinery. The California refineries have a throughput capacity of 70,000 bpd. However, due to the high cost of crude oil relative to product yield and low asphalt demand, we did not process crude oil in 2014 and 2013 and ran at low throughput rates during 2012.
The Paramount refinery is located on 63 acres in Paramount, California. Our Paramount refinery has the capability to produce gasoline, distillates, vacuum gas oil and asphalt.
The Long Beach refinery is located on 19 acres in Long Beach, California. The Long Beach refinery has the capability to produce vacuum gas oil and asphalt.
The Bakersfield refinery is located on approximately 600 acres in Bakersfield, California. The Bakersfield refinery has the capability to produce gasoline, distillates, vacuum gas oil and asphalt.
In the third quarter of 2014, we received a permit to construct a new 140,000 bpd rail unloading facility at the Bakersfield refinery and to modify the refinery to process light crude. The rail facility will give us the ability to source cost-advantaged crudes at the refinery for use by third parties or by us upon the restart of the Bakersfield refinery. This rail facility could receive up to two unit trains of crude per day.
California Refineries Raw Material Supply
Historically our California refineries received crude oil primarily from common carrier, private carrier and our owned pipelines. We have the capability to receive crude oil by rail at each of the California refineries’ locations. We are party to an agreement allowing us to purchase the California refineries’ crude needs through J. Aron. Other feedstocks, including butane and gasoline blendstocks, can be delivered by truck and pipeline. This combination of transportation arrangements allows the California refineries to receive and optimize the crude slate of waterborne domestic and foreign crude oil, along with California crude oil.
California Pipelines/Terminal
The California refineries utilize product pipelines, truck racks and terminals to distribute refined products. The Paramount and Long Beach refineries are connected by pipelines we own.
The California refineries have a feedstock pipeline and terminal system that is capable of supplying untreated vacuum gas oil and other unfinished products to other Los Angeles Basin refineries and third party terminals.
Krotz Springs Refinery
The Krotz Springs refinery located in Krotz Springs, Louisiana, has a throughput capacity of 74,000 bpd and is strategically located on approximately 381 acres on the Atchafalaya River in central Louisiana. This location provides access to


5


crude from barge, pipeline, railcar and truck. The refinery has direct access to the Colonial product pipeline system (“Colonial Pipeline”). This combination of logistical assets provides us with diversified access to locally-sourced, domestic and foreign crudes, as well as distribution of our products to markets throughout the Southern and Eastern United States and along the Mississippi and Ohio Rivers. In industry terms, the Krotz Springs refinery is characterized as a “mild residual cracking refinery,” which generally refers to a refinery utilizing vacuum distillation and catalytic cracking processes in addition to basic distillation and naphtha reforming processes to minimize low quality black oil production and to produce higher light product yields.
Our Krotz Springs refinery has the capability to process substantial volumes of low sulfur, or sweet, crudes to produce a high percentage of light, high-value refined products. Historically, sweet crude oil has accounted for 100% of the Krotz Springs refinery’s crude oil input.
Krotz Springs Refinery Raw Material Supply
In 2012, the Krotz Springs refinery began receiving crude oil sourced from West Texas to take advantage of depressed Midland-priced crudes. 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. The Krotz Springs refinery also has access to various types of domestic and foreign crudes via pipeline, rail or truck rack delivery. We are capable of receiving Light Louisiana Sweet (“LLS”) and foreign crudes from the EMPCo “Northline System.” The Northline System delivers LLS and foreign crude oils from the St. James, Louisiana crude oil terminalling complex.
Sweet crude oil accounts for all of the crude oil inputs at the Krotz Springs refinery, of which 58% was Gulf Coast sweet crude oils and 42% was WTI Midland priced crude oil in 2014.
J. Aron, through arrangements with various oil companies, currently supplies the majority of the Krotz Springs refinery’s crude oil input requirements. Other feedstocks, including butane and secondary feedstocks, are delivered by truck and marine transportation.
Krotz Springs Refinery Production
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
Substantially all of the gasoline and jet fuel produced by our Krotz Springs refinery is sold to J. Aron. We market transportation fuel production through bulk sales and exchange channels. These bulk sales and exchange arrangements are entered into with various oil companies and traders and are transported to markets on the Mississippi River and the Atchafalaya River as well as to the Colonial Pipeline.
Krotz Springs Refinery Product Pipelines
The Krotz Springs refinery connects to and distributes refined products into the Colonial Pipeline for distribution by our customers to the Southern and Eastern United States.
Krotz Springs Refinery Barge, Railcar and Truck
Products not shipped through the Colonial Pipeline, such as high sulfur diesel, are transported via barge for sale. Barges originating at the Krotz Springs refinery have access to both the Mississippi and Ohio Rivers.
Propylene/propane mix is sold via railcar and truck, to consumers at Mont Belvieu, Texas or in adjacent Louisiana markets. Mixed LPGs are shipped to an LPG fractionator at Napoleonsville, Louisiana. We pay a fractionation fee and sell the ethane and propane to a regional chemical company under contract, transport the normal butane back to the Krotz Springs refinery via truck for blending, and sell the isobutane and natural gasoline on a spot basis.
Asphalt
We own or operate 10 asphalt terminals located in Texas (Big Spring), Washington (Richmond Beach), California (Paramount, Long Beach, Elk Grove, Mojave and Bakersfield), Arizona (Phoenix and Flagstaff), and Nevada (Fernley) (50% interest), and a 50% interest in Wright Asphalt Products Company, LLC (“Wright”), which specializes in patented ground tire rubber modified asphalt products. The operations in which we have a 50% interest are recorded under the equity method of accounting and the investments are included as part of total assets in the asphalt segment data.
We purchase non-blended asphalt from third parties in addition to non-blended asphalt produced at the Big Spring refinery. We market asphalt through our terminals as blended and non-blended asphalt. We have an exclusive license to use advanced asphalt-blending technology in West Texas, Arizona, New Mexico and Colorado, and a non-exclusive license in Idaho,


6


Montana, Nevada, North Dakota, Utah and Wyoming, with respect to asphalt produced at our Big Spring refinery, and a ground tire rubber (“GTR”) asphalt manufacturing process with respect to asphalt sold in California.
Asphalt produced by our Big Spring refinery is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude, which is intended to approximate wholesale market prices. We market asphalt primarily as paving asphalt to road and materials manufacturers and highway construction/maintenance contractors as GTR, polymer modified or emulsion asphalt. Sales of asphalt are seasonal with the majority of our sales occurring between May and October.
Wright holds the licensing rights to a patented GTR manufacturing process for paving asphalts. Wright licenses this proprietary technology from Neste/Wright Asphalt Company under a perpetual license that covers all of North America, except California. Wright’s operations consist of sub-licensing the patented technology to parties to manufacture the GTR asphalt for Wright to sell at various Alon-owned or third party-owned facilities in Texas, Arizona, Oregon and Oklahoma. Wright also purchases and resells various other paving asphalts in these markets. During 2014, Wright obtained 56% of its asphalt requirements from our terminals. Wright sells GTR and its other asphalt products on either a negotiated contract or competitive bidding basis.
Retail
As of December 31, 2014, we operated 295 owned and leased convenience store sites primarily in Central and West Texas and New Mexico. Our convenience stores typically offer various grades of gasoline, diesel fuel, food products, food service, tobacco products, non-alcoholic and alcoholic beverages, general merchandise as well as money orders to the public.
The following table shows our owned and leased convenience stores by location:
Location
 
Owned
 
Leased
 
Total
Big Spring, Texas
 
6

 
2

 
8

Wichita Falls, Texas
 
9

 
2

 
11

Waco, Texas
 
10

 

 
10

Midland, Texas
 
10

 
7

 
17

Lubbock, Texas
 
17

 
4

 
21

Albuquerque, New Mexico
 
12

 
11

 
23

Odessa, Texas
 
13

 
22

 
35

Abilene, Texas
 
32

 
8

 
40

El Paso, Texas
 
13

 
69

 
82

Other locations in Central and West Texas
 
29

 
19

 
48

Total stores
 
151

 
144

 
295

The merchandise requirements of our convenience stores are serviced at least weekly by over 100 direct-store delivery (“DSD”) vendors. In order to minimize costs and facilitate deliveries, we utilize a single wholesale distributor, Core-Mark Mid-Continent, Inc., for non-DSD products. We purchase the products from Core-Mark at cost plus an agreed upon mark-up. Our current supply contract with Core-Mark expires in December 2017.
We are 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 convenience store operations.
Competition
The petroleum refining and marketing industry continues to be highly competitive. Our principal competitors include major independent refining and marketing companies such as Valero, Phillips 66, HollyFrontier and Western Refining. Our industry is also impacted by competition from integrated, multi-national oil companies including ExxonMobil, Chevron and Royal Dutch Shell. Because of their diversity, integration of operations and larger capitalization, these major competitors may have greater financial support and diversity with a potentially better ability to bear the economic risks, operating risks and volatile market conditions associated with the petroleum industry.
Profitability in the refining and marketing industry depends on the difference between refined product prices and the prices for crude 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.


7


All of our crude and feedstocks are purchased from third-party sources, while some of our vertically-integrated competitors have their own sources of crude oil that they may use to supply their refineries. However, our Big Spring refinery is in close proximity to Midland, Texas, which is the largest origination terminal for West Texas crude oil, which we believe provides us with transportation cost advantages over many of our regional competitors.
The markets for our refined products are generally supplied by a number of refiners, including large integrated oil companies or independent refiners. These larger companies typically have greater resources and may have greater flexibility in responding to volatile market conditions or absorbing market changes.
The principal competitive factors affecting our marketing businesses are price and quality of products, reliability and availability of supply and location of distribution points.
We compete in the asphalt market with various refineries including Valero, Tesoro, U.S. Oil, Western Refining, San Joaquin Refining, Ergon and HollyFrontier as well as regional and national asphalt marketing companies that have little or no associated refining operations. The principal factors affecting competitiveness in asphalt markets are cost, supply reliability, consistency of product quality, transportation cost and capability to produce the range of high performance products necessary to meet the requirements of customers.
Our major retail competitors include CST Brands, Chevron, Sunoco LP (Stripes® brand), Alimentation Couche-Tard Inc. (Circle K® brand), Western Refining and various other independent operators. The principal competitive factors affecting our retail segment are location of stores, product price and quality, appearance and cleanliness of stores and brand identification. We expect to continue to face competition from large, integrated oil companies, as well as from other convenience stores that sell motor fuels. Additionally, national grocery and dry goods retailers such as Wal-Mart, Kroger and Costco, as well as regional grocers and retailers have motor fuel retail businesses. Many of these competitors are substantially larger than we are and because of their diversity, integration of operations and greater resources may be better able to withstand volatile market conditions and lower profitability because of competitive pricing and lower operating costs.
Government Regulation and Legislation
Environmental Controls and Expenditures
Our operations are subject to extensive and frequently changing federal, state, regional and local laws, regulations and ordinances relating to the protection of the environment, including those governing emissions or discharges to the air, water, and land, the handling and disposal of solid and hazardous waste and the remediation of contamination. We believe our operations are generally in compliance with these requirements. Over the next several years our operations will have to meet new requirements being promulgated by the EPA and the states and jurisdictions in which we operate.
Fuels. The federal Clean Air Act and its implementing regulations require, among other things, significant reductions in the sulfur content in gasoline and diesel fuel. These regulations required most refineries to reduce the sulfur content in gasoline to 30 ppm and diesel to 15 ppm.
Gasoline and diesel produced at our Big Spring refinery currently meet the low sulfur gasoline and diesel fuel standards. Gasoline produced at our Krotz Springs refinery currently meets the low sulfur gasoline standard. Our Krotz Springs refinery does not manufacture low sulfur diesel fuel. In April 2014, the EPA promulgated final new “Tier 3” motor vehicle emission and fuel standards. Under the final rule, gasoline must contain no more than 10 ppm sulfur on an annual average basis beginning on January 1, 2017; however, approved small volume refineries have until January 1, 2020 to meet the standard. We believe that the Big Spring, Krotz Springs, Paramount and Bakersfield refineries each satisfy the definition of a small volume refinery and we have applied to EPA for status as small volume refineries for each of these facilities as is required by the Tier 3 regulations. We estimate that the capital investment associated with upgrades necessary to meet these new required sulfur levels, on a consolidated basis, will be less than $30 million.
The EPA has issued renewable fuel standards (“RFS”) mandates, requiring refiners such as us to blend renewable fuels into the petroleum fuels they produce and sell in the United States. To the extent that refiners will not or cannot blend renewable fuels into the products they produce in the quantities required to satisfy their obligations under the RFS program, those refiners must purchase renewable identification numbers (“RINs”) to maintain compliance. Under the RFS program, the volume of renewable fuels that obligated parties are required to blend into their finished petroleum fuels increases annually over time until 2022. The Big Spring and Krotz Springs refineries first became subject to the RFS program in 2013, and the Krotz Springs refinery received a hardship exemption for 2013. The California refineries did not process crude oil during 2014 and 2013 and as a result were not subject to the RFS requirements. The Big Spring refinery through its wholesale sales is able to blend finished products with renewable fuels, thus generating RINs. Conversely, the Krotz Springs refinery sells substantially all of its finished products which are subject to the RFS program, via the Colonial pipeline, which does not allow us to blend products; and therefore must purchase RINs to satisfy its obligation. The EPA has published the proposed volume mandates for 2014, which are generally lower than the volumes for 2013 and lower than the statutory mandates. The EPA submitted a draft


8


final rule for regulatory review by the federal Office of Management and Budget on August 21, 2014. In January 2015, the EPA announced that its goal was to release the final 2014 RFS volume mandates in the Spring of 2015.
Air Emissions. Conditions may develop that require additional capital expenditures at our refineries, product terminals and retail gasoline stations (operating and closed locations) for compliance with the Federal Clean Air Act and other federal, state and local requirements. We cannot currently determine the amounts of such future expenditures.
Compliance
In 2006, the Governor of California signed into law AB 32, the California Global Warming Solutions Act of 2006. Regulations implementing the goals stated in the law, i.e., the reduction of greenhouse gas (“GHG”) emission levels to 1990 levels through a market based “cap-and-trade” program, have been issued. Although ongoing legal challenges could disrupt implementation of the program, it is expected that AB 32 mandated reductions will require increased emission controls on both stationary and non-stationary sources and will result in requirements to significantly reduce GHGs from our California refineries and possibly our other California terminals.
While it is possible that the federal government will adopt some form of federal mandatory GHG emission reductions legislation in the future, the timing and specific requirements of any such legislation are uncertain at this time.
The EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act including rules that requires a reduction in emissions of GHGs from motor vehicles and another rule that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources that are potential major sources of conventional pollutant emissions. Beginning in January 2011, facilities already subject to the Prevention of Significant Deterioration and Title V operating permit programs that increase their emissions of GHGs by 75,000 tons per year were required to install control technology, known as “Best Available Control Technology,” to address the GHG emissions.
In December 2010, the EPA reached a settlement agreement with numerous parties under which it agreed to promulgate New Source Performance Standards (“NSPS”) to regulate greenhouse gas emissions from petroleum refineries. Although the EPA has not yet proposed NSPS to regulate GHG for petroleum refineries, the EPA has proposed NSPS to regulate GHG for electric utilities. 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 proposed rule would place additional emission control requirements on storage tanks, flares and coking units at petroleum refineries. Therefore, although it may do so in the future, we do not expect that the EPA will be issuing NSPS standards to regulate GHG from petroleum refineries at this time.
In October 2006, we were contacted by Region 6 of the EPA and invited to enter into discussions under the EPA’s National Petroleum Refinery Initiative. This initiative addresses what the EPA deems to be the most significant Clean Air Act compliance concerns affecting the petroleum refining industry. According to the EPA, as of January 2015, approximately 90% of the nation’s refinery capacity is under lodged or entered “global” settlements. If we enter into a global settlement, it would apply to our Big Spring refinery and possibly our Paramount and Long Beach refineries. Based on prior settlements that the EPA has reached with other petroleum refineries under the initiative, we anticipate that we would be required to pay a civil penalty, install air pollution controls, and enhance certain operations in consideration for a broad release from liability. At this time, we cannot estimate the cost of any required controls or civil penalties, but they are expected to be comparable to other settling refiners. These civil penalties will likely exceed $100,000 and other related costs that may be required under the settlement for pollution controls or environmentally beneficial projects could be significant.
The Krotz Springs and Bakersfield refineries were subject to “global settlements” with the EPA under the National Petroleum Refining Initiative, when we acquired them. In return for agreeing to the consent decree and implementing the reductions in emissions that it specifies, the refineries secured broad releases of liability that provide immunity from enforcement actions for alleged past non-compliance under each of the Clean Air Act programs covered by the consent decree. If we are unable to meet the agreed upon reductions without add-on controls, our capital costs could increase. Because the Krotz Springs refinery remains subject to the Valero consent decree, we entered into an agreement with Valero at the time of the acquisition allocating responsibilities under the consent decree. We are responsible for implementing only those portions of the consent decree that are specifically and uniquely applicable to the Krotz Springs refinery.
The Bakersfield refinery became subject to a global settlement with the EPA in 2001. Currently, the only continuing requirements are periodic audits of its Leak Detection and Repair program and enhanced sampling and reporting under the Benzene Waste Operations NESHAP. As part of the global settlement, the Bakersfield refinery was required to perform an evaluation of and has accepted subpart J applicability for two of its pre-1973 flares. System modifications may be needed to comply with emission limits. The costs of any such modifications are unknown at this time. The compliance date has been proposed as January 1, 2017, coincident with the compliance date in local flare Rule 4311.


9


In July 2010, the EPA disapproved Texas’ “flexible permit program” and indicated that sources operating under a flexible permit issued by the Texas Commission on Environmental Quality (“TCEQ”) are not properly permitted and are subject to enforcement. In 2010, the Big Spring refinery was one of more than 100 facilities in Texas to receive a Clean Air Act request for information from the EPA relating to the EPA’s disapproval of Texas’ “flexible permit program.” According to the EPA, the Texas flexible permit program and its implementing rules were never approved by the EPA for inclusion in the Texas state clean-air implementation plan and, therefore, emission limitations in Texas flexible permits are not federally enforceable. The EPA indicated that it would consider enforcement against holders of flexible permits that failed to comply with applicable federal requirements on a case-by-case basis. We had agreed to convert our Big Spring refinery’s non-flexible permit to a federally enforceable non-flexible permit and submitted a permit application for that purpose, which remains pending. In August 2012, the U.S. Fifth Circuit Court of Appeals vacated the EPA’s final rule disapproving Texas’ flexible permit program and remanded the program back to the EPA for further consideration. Following the Fifth Circuit decision, Texas submitted a state clean-air implementation plan, including the flexible permit provisions, to the EPA for reconsideration in accordance with the Fifth Circuit’s decision. In July 2014, the EPA published its approval of Texas’ flexible permit program, conditioned on a commitment from Texas to adopt certain minor clarifications to the flexible permit program by November 30, 2014. Texas timely adopted the required minor clarifications and submitted the revised program to the EPA for approval. On December 31, 2014, the EPA issued a proposed rule converting the EPA’s previous conditional approval of Texas’ program to a full approval. We are presently assessing our Big Spring refinery’s air emissions permitting alternatives as a result of these developments.
In August 2012, the EPA sent letters to the petroleum refining industry regarding the EPA’s recently issued enforcement alert entitled EPA Enforcement Targets Flaring Efficiency Violations. The Enforcement Alert identified new standards that refiners are required to meet for combustion efficiency of their flares. The EPA has already commenced enforcement against several refining companies and we understand that other settlement negotiations are underway.
Remediation Efforts. We are currently remediating historical soil and groundwater contamination at our Big Spring refinery and terminals system. We spent $0.9 million in 2014 for remediation costs and we estimate an additional $1.7 million will be spent during 2015. We are also remediating historical soil and groundwater contamination at the Abilene, Southlake and Wichita Falls terminals that were in existence at the time they were acquired. As a result of the remediation efforts completed, we have submitted a request to TCEQ requesting closure of the wells at the Southlake terminal.
We are currently engaged in four separate remediation projects in the Los Angeles area. Two projects focus on clean-up efforts in and around the Paramount refinery and the Lakewood Tank Farm. Our Paramount subsidiary shares the cost of both these remediation projects with a prior owner of the Paramount refinery and Lakewood Tank Farm. We also have remediation projects at the Long Beach refinery and Pipeline 145 that existed at the time of our acquisitions. A total of $2.1 million was spent for all four remediation projects in 2014 of which our portion was $1.3 million. We estimate that an additional $2.5 million will be spent in 2015 with our portion being $1.7 million.
In conjunction with our acquisition of the Long Beach refinery in September 2006, we acquired a seven-year environmental insurance policy, which was renewed in 2013 for an additional three years. This policy provides us coverage for both known and unknown conditions existing at the refinery at the time of our acquisition for off-site, third party bodily injury and property damage claims. The policy limit on a per occurrence and aggregate basis is $15.0 million and has a per occurrence deductible of $0.5 million.
We are currently remediating historical soil and groundwater contamination at our Richmond Beach, Washington terminal. We spent $0.5 million in 2014 for remediation costs and we estimate an additional $0.6 million will be spent during 2015.
In conjunction with our acquisition of the Bakersfield refinery on June 1, 2010, we entered into an indemnification agreement with a prior owner for remediation expenses of conditions that existed at the Bakersfield refinery on the acquisition date. We are required to make indemnification claims to the prior owner by March 15, 2015. We spent $8.2 million in 2014 for these remediation costs, of which our portion was $0.7 million. We estimate that an additional $3.6 million will be spent during 2015, of which our portion will be $0.2 million. Additionally, the local Water Board has issued a draft Clean-up and Abatement Order, and additional capital expenditures associated with the Order expect to be completed in 2015.
In addition, a majority of our owned and leased convenience stores have underground gasoline and diesel fuel storage tanks. Compliance with federal and state regulations that govern these storage tanks can be costly. The operation of underground storage tanks also poses various risks, including soil and groundwater contamination. We are currently investigating and remediating leaks from underground storage tanks at some of our convenience stores, and it is possible that we may identify more leaks or contamination in the future that could result in fines or civil liability for us. We have established reserves in our financial statements in respect of these matters to the extent that the associated costs are both probable and reasonably estimable.


10


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 pursuant to which the refiner permits a distributor to use a trademark in connection with the sale or distribution of motor fuel. Under the PMPA, we may not terminate or fail to renew branded distributor contracts unless certain enumerated preconditions or grounds for termination or non-renewal are met and we also comply with the prescribed notice requirements.
Employees
As of December 31, 2014, we had approximately 2,745 employees. Approximately 625 employees worked in our refining and marketing segment, of which approximately 485 were employed at our refineries and approximately 140 were employed at our corporate offices in Dallas, Texas. Approximately 105 employees worked in our asphalt segment and approximately 2,015 employees worked in our retail segment.
Approximately 200 employees worked at our Big Spring refinery, approximately 135 of whom are covered by a collective bargaining agreement that expires on April 1, 2015. None of the employees in our asphalt segment, retail segment or in our corporate offices are represented by a union. We consider our relations with our employees to be satisfactory.
Properties and Insurance
Our principal properties are described above under the captions “Refining and Marketing,” “Asphalt” and “Retail” in 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, 2014, we were the lessee under a number of cancelable and non-cancelable leases for certain properties. Our leases are discussed more fully in Note 21 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities. Our property insurance policies that cover our refineries and asphalt assets have a $950 million limit. Claims for physical damage at our refineries and asphalt assets 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.
We maintain third party liability insurance policies that cover third party claims with a $300 million limit subject to a $5 million deductible. We are fully exposed to third party claims in excess of the applicable limit and sub-limits and a $5 million deductible.


11


Executive Officers of the Registrant
Our current executive officers and key employees (identified by an asterisk), their ages as of March 1, 2015, and their business experience during at least the past five years are set forth below.
Name
 
Age
 
Position
David Wiessman
 
60
 
Executive Chairman of the Board of Directors
Jeff D. Morris
 
63
 
Vice Chairman of the Board of Directors
Paul Eisman
 
59
 
Chief Executive Officer and President
Shai Even
 
46
 
Senior Vice President and Chief Financial Officer
Claire A. Hart
 
59
 
Senior Vice President
Alan Moret
 
60
 
Senior Vice President of Supply
Michael Oster
 
43
 
Senior Vice President of Mergers and Acquisitions
Jimmy C. Crosby
 
55
 
Senior Vice President of Refining
James Ranspot
 
44
 
Senior Vice President, General Counsel and Secretary
Scott Rowe
 
56
 
Senior Vice President of Asphalt Marketing
Jeff Brorman*
 
47
 
Vice President of Refining — Big Spring
Gregg Byers*
 
60
 
Vice President of Refining — Krotz Springs
Kyle McKeen*
 
51
 
President and Chief Executive Officer of Alon Brands
Josef Lipman*
 
69
 
President and Chief Executive Officer of SCS
Set forth below is a brief description of the business experience of each of the executive officers and key employees listed above.
David Wiessman has served as Executive Chairman of the Board of Directors of Alon since July 2000 and served as President and Chief Executive Officer of Alon from its formation in 2000 until May 2005. Mr. Wiessman has over 30 years of oil industry and marketing experience. Since 1994, Mr. Wiessman has served as a director of Alon Israel Oil Company, Ltd., or Alon Israel, Alon’s largest stockholder, and served as its Chief Executive Officer and President from 1994 to 2014. In 1987, Mr. Wiessman became Chief Executive Officer of, and a stockholder in, Bielsol Investments (1987) Ltd., or Bielsol, which acquired a 50% interest in Alon Israel in 1992. In 1976, after serving in the Israeli Air Force, he became Chief Executive Officer of Bielsol Ltd., a privately-owned Israeli company that owns and operates gasoline stations and owns real estate in Israel. Since August 2012, Mr. Wiessman has been Executive Chairman of the Board of Directors of the general partner of Alon USA Partners, LP, or Alon Partners, which is listed on the NYSE. Mr. Wiessman has also been Executive Chairman of the Board of Directors of Alon Holdings Blue Square-Israel, Ltd., which is listed on the NYSE and the Tel Aviv Stock Exchange, or TASE, since 2003; Chairman of Blue Square Real Estate Ltd., which is listed on the TASE, since 2006; and Executive Chairman of the Board and President of Dor-Alon Energy Israel (1988) Ltd., which is listed on the TASE, since 2005, and all of which are subsidiaries of Alon Israel. The Board has concluded that Mr. Wiessman’s vision, business expertise, industry experience, leadership skills and devotion to community service qualify him to serve as Executive Chairman of the Board.
Jeff D. Morris has served as Vice Chairman of the Board of Directors of Alon since May 2011 and a director since May 2005. Prior to this Mr. Morris served as our Chief Executive Officer from May 2005 to May 2011, our Chief Executive Officer of our operating subsidiaries from July 2000 to May 2011, our President from May 2005 until March 2010 and President of our operating subsidiaries from July 2000 until March 2010. Since August 2012, Mr. Morris has been Vice Chairman of the Board of the general partner of Alon Partners. Prior to joining Alon, he held various positions at Fina, Inc., where he began his career in 1974. Mr. Morris served as Vice President of Fina, Inc.’s SouthEastern Business Unit from 1998 to 2000 and as Vice President of its SouthWestern Business Unit from 1995 to 1998. In these capacities, he was responsible for both the Big Spring refinery and Fina’s Port Arthur refinery and the crude oil gathering assets and marketing activities for both business units. Mr. Morris has also been a director of Krotz Springs since 2008. The Board has concluded that Mr. Morris’ experience gained as Chief Executive Officer of Alon, detailed knowledge of Alon’s operations and assets, expertise in oil refining and marketing, devotion to community service and management skills qualify him to serve as a member of the Board.
Paul Eisman was appointed to serve as our Chief Executive Officer in May 2011 and our President in March 2010. Prior to joining Alon, Mr. Eisman was Executive Vice President, Refining & Marketing Operations at Frontier Oil Corporation from 2006 to 2009 and held various positions at KBC Advanced Technologies from 2003 to 2006, including Vice President of North American Operations. During 2002, Mr. Eisman was Senior Vice President of Planning for Valero Energy Corporation following Valero’s acquisition of Ultramar Diamond Shamrock. Prior to the acquisition, Mr. Eisman had a 24-year career with Ultramar Diamond Shamrock, serving in many technical and operational roles including Executive Vice President of Corporate Development and Senior Vice President of Refining.


12


Shai Even has served as a Senior Vice President since August 2008 and as our Chief Financial Officer since December 2004. Mr. Even served as a Vice President from May 2005 to August 2008 and Treasurer from August 2003 until March 2007. Prior to joining Alon, Mr. Even served as Chief Financial Officer of DCL Technologies, Ltd. from 1996 to July 2003 and prior to that worked for KPMG LLP from 1993 to 1996. Mr. Even has also been a director of Alon Refining Krotz Springs, Inc. since July 2008 and Alon Brands, Inc. since November 2008. Mr. Even was selected to serve as a director of the general partner of the Partnership because of his financial education and expertise, financial reporting background, public accounting experience, management experience and detailed knowledge of our operations. Mr. Even stepped down as a director of the general partner of the Partnership in November 2012.
Claire A. Hart has served as our Senior Vice President since January 2004 and served as our Chief Financial Officer and Vice President from August 2000 to January 2004. Prior to joining Alon, he held various positions in the Finance, Accounting and Operations departments of FINA for 13 years, serving as Treasurer from 1998 to August 2000 and as General Manager of Credit Operations from 1997 to 1998.
Alan Moret has served as our Senior Vice President of Supply since August 2008. Mr. Moret served as our Senior Vice President of Asphalt Operations from August 2006 to August 2008, with responsibility for asphalt operations and marketing at our refineries and asphalt terminals. Prior to joining Alon, Mr. Moret was President of Paramount Petroleum Corporation from November 2001 to August 2006. Prior to joining Paramount Petroleum Corporation, Mr. Moret held various positions with Atlantic Richfield Company, most recently as President of ARCO Crude Trading, Inc. from 1998 to 2000 and as President of ARCO Seaway Pipeline Company from 1997 to 1998.
Michael Oster has served as our Senior Vice President of Mergers and Acquisitions of Alon Energy since August 2008 and General Manager of Commercial Transactions of Alon Energy from January 2003 to August 2008. Prior to joining Alon Energy, Mr. Oster was a partner in the Israeli law firm, Yehuda Raveh and Co.
Jimmy C. Crosby has served as our Senior Vice President of Refining since November 2012. Mr. Crosby served as Vice President of Refining - Big Spring since January 2010, with responsibility for operation at the Big Spring Refinery. Prior to this Mr. Crosby served as Vice President of Refining - California Refineries from March 2009 until January 2010, as Vice President of Refining and Supply from May 2007 to March 2009, as Vice President of Supply and Planning from May 2005 to May 2007 and as General Manager of Business Development and Planning from August 2000 to May 2005. Prior to joining Alon, Mr. Crosby worked with FINA from 1996 to August 2000 where he last held the position of Manager of Planning and Economics for the Big Spring refinery.
James Ranspot has served as Senior Vice President, General Counsel and Secretary since March 2013. He served as Alon’s Chief Legal Counsel - Corporate from August 2010 until March 2013, and Assistant General Counsel from June 2006 to August 2010. Prior to joining Alon, Mr. Ranspot practiced corporate and securities law, with a focus on public and private merger and acquisition transactions and public securities offerings.
Scott Rowe has served as our Senior Vice President, Asphalt Marketing, since joining Alon in 2014. Mr. Rowe has over 30 years of experience in the petroleum refining and marketing business, with most of his experience specific to asphalt. Prior to joining Alon, Mr. Rowe was the President of The Hudson Companies, a privately held asphalt terminalling 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. 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


13


Carter Energy in 2005, Mr. McKeen was a member of the Board of Managers of Alon Brands, Inc. from September 2002 to 2005 and held numerous positions of increasing responsibilities with Alon Energy, including Vice President of Marketing.
Josef Lipman has served as President and Chief Executive Officer of Southwest Convenience Stores, LLC, or SCS, our subsidiary conducting our retail operations since July 2001. From 1997 to July 2001, Mr. Lipman served as General Manager of Cosmos, a chain of supermarkets in Israel owned by Super-Sol Ltd., where he was responsible for marketing and store operations.
ITEM 1A. RISK FACTORS.
The occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report on Form 10-K or in any other of our filings with the SEC could have a material adverse effect on our business, financial position, results of operations and cash flows. In evaluating an investment in any of our securities, you should consider carefully, among other things, the factors and the specific risks set forth below. This Annual Report on Form 10-K contains forward-looking statements that involve risks and uncertainties. See “Forward-Looking Statements” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of the factors that could cause actual results to differ materially from those projected.
The price volatility of crude oil, other feedstocks, refined products and fuel and utility services may have a material adverse effect on our earnings, profitability and cash flows.
Our refining and marketing earnings, profitability and cash flows from operations depend primarily on the margin between refined product prices and the prices for crude oil and other feedstocks. When the margin between refined product prices and crude oil and other feedstock prices contracts, as has been the case in recent periods and may be the case in the future, our results of operations and cash flows are negatively affected. Refining margins historically have been volatile, and are likely to continue to be volatile as a result of a variety of factors including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services. The direction and timing of changes in prices for crude oil and refined products do not necessarily correlate with one another and it is the relationship between such prices that has the greatest impact on our results of operations and cash flows.
Prices of crude oil, other feedstocks and refined products, and the relationships between such prices and prices for refined products, depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline, diesel, asphalt and other refined products and the relative magnitude and timing of such changes. Such supply and demand are affected by, among other things:
changes in general economic conditions;
changes in the underlying demand for our products;
the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;
worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa and Latin America;
the level of foreign and domestic production of crude oil and refined products and the volume of crude oil, feedstock and refined products imported in the United States;
refinery utilization rates;
infrastructure limitations;
the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to affect oil prices and maintain production controls;
the actions of customers and competitors;
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;


14


the impact of global economic conditions on our business; and
the development and marketing of alternative and competing fuels.
Although we continually analyze refinery operating margins at each of our refineries and seek to adjust throughput volumes and product slates to optimize our operating results based on market conditions, there are inherent limitations on our ability to offset the effects of adverse market conditions. For example, reductions in throughput volumes in a negative operating margin environment may reduce operating losses, but it would not eliminate them because we would still be incurring fixed costs and certain levels of variable costs.
The nature of our business has historically required us to maintain substantial quantities of crude oil and refined product inventories. Because crude oil and refined products are commodities, we have no control over the changing market value of these inventories. Our inventory is valued at the lower of cost or market value under the last-in, first-out (“LIFO”) inventory valuation methodology. As a result, if the market value of our inventory were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of sales. Our investment in inventory is affected by the general level of crude oil prices, and significant increases in crude oil prices could result in substantial working capital requirements to maintain inventory volumes. Changes in the value of our inventory or increases in the amount of our working capital necessary to maintain our inventory volumes could have a material adverse effect on our earnings, profitability and cash flows.
In addition, the volatility in costs of natural gas, electricity and other utility services used by our refineries and other operations affect our operating costs. Utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for utility services in both local and regional markets. Future increases in utility prices may have a negative effect on our earnings, profitability and cash flows.
Our profitability depends, in part, on the differential between the cost of crude oils processed by our refineries and those processed by our competitors. Changes in this differential could negatively affect our profitability.
We select grades of crude oil to process based, in part, on each individual refinery’s configuration and operating units. Our profitability is partially derived from our ability to purchase and process crude oil feedstocks that are less expensive than those processed by competing refiners. We quantify this differential in crude prices by comparing our crude acquisition price with benchmark crude oil grades such as West Texas Intermediate. Crude oil differentials can vary significantly depending on overall economic conditions, trends and conditions within the markets for crude oil and refined products, and infrastructure constraints. An adverse change in these differentials affecting one or more of our refineries could have a negative impact on our earnings.
Our indebtedness could adversely affect our financial condition or make us more vulnerable to adverse economic conditions.
Our level of indebtedness could have significant effects on our business, financial condition and results of operations and cash flows and, consequently, important consequences to your investment in our securities, such as:
we may be limited in our ability to obtain additional financing to fund our working capital needs, capital expenditures and debt service requirements or our other operational needs;
we may be limited in our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our debt;
we may be at a competitive disadvantage compared to competitors with less leverage since we may be less capable of responding to adverse economic and industry conditions; and
we may not have sufficient flexibility to react to adverse changes in the economy, our business or the industries in which we operate.
Our ability to service our indebtedness will depend on our ability to generate cash in the future.
Our ability to make payments on our indebtedness will depend on our ability to generate cash in the future. Our ability to generate cash is subject to general economic and market conditions and financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will generate sufficient cash to fund our working capital requirements, capital expenditure, debt service and other liquidity needs, which could result in our inability to comply with financial and other covenants contained in our debt agreements, our being unable to repay or pay interest on our indebtedness, and our inability to fund our other liquidity needs. If we are unable to service our debt obligations, fund our other liquidity needs and maintain compliance with our financial and other covenants, we could be forced to curtail our operations, our creditors could accelerate our indebtedness and exercise other remedies and we could be required to pursue one or more


15


alternative strategies, such as selling assets or refinancing or restructuring our indebtedness. However, we cannot assure you that any such alternatives would be feasible or prove adequate.
The dangers inherent in our operations could cause disruptions and could expose us to potentially significant losses, costs or liabilities.
Our operations are subject to significant hazards and risks inherent in refining operations and in transporting and storing crude oil, intermediate products and refined products. These hazards and risks include, but are not limited to, natural disasters, fires, explosions, pipeline ruptures and spills, waterborne transportation accidents, third-party interference and mechanical failure of equipment at our or third-party facilities, any of which could result in production and distribution difficulties and disruptions, environmental pollution, personal injury or wrongful death claims and other damage to our properties and the properties of others. The occurrence of such events at any of our refineries could significantly disrupt our production and distribution of refined products, and any sustained disruption could have a material adverse effect on our business, financial condition, 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.
If the price of crude oil increases significantly, it could reduce our margin on our fixed-price asphalt supply contracts.
We enter into fixed-price asphalt supply contracts pursuant to which we agree to deliver asphalt to customers at future dates. We set the pricing terms in these agreements based, in part, upon the price of crude oil at the time we enter into each contract. If the price of crude oil increases from the time we enter into the contract to the time we produce the asphalt, our margins from these sales could be adversely affected.
Our operating results are seasonal and generally lower in the first and fourth quarters of the year.
Demand for gasoline and asphalt products is generally higher during 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.
Changes in our credit profile could affect our relationships with our suppliers, which could have a material adverse effect on our liquidity and our ability to operate our refineries at full capacity.
Changes in our credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms for our purchases or require us to post security prior to payment. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our suppliers of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could cause us to be unable to operate our refinery at full capacity. A failure to operate our refinery at full capacity could adversely affect our profitability and cash flows. Alternatively, these more burdensome payment terms may require us to incur additional indebtedness under our revolving credit facility, which could increase our interest expense and adversely affect our cash flows.
Our 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 our largest supplier of crude oil and largest customer of refined products from our refineries. In the future, we could purchase up to 100% of our supply needs at each of our refineries from J. Aron pursuant to this agreement. Additionally, we are obligated to repurchase all consigned inventories and certain other inventories upon termination of this agreement, which may be terminated by J. Aron as early as May 31, 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


16


perform its obligations, which could consequently have a material adverse effect on our business, results of operations or liquidity. In addition, we may be required to use substantial capital to repurchase inventories from J. Aron upon termination of the agreements, which could have a material adverse effect on our financial condition.
Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.
We compete with a broad range of companies in our refining and marketing operations. Many of these competitors are integrated, multinational oil companies that are substantially larger than we are. Because of their diversity, integration of operations, larger capitalization, larger and more complex refineries and greater resources, these companies may be better able to withstand disruptions in operations and volatile market conditions, to offer more competitive pricing during times of intense price fluctuations and to obtain crude oil in times of shortage.
We are not engaged in the exploration and production business and therefore do not produce any of our crude oil or other feedstocks. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production. Competitors that have their own crude production are at times able to offset losses from refining operations with profits from oil producing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries, such as wind, solar and hydropower that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual customers. If we are unable to compete effectively with these competitors, both within and outside our industry, there could be a material adverse effect on our business, financial condition, results of operations and cash flows.
Competition in the asphalt industry is intense and an increase in competition in the markets in which we sell our asphalt products could adversely affect our earnings and profitability.
Our asphalt business competes with other refiners and with regional and national asphalt marketing companies. Many of these competitors are larger, more diverse companies with greater resources, providing them advantages in obtaining crude oil and other blendstocks and in competing through bidding processes for asphalt supply contracts.
We compete in large part on our ability to deliver specialized asphalt products which we produce under proprietary technology licenses. Recently, demand for these specialized products has increased due to new specification requirements by state and federal governments. If we were to lose our rights under our technology licenses, or if competing technologies for specialized products are developed by our competitors, our profitability could be adversely affected.
Competition in the retail industry is intense, and an increase in competition in the markets in which our retail businesses operate could adversely affect our earnings and profitability.
Our retail operations compete with numerous convenience stores, gasoline service stations, supermarket chains, drug stores, fast food operations and other retail outlets. Increasingly, national high-volume grocery and dry-goods retailers, such as Albertson’s and Wal-Mart are entering the gasoline retailing business. Many of these competitors are substantially larger than we are. Because of their diversity, integration of operations and greater resources, these companies may be better able to withstand volatile market conditions or levels of low or no profitability. In addition, these retailers may use promotional pricing or discounts, both at the pump and in the store, to encourage in-store merchandise sales. These activities by our competitors could adversely affect our profit margins. Additionally, our convenience stores could lose market share, relating to both gasoline and merchandise, to these and other retailers, which could adversely affect our business, results of operations and cash flows. Our convenience stores compete in large part based on their ability to offer convenience to customers. Consequently, changes in traffic patterns and the type, number and location of competing stores could result in the loss of customers and reduced sales and profitability at affected stores.
We may incur significant costs to comply with new or changing environmental laws and regulations.
Our operations are subject to extensive regulatory controls on air emissions, water discharges, waste management and the clean-up of contamination that can require costly compliance measures. If we fail to 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 (the “Initiative”). This Initiative is a coordinated, integrated compliance and enforcement strategy to address federal Clean Air Act compliance issues at the nation’s largest petroleum refineries, including compliance with New Source Review/Prevention of Significant Deterioration requirements, New Source Performance Standards, Leak Detection and Repair requirements, and National Emission Standards for Hazardous Air Pollutants for Benzene Waste Operations. According


17


to the EPA, as of January 2015, approximately 90% of the nation’s refining capacity is under lodged or entered “global” settlements. In February 2007, we committed in writing to enter into discussions with the EPA regarding our Big Spring refinery and, since that time, have held negotiations with the agency with respect to entering into a global settlement under the Initiative. Based on our on-going negotiations as well as consideration of prior settlements that the EPA has reached with other petroleum refineries under the Initiative, we believe that we would be required to pay a civil penalty, install air pollution controls, and enhance certain operations and maintenance programs in consideration for a broad release from liability. At this time, while we cannot estimate the cost of any such civil penalties, pollution controls or environmentally beneficial projects, the civil penalties will likely exceed $100,000, and the remaining costs could be significant and collectively could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In 2010, our Big Spring refinery was one of more than 100 facilities in Texas to receive a Clean Air Act request for information from the EPA relating to the EPA’s disapproval of Texas’ “flexible permit program.” According to the EPA, the Texas flexible permit program and its implementing rules were never approved by the EPA for inclusion in the Texas state clean-air implementation plan and, therefore, emission limitations in Texas flexible permits are not federally enforceable. The EPA indicated that it would consider enforcement against holders of flexible permits that failed to comply with applicable federal requirements on a case-by-case basis. We had agreed to convert the Big Spring refinery’s non-flexible permit to a federally enforceable non-flexible permit and submitted a permit application for that purpose, which remains pending. In August 2012, the U.S. Fifth Circuit Court of Appeals vacated the EPA’s final rule disapproving Texas’ flexible permit program and remanded the program back to the EPA for further consideration. Following the Fifth Circuit decision, Texas submitted a state clean-air implementation plan, including the flexible permit provisions, to the EPA for reconsideration in accordance with the Fifth Circuit’s decision. In July 2014, the EPA published its approval of Texas’ flexible permit program, conditioned on a commitment from Texas to adopt certain minor clarifications to the flexible permit program by November 30, 2014. Texas timely adopted the required minor clarifications and submitted the revised program to the EPA for approval. On December 31, 2014, the EPA issued a proposed rule converting the EPA’s previous conditional approval of Texas’ program to a full approval. We are presently assessing our Big Spring refinery’s air emissions permitting alternatives as a result of these developments.
In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, in March 2014, the EPA announced final new “Tier 3” motor vehicle emission and fuel standards. Under the final rule, gasoline must contain no more than 10 ppm sulfur on an annual average basis beginning as early as January 1, 2017; however, approved small volume refineries have until January 1, 2020 to meet the standard. We believe that the Big Spring, Krotz Springs, Paramount, and Bakersfield refineries each satisfy the definition of a small volume refinery, and we have applied to the EPA for status as small volume refineries for each of these facilities as is required by the Tier 3 regulations. We estimate that the capital investment associated with upgrades necessary to meet these new required sulfur levels will be less than $30 million. We are not able to predict the impact of other new or changed laws or regulations or changes in the ways that such laws or regulations are administered, interpreted or enforced but we may incur increased operating costs and capital expenditures to comply, which could be material. To the extent that the costs associated with meeting any of these requirements are substantial and not adequately provided for, our results of operations and cash flows could suffer.
Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and a reduced demand for our refining services.
In December 2009 the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act including rules that require a reduction in emissions of GHGs from motor vehicles and another rule that established GHG emissions thresholds that determine when certain stationary sources must obtain construction or operating permits under the Clean Air Act. In cases where a new source is constructed or an existing major source undergoes a major modification, facilities may be required to reduce those emissions according to “best available control technology” standards for GHGs. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis, for emissions occurring after January 1, 2010.
In addition, the federal Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and 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


18


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 $7.2 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 $37.4 million in investigation and remediation expenses in connection with our California refineries and terminals over the next 15 years. There can be no assurances, however, that we will not have to spend more than these anticipated amounts. Our handling and storage of petroleum and hazardous substances may lead to additional contamination at our facilities and facilities to which we send or sent wastes or by-products for treatment or disposal, in which case we may be subject to additional cleanup costs, governmental penalties, and third-party suits alleging personal injury and property damage. Joint and several strict liability may be incurred in connection with such releases of petroleum hydrocarbons, hazardous substances and/or wastes. Although we have sold two of our pipelines pursuant to a transaction with Sunoco, we have agreed, subject to certain limitations, to indemnify Sunoco for costs and liabilities that may be incurred by Sunoco as a result of environmental conditions existing at the time of the sale. If we are forced to incur costs or pay liabilities in connection with such releases and contamination or any associated third-party proceedings and investigations, or in connection with any of our indemnification obligations to Sunoco, such costs and payments could be significant and could adversely affect our business, results of operations and cash flows.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with worker health and safety, environmental and other laws and regulations.
From time to time, we have been sued or investigated for alleged violations of worker health and safety, environmental and other laws. If a lawsuit or enforcement proceeding were commenced or resolved against us, we could incur significant costs and liabilities. In addition, our operations require numerous permits and authorizations under environmental and various other laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or worker health and safety. A violation of authorization or permit conditions or of other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have an adverse effect on our business, results of operations or cash flows.
Renewable fuels mandates may reduce demand for the petroleum fuels we produce, which could have a material adverse effect on our results of operations and financial condition.
The EPA has issued RFS mandates, requiring refiners such as us to blend renewable fuels into the petroleum fuels they produce and sell in the United States. To the extent refiners will not or cannot blend renewable fuels in the products they produce in the quantities required to satisfy their obligations under the RFS program, those refiners must purchase RINs to maintain compliance. Under the RFS program, the volume of renewable fuels that obligated parties are required to blend into their finished petroleum fuels increases annually over time until 2022. As a result of receiving hardship relief made available to obligated parties meeting certain criteria, our Big Spring refinery first became subject to the RFS program in 2013 and the Krotz Springs refinery first became subject to the program in 2014. RINs costs for the Big Spring refinery were $6.7 million and $14.9 million for 2014 and 2013, respectively. RINs costs for the Krotz Springs refinery were $21.4 million for 2014, although we are still considering whether to seek hardship relief from the EPA for 2014. The Big Spring refinery through its wholesale sales is able to blend finished products with renewable fuels, thus generating RINs. Conversely, the Krotz Springs refinery sells substantially all of its finished products which are subject to the RFS program, via the Colonial pipeline, which does not allow us to blend products; and therefore must purchase RINs to satisfy its obligation. The EPA has published the proposed volume mandates for 2014, which are generally lower than the volumes for 2013 and lower than the statutory mandates. The EPA submitted a draft final rule for regulatory review by the federal Office of Management and Budget on August 21, 2014. In January 2015, the EPA announced that its goal was to release the final 2014 RFS volume mandates in the Spring of 2015. The price of RINs has been extremely volatile and has increased over the last year. We cannot currently predict the future prices of RINs and, thus, the expenses related to RINs compliance have the potential to be material. Existing laws


19


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, which could have an adverse effect on our business, results of operations or cash flows.
We could encounter significant opposition to operations at our California refineries.
Our Paramount refinery is located in a residential area. The refinery is located near schools, apartment complexes, private homes and shopping establishments. In addition, our Long Beach refinery is located in close proximity to other commercial facilities, and our Bakersfield refinery is adjacent to newly developed commercial and retail property. Any loss of community support for our California refining operations could result in higher than expected expenses in connection with opposing any community action to restrict or terminate the operation of the refinery. Any community action in opposition to our current and planned use of the California refineries could have a material adverse effect on our business, results of operations and cash flows.
The occurrence of a release of hazardous materials or a catastrophic event affecting our California refineries could endanger persons living nearby.
Because our California refineries are located in residential areas, any release of hazardous material or catastrophic event could cause injuries to persons outside the confines of these refineries. In the event that persons were injured as a result of such an event, we would likely incur substantial legal costs as well as any costs resulting from settlements or adjudication of claims from such injured persons. The extent of these expenses and costs could be in excess of the limits provided by our insurance policies. As a result, any such event could have a material adverse effect on our business, results of operations and cash flows.
Certain of our facilities are located in areas that have a history of earthquakes or hurricanes, the occurrence of which could materially impact our operations.
Our refineries located in California and the related pipeline and asphalt terminals 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.
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.


20


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 insurance policies that cover our refineries and asphalt assets have a $950 million limit. Claims for physical damage at our refineries and asphalt assets 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.
We maintain third party liability insurance policies that cover third party claims with a $300 million limit subject to a $5 million deductible. We are fully exposed to third party claims in excess of the applicable limit and sub-limits and a $5 million deductible.
Additionally, we could suffer losses for uninsurable or uninsured risks or insurable events in amounts in excess of our existing insurance coverage or which are not covered by that insurance. 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.
If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively affected.
Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel. We do not currently maintain key man life insurance with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel would be unavailable to us for any reason, we would be required to hire other personnel to manage and operate our company and to develop our products and technology. We cannot assure you that we would be able to locate or employ such qualified personnel on acceptable terms or at all.
A substantial portion of our Big Spring refinery’s workforce is unionized, and we may face labor disruptions that would interfere with our operations.
As of December 31, 2014, we employed approximately 200 people at our Big Spring refinery, approximately 135 of whom were covered by a collective bargaining agreement. The collective bargaining agreement expires on April 1, 2015. Our current labor agreement may not prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse effect on our results of operation and financial condition.
We conduct our convenience store business under a license agreement with 7-Eleven, and the loss of this license could adversely affect the results of operations of our retail segment.
Our convenience store operations are primarily conducted under the 7-Eleven name pursuant to a license agreement between 7-Eleven, Inc. and us. 7-Eleven may terminate the agreement if we default on our obligations under the agreement. This termination would result in our convenience stores losing the use of the 7-Eleven brand name, the accompanying 7-Eleven advertising and certain other brand names and products used exclusively by 7-Eleven. Termination of the license agreement could have a material adverse effect on our retail operations.
We 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. Two of our current and former executive officers, Messrs. Morris and Hart, are parties to stockholders’ agreements with Alon Assets and us, pursuant to which we may elect or be required to purchase their shares in connection with put/call rights or rights of first refusal contained in those agreements. The purchase price for the shares is generally determined pursuant to certain formulas set forth in the stockholders’ agreements, the purchase price under certain circumstances involving a termination of, or resignation from, employment would be the fair market value of the shares. For additional information, see Item 12 “Security Ownership of Certain Beneficial Holders and Management and


21


Related Stockholder Matters.” Additionally, we own 81.6% of the Partnership’s common units and 100% of Alon USA Partners GP, LLC, the general partner of the Partnership. To the extent the Partnership is unable to make distributions to its partners, we may be unable to pay any dividends.
The wholesale fuel distribution industry is characterized by intense competition and fragmentation and our failure to effectively compete could adversely affect our business and results of operations.
The market for distribution of wholesale motor fuel is highly competitive and fragmented. We have numerous competitors, some of which have significantly greater resources and name recognition than us. We rely on our ability to provide reliable supply and value-added services and to control our operating costs in order to maintain our margins and competitive position. If we were to fail to maintain the quality of our services, customers could choose alternative distribution sources and our competitive position could be adversely affected. Furthermore, we compete against major oil companies with integrated marketing businesses. Through their greater resources and access to crude oil, these companies may be better able to compete on the basis of price or offer lower wholesale and retail pricing which could negatively affect our fuel margins. The occurrence of any of these events could have a material adverse effect on our business and results of operations.
Commodity derivative contracts may limit our potential gains, exacerbate potential losses, result in period-to-period earnings volatility and involve other risks.
We may enter into commodity derivatives contracts 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.”
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


22


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.
It may be difficult to serve process on or enforce a United States judgment against certain of our directors.
All of our directors, other than Messrs. Ron Haddock and Jeff Morris, reside in Israel. In addition, a substantial portion of the assets of these directors are located outside of the United States. As a result, you may have difficulty serving legal process within the United States upon any of these persons. You may also have difficulty enforcing, both in and outside the United States, judgments you may obtain in United States courts against these persons in any action, including actions based upon the civil liability provisions of United States federal or state securities laws. Furthermore, there is substantial doubt that the courts of the State of Israel would enter judgments in original actions brought in those courts predicated on United States federal or state securities laws.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 3. LEGAL PROCEEDINGS.
In the ordinary conduct of our business, we are subject to periodic lawsuits, investigations and claims, including environmental claims and employee related matters. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, results of operations, cash flows or financial condition.
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 currently is not scheduled for trial. Due to the uncertainties of litigation, we cannot predict with certainty the ultimate resolution of this lawsuit.
ITEM 4. MINE SAFTETY DISCLOSURES
None.


23


PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Market Information
Our common stock is traded on the New York Stock Exchange under the symbol “ALJ.”
The following table sets forth the quarterly high and low sales prices of and dividends declared on our common stock for each quarterly period within the two most recently completed fiscal years:
 
 
Sales Prices of our Common Stock
 
Dividends per Common Share
Quarterly Period
 
High
 
Low
 
 
 
 
 
 
 
 
2014
 
 
 
 
 
 
Fourth Quarter (1)
 
$
17.17

 
$
11.64

 
$
0.31

Third Quarter (2)
 
17.31

 
12.08

 
0.10

Second Quarter
 
17.58

 
12.43

 
0.06

First Quarter
 
17.04

 
12.92

 
0.06

2013
 
 
 
 
 
 
Fourth Quarter
 
$
16.64

 
$
8.55

 
$
0.06

Third Quarter
 
14.70

 
10.12

 
0.06

Second Quarter (1) (3)
 
19.05

 
14.35

 
0.22

First Quarter
 
21.24

 
17.10

 
0.04

_______________________
(1)
Dividends declared on our common stock during the fourth quarter of 2014 and the second quarter of 2013 include special non-recurring dividends of $0.21 per common share and $0.16 per common share, respectively.
(2)
Beginning in the third quarter of 2014, our board of directors increased the regular quarterly cash dividend from $0.06 per common share to $0.10 per common share.
(3)
Beginning in the second quarter of 2013, our board of directors increased the regular quarterly cash dividend from $0.04 per common share to $0.06 per common share.
On February 5, 2015, our board of directors approved the regular quarterly cash dividend of $0.10 per share on our common stock, payable on March 16, 2015, to holders of record at the close of business on February 26, 2015.
We intend to continue to pay quarterly cash dividends on our common stock at an annual rate of $0.40 per share. However, the declaration and payment of future dividends to holders of our common stock will be at the discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, legal requirements, restrictions in our debt agreements, the terms of our preferred stock and other factors our board of directors deems relevant.
Holders
As of March 1, 2015, there were 42 common stockholders of record.
Recent Sales of Unregistered Securities
In June 2012, Alon entered into amendments to shareholder agreements among Alon, Jeff Morris and Claire Hart, two of our current executives, and two of our subsidiaries Alon Assets, Inc. (“Alon Assets”) and Alon Operating, Inc. (“Alon Operating”), pursuant to which the non-voting shares of Alon Assets and Alon Operating held by Messrs. Morris and Hart could be exchanged for shares of our common stock in quarterly installments over periods of five and three years, respectively. In November 2012, Alon Assets and Alon Operating were merged, with Alon Assets being the surviving entity.


24


The following issuances of shares of our common stock occurred during the December 31, 2014 fiscal year pursuant to the agreements described above:
 
 
Exchange Date
 
Number of Shares Issued
Jeff D. Morris
 
January 11, 2014
 
116,347

 
 
April 12, 2014
 
116,347

 
 
July 11, 2014
 
116,347

 
 
October 11, 2014
 
116,347

 
 
 
 
 
Claire A. Hart
 
January 11, 2014
 
48,475

 
 
April 12, 2014
 
48,475

 
 
July 11, 2014
 
48,475

 
 
October 11, 2014
 
48,475

The issuances of the shares of common stock to Messrs. Morris and Hart reflected above were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
None.


25


Stockholder Return Performance Graph
The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, each as amended, except to the extent we specifically incorporate it by reference into such filing.
The following performance graph compares the cumulative total stockholder return on Alon common stock as traded on the NYSE with the Standard & Poor’s 500 Stock Index (the “S&P 500”) and our peer group as selected by management for the cumulative five-year period from December 31, 2009 to December 31, 2014, 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.
 
12/2009
 
12/2010
 
12/2011
 
12/2012
 
12/2013
 
12/2014
Alon
$
100.00

 
$
89.67

 
$
132.71

 
$
279.70

 
$
261.75

 
$
207.92

S&P 500
100.00

 
115.06

 
117.49

 
136.30

 
180.44

 
205.14

Peer Group
100.00

 
146.63

 
149.85

 
287.77

 
410.56

 
410.39



26


ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth selected historical consolidated financial data as of and for each of the five years in the period ending December 31, 2014. The selected historical consolidated statement of operations data for the years ended December 31, 2014, 2013 and 2012, and the selected consolidated balance sheet data as of December 31, 2014 and 2013, 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, 2011 and 2010, and the selected consolidated balance sheet data as of December 31, 2012, 2011 and 2010, 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,
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
 
(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
 
 
 
 
 
Net sales
 
$
6,779,456

 
$
7,046,381

 
$
8,017,741

 
$
7,186,257

 
$
4,030,743

Operating income (loss)
 
201,572

 
149,433

 
269,475

 
181,521

 
(160,781
)
Net income (loss) available to stockholders
 
38,457

 
22,986

 
79,134

 
42,507

 
(122,932
)
Earnings (loss) per share, basic
 
$
0.56

 
$
0.33

 
$
1.29

 
$
0.77

 
$
(2.27
)
Weighted average shares outstanding, basic
 
68,985

 
63,538

 
57,501

 
55,431

 
54,186

Earnings (loss) per share, diluted
 
$
0.55

 
$
0.32

 
$
1.24

 
$
0.69

 
$
(2.27
)
Weighted average shares outstanding, diluted
 
69,373

 
64,852

 
63,917

 
61,401

 
54,186

Cash dividends per common share
 
$
0.53

 
$
0.38

 
$
0.16

 
$
0.16

 
$
0.16

 
 
 
 
 
 
 
 
 
 
 
BALANCE SHEET DATA:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
214,961

 
$
224,499

 
$
116,296

 
$
157,066

 
$
71,687

Working capital
 
126,665

 
60,863

 
87,242

 
99,452

 
990

Total assets
 
2,200,874

 
2,245,140

 
2,223,574

 
2,330,382

 
2,088,521

Total debt
 
563,687

 
612,248

 
587,017

 
1,050,196

 
916,305

Total debt less cash and cash equivalents
 
348,726

 
387,749

 
470,721

 
893,130

 
844,618

Total equity
 
673,778

 
625,404

 
621,186

 
395,784

 
341,767




27


ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The following discussion of our financial condition and results of operations is provided as a supplement to, and should be read in conjunction with, our consolidated financial statements and the notes thereto included elsewhere in this Annual Report on Form 10-K and the other sections of this Annual Report on Form 10-K, including Items 1 and 2 “Business and Properties,” and Item 6 “Selected Financial Data.”
Forward-Looking Statements
Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.
Forward-looking statements reflect our current expectations of future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows. See Item 1A “Risk Factors.”
Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:
changes in general economic conditions and capital markets;
changes in the underlying demand for our products;
the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;
changes in the spread between West Texas Intermediate (“WTI”) Cushing crude oil and West Texas Sour (“WTS”) crude oil or WTI Midland crude oil;
changes in the spread between WTI Cushing crude oil and Light Louisiana Sweet (“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 our refineries and most of our asphalt terminals, under which J. Aron is our largest supplier of crude oil and our largest customer of refined products. Additionally, upon termination of the Supply and Offtake Agreements, we are obligated to purchase the crude oil and refined products 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 renewable fuel standards program (“RFS”), including the availability, cost and price volatility of renewable identification numbers (“RINs”);
the effects and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;
operating hazards, accidents, fires, severe weather, floods and other natural disasters, casualty losses and other matters beyond our control, which could result in unscheduled downtime;
the effects of seasonality on demand for our products;


28


the level of competition from other petroleum refiners;
the easing of logistical and infrastructure constraints at Cushing;
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. Our crude oil refineries are located in Texas, Louisiana and California and have a combined crude oil throughput capacity of approximately 217,000 barrels per day (“bpd”). We are a leading marketer of asphalt, which we distribute primarily through asphalt terminals located predominately in the Southwest and Western United States. We are the largest 7-Eleven licensee in the United States and operate 295 convenience stores in Central and West Texas and New Mexico.
Refining and Marketing Segment. Our refining and marketing segment includes a sour crude oil refinery located in Big Spring, Texas, a light sweet crude oil refinery located in Krotz Springs, Louisiana and heavy crude oil refineries located in Paramount, Bakersfield and Long Beach, California (“California refineries”). Our refineries have a combined crude oil throughput capacity of approximately 217,000 bpd. We refine crude oil into petroleum products, including various grades of gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum-based products, which are marketed primarily in the South Central, Southwestern and Western United States. Our California refineries did not process crude oil in 2014 and 2013 due to the high cost of crude oil relative to product yield and low asphalt demand.
We own the Big Spring refinery and wholesale marketing operations through Alon USA Partners, LP (the “Partnership”). Our marketing of transportation fuels produced at the Big Spring refinery is focused on West and Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in these regions as our “physically integrated system” because our distributors in this region are supplied primarily with motor fuels produced at our Big Spring refinery and distributed through a network of pipelines and terminals which we either own or have access to through leases or long-term throughput agreements.
We supply gasoline and diesel to 644 Alon branded retail sites, including our retail segment convenience stores. In 2014, approximately 58% of the gasoline and 29% of the diesel produced at the Big Spring refinery was transferred to our branded marketing business at prices substantially determined by wholesale market prices. Additionally, we license the use of the Alon brand name and provide credit card processing services to 73 licensed locations that are not under fuel supply agreements.
We market transportation fuel production from our Krotz Springs refinery through bulk sales and exchange channels. These bulk sales and exchange arrangements are entered into with various oil companies and traders and are transported to markets on the Mississippi River and the Atchafalaya River as well as to the Colonial Pipeline.
Asphalt Segment. We own or operate 10 asphalt terminals located in Texas (Big Spring), Washington (Richmond Beach), California (Paramount, Long Beach, Elk Grove, Mojave and Bakersfield), Arizona (Phoenix and Flagstaff) and Nevada (Fernley) (50% interest), and a 50% interest in Wright Asphalt Products Company, LLC (“Wright”), which specializes in patented ground tire rubber modified asphalt products. The operations in which we have a 50% interest are recorded under the equity method of accounting and the investments are included as part of total assets in the asphalt segment data.
We purchase non-blended asphalt from third parties in addition to non-blended asphalt produced at the Big Spring refinery. We market asphalt through our terminals as blended and non-blended asphalt. We have an exclusive license to use advanced asphalt-blending technology in West Texas, Arizona, New Mexico and Colorado, and a non-exclusive license in Idaho, Montana, Nevada, North Dakota, Utah and Wyoming, with respect to asphalt produced at our Big Spring refinery, and a ground tire rubber (“GTR”) asphalt manufacturing process with respect to asphalt sold in California.
Asphalt produced by our Big Spring refinery is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude, which is intended to approximate wholesale market prices. We market asphalt primarily as paving asphalt to road and materials manufacturers and highway construction/maintenance contractors as GTR, polymer modified or emulsion asphalt. Sales of asphalt are seasonal with the majority of our sales occurring between May and October.


29


Retail Segment.
Our convenience stores typically offer various grades of gasoline, diesel fuel, food products, food service, tobacco products, non-alcoholic and alcoholic beverages, general merchandise as well as money orders to the public, primarily under the 7-Eleven and Alon brand names. Substantially all of the motor fuel sold through our retail segment is supplied by our Big Spring refinery.
For additional information on each of our operating segments, see Items 1. and 2. “Business and Properties.”
Summary of 2014 Developments
We paid cash dividends on common stock totaling $0.53 per share, which included a special non-recurring dividend of $0.21 per share paid in December. We also increased our regular quarterly cash dividend from $0.06 per share to $0.10 per share during the third quarter.
We completed the major turnaround at the Big Spring refinery, including the vacuum tower revamp project, which increased crude oil throughput to 73,000 bpd from 70,000 bpd and increased diesel production by 3,000 bpd.
We have reduced WTS crude and increased Midland priced WTI crude received at the Big Spring refinery, averaging throughput of 32,429 bpd of WTI for the full year 2014, a 56.6% increase from 2013.
We repaid the outstanding balance on the 13.50% Alon Refining Krotz Springs senior secured notes.
We entered into a five-year Term Loan Agreement for a principal amount of $25.0 million, maturing in March 2019. Additionally, Alon Retail entered into a new credit agreement that includes a $110.0 million term loan and a $10.0 million revolving credit loan, which will mature in March 2019.
We completed the sale of our Willbridge, Oregon facility for $40.0 million.
We received a permit to construct a 140,000 bpd rail unloading facility and make modifications to process light crude oil at our Bakersfield refinery.
We are planning to create a new logistics master limited partnership utilizing assets that we currently operate.
2014 Operational and Financial Highlights
Operating income for 2014 was $201.6 million, compared to $149.4 million in 2013. Our operational and financial highlights for 2014 include the following:
Combined refinery average throughput for 2014 was 136,378 bpd, compared to a combined refinery average throughput of 131,808 bpd in 2013.
During the second quarter of 2014, we completed a major turnaround at the Big Spring refinery, including the vacuum tower revamp project, which increased crude oil throughput to 73,000 bpd from 70,000 bpd and increased diesel production by 3,000 bpd. However, despite the reduced throughput experienced during the second quarter of 39,000 bpd, our Big Spring refinery average throughput was 66,033 bpd for 2014 compared to 67,103 bpd for 2013.
The Krotz Springs refinery average throughput for 2014 was 70,345 bpd compared to 64,705 bpd for 2013. Refinery throughput at the Krotz Springs refinery was lower for 2013 due to the unplanned shut down and repair of the reformer unit for approximately one month.
Refinery operating margin at the Big Spring refinery was $16.69 per barrel in 2014, compared to $14.59 per barrel in 2013. This increase was primarily due to a widening of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread, partially offset by a lower Gulf Coast 3/2/1 crack spread.
Refinery operating margin at the Krotz Springs refinery was $7.57 per barrel in 2014 compared to $6.16 per barrel for 2013. This increase was primarily due to a higher Gulf Coast 2/1/1 high sulfur diesel crack spread and a widening WTI Cushing to WTI Midland spread, partially offset by a narrowing LLS to WTI Cushing spread. In 2014, the Krotz Springs refinery operating margin was negatively impacted by RINs costs of $21.4 million, or $0.83 per barrel of throughput. The Krotz Springs refinery received an exemption from the RFS requirements for 2013 and as a result did not record costs associated with RINs.
The average WTI Cushing to WTS spread for 2014 was $6.04 per barrel compared to $3.72 per barrel for 2013. The average WTI Cushing to WTI Midland spread for 2014 was $6.93 per barrel compared to $2.59 per barrel for 2013. The average LLS to WTI Cushing spread for 2014 was $3.85 per barrel compared to $11.06 per barrel for 2013.


30


The average Gulf Coast 3/2/1 crack spread was $14.52 per barrel for 2014 compared to $19.16 per barrel for 2013, which was primarily influenced by a decrease in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for 2014 was $7.30 per barrel compared to $12.41 per barrel for 2013.
The average Gulf Coast 2/1/1 high sulfur diesel crack spread for 2014 was $9.76 per barrel compared to $7.89 per barrel for 2013, which was primarily influenced by an increase in the Brent to LLS spread. The average Brent to LLS spread for 2014 was $3.45 per barrel compared to $1.35 per barrel for 2013.
Asphalt margins in 2014 were $43.86 per ton compared to $68.67 per ton in 2013. This decrease was primarily due to higher costs of purchased asphalt during 2014.
Retail fuel sales volume increased by 2.2% to 192.6 million gallons in 2014 from 188.5 million gallons in 2013.
Major Influences on Results of Operations
Refining and Marketing. Earnings and cash flow from our refining and marketing segment are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. These prices depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, not necessarily fluctuations in those prices, that affect our earnings.
In order to measure our operating performance, we compare our per barrel refinery operating margins to certain industry benchmarks. We calculate this margin for each refinery by dividing the refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales (exclusive of substantial hedge positions). 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 priced crude oil.
The Krotz Springs refinery has the capability to process substantial volumes of low-sulfur, or sweet, crude oils to produce a high percentage of light, high-value refined products. Sweet crude oil typically comprises 100% of the Krotz Springs refinery’s crude oil input. This input is primarily comprised of LLS crude oil and WTI Midland priced crude oil.
In addition, we have been able to capitalize on the oversupply of West Texas crudes in Midland, the largest origination terminal for West Texas crude oil, resulting from increased production in the Permian Basin coupled with infrastructure constraints. Although West Texas crudes are typically transported to Cushing and to the Gulf Coast for sale, current logistical and infrastructure constraints are limiting the ability of Permian Basin producers to transport their production to Cushing and to the Gulf Coast. The resulting oversupply of West Texas crudes at Midland has depressed Midland crude prices and enabled us to obtain an increased portion of our crude supply at discounted prices to Cushing. Moreover, by sourcing West Texas crudes at Midland, we are able to eliminate the cost of transporting crude to and from Cushing. The WTI Cushing less WTI Midland spread represents the differential between the average per barrel price of WTI Cushing crude oil and the average per barrel price of WTI Midland crude oil. A widening of the WTI Cushing less WTI Midland spread can favorably influence the operating margin for both our Big Spring and Krotz Springs refineries. An easing of the current logistical and infrastructure constraints through new pipeline construction or expansion could have an adverse effect on our 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 can favorably influence both the Big Spring and Krotz Springs refineries’ operating margins. Also, the


31


Krotz Springs refinery is influenced by the spread between Brent crude and LLS. The Brent less LLS spread represents the differential between the average per barrel price of Brent crude oil and the average per barrel price of LLS crude oil. A widening of the spread between Brent and LLS can favorably influence the Krotz Springs refinery operating margins.
The results of operations from our refining and marketing segment are also significantly affected by our refineries’ operating costs, particularly the cost of natural gas used for fuel and the cost of electricity. Natural gas prices have historically been volatile. Typically, electricity prices fluctuate with natural gas prices.
Demand for gasoline products is generally higher during summer months than during winter months due to seasonal increases in highway traffic. As a result, the operating results for our refining and marketing segment for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters. The effects of seasonal demand for gasoline are partially offset by seasonality in demand for diesel, which in our region is generally higher in winter months as east-west trucking traffic moves south to avoid winter conditions on northern routes.
Safety, reliability and the environmental performance of our refineries are critical to our financial performance. The financial impact of planned downtime, such as a turnaround or major maintenance project, is mitigated through a diligent planning process that considers expectations for product availability, margin environment and the availability of resources to perform the required maintenance.
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 LIFO inventory valuation methodology, price fluctuations generally have little effect on our financial results.
Asphalt. Earnings from our asphalt segment depend primarily upon the margin between the price at which we sell our asphalt and the 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 (“cpg”) basis. Our retail fuel margins are driven by local supply, demand and competitor pricing. Our retail sales are seasonal and peak in the second and third quarters of the year, while the first and fourth quarters usually experience lower overall sales.
Factors Affecting Comparability
Our financial condition and operating results over the three-year period ended December 31, 2014 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, 2014, as part of our planned turnaround at the Big Spring refinery, we revamped the refinery’s vacuum tower, which increased crude oil throughput to 73,000 bpd from 70,000 bpd and increased diesel production by 3,000 bpd. This planned downtime at our Big Spring refinery resulted in reduced refinery throughput during the period.
During the year ended December 31, 2013, the Krotz Springs refinery was impacted by the unplanned shut down and repair of the reformer unit for approximately one month.
During the years ended December 31, 2014 and 2013, we did not process crude oil at our California refineries and therefore, no throughput data has been presented for the years ended December 31, 2014 and 2013. The throughput data for the California refineries for the year ended December 31, 2012 reflects approximately eight months of throughput data as the California refineries did not process crude oil during the first quarter of 2012 or December 2012.


32


Certain Derivative Impacts
Included in cost of sales for the years ended December 31, 2014, 2013 and 2012 are gains (losses) on commodity swaps of $4.7 million, $23.9 million and ($130.1) million, respectively.
Included in other income (loss), net for the year ended December 31, 2012 are losses on heating oil call option crack spread contracts of $7.3 million.
Renewable Fuel Standards
Included in costs of sales for the years ended December 31, 2014 and 2013 are RINs costs of $27.1 million and $14.9 million, respectively. The Big Spring and Krotz Springs refineries first became subject to the RFS program in 2013, and the Krotz Springs refinery received a hardship exemption for 2013, and as a result did not record costs associated with RINs.
Debt Related Transactions
During 2014, we repaid the outstanding balance on the 13.50% Alon Refining Krotz Springs senior secured notes.
Interest expense for the year ended December 31, 2013 includes a charge of $8.5 million for a prepayment premium and write-offs of unamortized original issuance discount and debt issuance costs recognized for prepayment of a portion of the Alon Refining Krotz Springs senior secured notes.
Interest expense for the year ended December 31, 2012 includes a charge of $9.6 million for the write-off of unamortized original issuance discount associated with the repayment of the Alon Brands Term Loan and charges of $27.6 million for the write-offs of unamortized original issuance discount and debt issuance costs associated with the repayment of the Alon USA Energy, Inc. term loan credit facilities.


33


Results of Operations
The period-to-period comparisons of our results of operations have been prepared using the historical periods included in our consolidated financial statements. We refer to our financial statement line items in the explanation of our period-to-period changes in results of operations. Below are general definitions of what those line items include and represent.
Net Sales. Net sales consist primarily of sales of refined petroleum products through our refining and marketing segment and asphalt segment and sales of merchandise, food products and motor fuels through our retail segment.
For the refining and marketing segment, net sales consist of gross sales, net of customer rebates, discounts and excise taxes and include intersegment sales to our asphalt and retail segments, which are eliminated through consolidation of our financial statements. Asphalt sales consist of gross sales, net of any discounts and applicable taxes. For our petroleum and asphalt products, net sales are mainly affected by crude oil and refined product prices and volume changes caused by operations. Retail net sales consist of gross merchandise sales, less rebates, commissions and discounts, and gross fuel sales, including excise taxes. Our retail merchandise sales are affected primarily by competition and seasonal influences.
Cost of Sales. Refining and marketing cost of sales includes principally crude oil, blending materials, other raw materials and transportation costs, which include cost associated with our crude oil and product pipelines. Asphalt cost of sales includes costs of purchased asphalt, blending materials and transportation costs. Retail cost of sales includes costs of 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 marketing expenses are also included in SG&A expenses for the refining and marketing and asphalt segments.


34


ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED
Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for us and our three operating segments for years ended December 31, 2014, 2013 and 2012. 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,
 
2014
 
2013
 
2012
 
(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
Net sales (1)
$
6,779,456

 
$
7,046,381

 
$
8,017,741

Operating costs and expenses:
 
 
 
 
 
Cost of sales
6,002,270

 
6,325,088

 
7,149,385

Direct operating expenses
281,686

 
287,752

 
313,242

Selling, general and administrative expenses (2)
170,139

 
168,172

 
161,401

Depreciation and amortization (3)
124,063

 
125,494

 
121,929

Total operating costs and expenses
6,578,158

 
6,906,506

 
7,745,957

Gain (loss) on disposition of assets
274

 
9,558

 
(2,309
)
Operating income
201,572

 
149,433

 
269,475

Interest expense (4)
(111,143
)
 
(94,694
)
 
(129,572
)
Equity earnings of investees
1,678

 
5,309

 
7,162

Other income (loss), net (5)
674

 
218

 
(6,584
)
Income before income tax expense
92,781

 
60,266

 
140,481

Income tax expense
22,913

 
12,151

 
49,884

Net income
69,868

 
48,115

 
90,597

Net income attributable to non-controlling interest
31,411

 
25,129

 
11,463

Net income available to stockholders
$
38,457

 
$
22,986

 
$
79,134

Earnings per share, basic
$
0.56

 
$
0.33

 
$
1.29

Weighted average shares outstanding, basic (in thousands)
68,985

 
63,538

 
57,501

Earnings per share, diluted
$
0.55

 
$
0.32

 
$
1.24

Weighted average shares outstanding, diluted (in thousands)
69,373

 
64,852

 
63,917

Cash dividends per share
$
0.53

 
$
0.38

 
$
0.16

CASH FLOW DATA:
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
193,658

 
$
162,233

 
$
387,810

Investing activities
(108,995
)
 
(51,441
)
 
(104,980
)
Financing activities
(94,201
)
 
(2,589
)
 
(323,600
)
OTHER DATA:
 
 
 
 
 
Adjusted EBITDA (6)
$
327,713

 
$
270,896

 
$
394,291

Capital expenditures (7)
88,429

 
68,513

 
93,901

Capital expenditures for turnarounds and catalysts
62,473

 
8,617

 
11,460




35


 
As of December 31,
 
2014
 
2013
BALANCE SHEET DATA (end of period):
(dollars in thousands)
Cash and cash equivalents
$
214,961

 
$
224,499

Working capital
126,665

 
60,863

Total assets
2,200,874

 
2,245,140

Total debt
563,687

 
612,248

Total debt less cash and cash equivalents
348,726

 
387,749

Total equity
673,778

 
625,404

(1)
Includes excise taxes on sales by the retail segment of $75,409, $73,597 and $66,563 for the years ended December 31, 2014, 2013 and 2012, respectively.
(2)
Includes corporate headquarters selling, general and administrative expenses of $705, $721 and $960 for the years ended December 31, 2014, 2013 and 2012, respectively, which are not allocated to our three operating segments.
(3)
Includes corporate depreciation and amortization of $2,399, $2,673 and $2,127 for the years ended December 31, 2014, 2013 and 2012, respectively, which are not allocated to our three operating segments.
(4)
Interest expense for the year ended December 31, 2013 includes charges of $8,467 for a prepayment premium and write-offs of unamortized original issuance discount and debt issuance costs recognized for the prepayment of a portion of the Alon Refining Krotz Springs senior secured notes.
Interest expense for the year ended December 31, 2012 includes a charge of $9,624 for the write-off of unamortized original issuance discount associated with the repayment of the Alon Brands Term Loan and charges of $27,576 for the write-offs of unamortized original issuance discount and debt issuance costs recognized for the repayment of the Alon USA Energy, Inc. term loan credit facilities.
(5)
Other income (loss), net for the year ended December 31, 2012 is substantially the loss on heating oil call option crack spread contracts.
(6)
See “Reconciliation of Amounts Reported Under Generally Accepted Accounting Principles” for information regarding our definition of Adjusted EBITDA, its limitations as an analytical tool and a reconciliation of net income available to stockholders to Adjusted EBITDA for the periods presented.
(7)
Includes corporate capital expenditures of $2,756, $881 and $2,228 for the years ended December 31, 2014, 2013 and 2012, respectively, which are not allocated to our three operating segments.


36


REFINING AND MARKETING SEGMENT
 
 
 
 
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(dollars in thousands, except per barrel data and pricing statistics)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
Net sales (1)
$
5,937,982

 
$
6,090,688

 
$
7,241,935

Operating costs and expenses:
 
 
 
 
 
Cost of sales
5,329,605

 
5,561,825

 
6,551,483

Direct operating expenses
241,833

 
244,759

 
278,725

Selling, general and administrative expenses
56,004

 
52,846

 
51,215

Depreciation and amortization
104,676

 
105,597

 
103,638

Total operating costs and expenses
5,732,118

 
5,965,027

 
6,985,061

Gain (loss) on disposition of assets
(1,255
)
 
7,359

 
(2,502
)
Operating income
$
204,609

 
$
133,020

 
$
254,372

KEY OPERATING STATISTICS:
 
 
 
 
 
Per barrel of throughput:
 
 
 
 
 
Refinery operating margin – Big Spring (2)
$
16.69

 
$
14.59

 
$
23.50

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

 
N/A

 
2.36

Refinery operating margin – Krotz Springs (2)
7.57

 
6.16

 
8.30

Refinery direct operating expense – Big Spring (3)
4.39

 
4.53

 
4.00

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

 
N/A

 
12.59

Refinery direct operating expense – Krotz Springs (3)
4.12

 
4.09

 
3.85

Capital expenditures
$
63,148

 
$
40,272

 
$
68,112

Capital expenditures for turnarounds and catalysts
62,473

 
8,617

 
11,460

PRICING STATISTICS:
 
 
 
 
 
Crack spreads (3/2/1) (per barrel):
 
 
 
 
 
Gulf Coast
$
14.52

 
$
19.16

 
$
27.43

Crack spreads (2/1/1) (per barrel):
 
 
 
 
 
Gulf Coast high sulfur diesel
$
9.76

 
$
7.89

 
$
11.29

WTI Cushing crude oil (per barrel)
$
93.10

 
$
97.97

 
$
94.14

Crude oil differentials (per barrel):
 
 
 
 
 
WTI Cushing less WTI Midland
$
6.93

 
$
2.59

 
$
2.92

WTI Cushing less WTS
6.04

 
3.72

 
4.09

LLS less WTI Cushing
3.85

 
11.06

 
16.46

Brent less LLS
3.45

 
1.35

 
0.73

Brent less WTI Cushing
7.30

 
12.41

 
17.19

Product price (dollars per gallon):
 
 
 
 
 
Gulf Coast unleaded gasoline
$
2.49

 
$
2.70

 
$
2.82

Gulf Coast ultra-low sulfur diesel
2.71

 
2.97

 
3.05

Gulf Coast high sulfur diesel
2.59

 
2.87

 
2.99

Natural gas (per MMBtu)
4.26

 
3.73

 
2.83



37


THROUGHPUT AND PRODUCTION DATA:
BIG SPRING REFINERY
Year Ended December 31,
2014
 
2013
 
2012
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
WTS crude
30,323

 
45.9

 
43,705

 
65.1

 
52,190

 
75.7

WTI crude
32,429

 
49.1

 
20,706

 
30.9

 
14,396

 
20.9

Blendstocks
3,281

 
5.0

 
2,692

 
4.0

 
2,360

 
3.4

Total refinery throughput (4)
66,033

 
100.0

 
67,103

 
100.0

 
68,946

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline
32,932

 
49.7

 
33,736

 
50.4

 
34,637

 
50.3

Diesel/jet
23,252

 
35.1

 
22,404

 
33.5

 
22,329

 
32.5

Asphalt
2,716

 
4.1

 
3,640

 
5.4

 
4,084

 
5.9

Petrochemicals
3,756

 
5.7

 
4,152

 
6.2

 
4,054

 
5.9

Other
3,565

 
5.4

 
3,033

 
4.5

 
3,706

 
5.4

Total refinery production (5)
66,221

 
100.0

 
66,965

 
100.0

 
68,810

 
100.0

Refinery utilization (6)
 
 
97.2
%
 
 
 
94.9
%
 
 
 
97.3
%
THROUGHPUT AND PRODUCTION DATA:
CALIFORNIA REFINERIES
Year Ended December 31,
2014
 
2013
 
2012
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
Medium sour crude

 

 

 

 
9,071

 
50.7

Heavy crude

 

 

 

 
8,038

 
45.0

Blendstocks

 

 

 

 
768

 
4.3

Total refinery throughput (4)

 

 

 

 
17,877

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline

 

 

 

 
3,716

 
20.8

Diesel/jet

 

 

 

 
6,503

 
36.4

Asphalt

 

 

 

 
4,580

 
25.6

Heavy unfinished

 

 

 

 
2,603

 
14.6

Other

 

 

 

 
462

 
2.6

Total refinery production (5)

 

 

 

 
17,864

 
100.0

Refinery utilization (6)
 
 
%
 
 
 
%
 
 
 
23.6
%
THROUGHPUT AND PRODUCTION DATA:
KROTZ SPRINGS REFINERY
Year Ended December 31,
2014
 
2013
 
2012
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
WTI crude
28,373

 
40.3

 
29,580

 
45.7

 
20,111

 
29.6

Gulf Coast sweet crude
39,636

 
56.4

 
33,233

 
51.4

 
46,924

 
69.2

Blendstocks
2,336

 
3.3

 
1,892

 
2.9

 
842

 
1.2

Total refinery throughput (4)
70,345

 
100.0

 
64,705

 
100.0

 
67,877

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
Gasoline
32,925

 
45.9

 
29,432

 
44.6

 
29,081

 
42.4

Diesel/jet
30,060

 
41.9

 
26,508

 
40.2

 
28,466

 
41.4

Heavy Oils
1,146

 
1.6

 
1,175

 
1.8

 
2,709

 
3.9

Other
7,579

 
10.6

 
8,857

 
13.4

 
8,464

 
12.3

Total refinery production (5)
71,710

 
100.0

 
65,972

 
100.0

 
68,720

 
100.0

Refinery utilization (6)
 
 
91.9
%
 
 
 
85.9
%
 
 
 
90.6
%


38


(1)
Net sales include intersegment sales to our asphalt and retail segments at prices which approximate wholesale market prices. These intersegment sales are eliminated through consolidation of our financial statements.
(2)
Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales (exclusive of substantial hedge positions) attributable to each refinery by its throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margins to these crack spreads to assess our operating performance relative to other participants in our industry.
The refinery operating margin for the years ended December 31, 2014, 2013 and 2012 excludes gains (losses) on commodity swaps of $4,660, $23,900 and ($116,020), respectively.
(3)
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.
(4)
Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.
(5)
Total refinery production represents the barrels per day of various products produced from processing crude and other refinery feedstocks through the crude units and other conversion units at the refineries.
(6)
Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.


39


ASPHALT SEGMENT
 
 
 
 
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(dollars in thousands, except per ton data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
Net sales (1)
$
457,412

 
$
612,443

 
$
603,896

Operating costs and expenses:

 

 
 
Cost of sales (1) (2)
431,931

 
558,263

 
563,516

Direct operating expenses
39,853

 
42,993

 
34,517

Selling, general and administrative expenses
7,874

 
8,886

 
4,230

Depreciation and amortization
4,747

 
6,398

 
5,866

Total operating costs and expenses
484,405

 
616,540

 
608,129

Gain on disposition of assets
1,396

 

 
505

Operating loss
$
(25,597
)
 
$
(4,097
)
 
$
(3,728
)
KEY OPERATING STATISTICS:
 
 
 
 
 
Blended asphalt sales volume (tons in thousands) (3)
516

 
701

 
842

Non-blended asphalt sales volume (tons in thousands) (4)
65

 
88

 
105

Blended asphalt sales price per ton (3)
$
571.18

 
$
573.87

 
$
589.63

Non-blended asphalt sales price per ton (4)
397.91

 
372.00

 
372.36

Asphalt margin per ton (5)
43.86

 
68.67

 
42.64

Capital expenditures
$
5,777

 
$
9,425

 
$
9,420

(1)
Net sales and cost of sales include asphalt purchases sold as part of a supply and offtake arrangement of approximately $137,000, $177,000 and $68,000 for the years ended December 31, 2014, 2013 and 2012, 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 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.


40


RETAIL SEGMENT
 
 
 
 
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(dollars in thousands, except per gallon data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
Net sales (1)
$
939,684


$
944,193

 
$
907,918

Operating costs and expenses:



 
 
Cost of sales (2)
796,356


805,943

 
770,394

Selling, general and administrative expenses
105,556


105,719

 
104,996

Depreciation and amortization
12,241


10,826

 
10,298

Total operating costs and expenses
914,153

 
922,488

 
885,688

Gain (loss) on disposition of assets
134


2,199

 
(312
)
Operating income
$
25,665

 
$
23,904

 
$
21,918

KEY OPERATING STATISTICS:
 
 
 
 
 
Number of stores (end of period) (3)
295

 
297

 
298

Retail fuel sales (thousands of gallons)
192,582

 
188,493

 
170,848

Retail fuel sales (thousands of gallons per site per month) (3)
57

 
55

 
50

Retail fuel margin (cents per gallon) (4)
21.6

 
19.3

 
20.2

Retail fuel sales price (dollars per gallon) (5)
$
3.20

 
$
3.33

 
$
3.47

Merchandise sales
$
322,262

 
$
316,432

 
$
315,082

Merchandise sales (per site per month) (3)
$
91

 
$
89

 
$
88

Merchandise margin (6)
31.4
%
 
32.1
%
 
32.5
%
Capital expenditures
$
16,748

 
$
17,935

 
$
14,141

(1)
Includes excise taxes on sales of $75,409, $73,597 and $66,563 for the years ended December 31, 2014, 2013 and 2012, 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, 2014, we had 295 retail convenience stores of which 283 sold fuel. At December 31, 2013, we had 297 retail convenience stores of which 285 sold fuel. At December 31, 2012, we had 298 retail convenience stores of which 286 sold fuel.
(4)
Retail fuel margin represents the difference between retail fuel sales revenue and the net cost of purchased retail fuel, including transportation costs and associated excise taxes, expressed on a cents-per-gallon basis. Retail fuel margins are frequently used in the retail industry to measure operating results related to retail fuel sales.
(5)
Retail fuel sales price per gallon represents the average sales price for retail fuels sold through our retail convenience stores.
(6)
Merchandise margin represents the difference between merchandise sales revenues and the delivered cost of merchandise purchases, net of rebates and commissions, expressed as a percentage of merchandise sales revenues. Merchandise margins, also referred to as in-store margins, are commonly used in the retail convenience store industry to measure in-store, or non-fuel, operating results.


41


Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Net Sales
Consolidated. Net sales for the year ended December 31, 2014 were $6,779.5 million, compared to $7,046.4 million for the year ended December 31, 2013, a decrease of $266.9 million. This decrease was primarily due to lower refined product prices, partially offset by higher combined refinery throughput.
Refining and Marketing Segment. Net sales for our refining and marketing segment were $5,938.0 million for the year ended December 31, 2014, compared to $6,090.7 million for the year ended December 31, 2013, a decrease of $152.7 million. This decrease was primarily due to lower refined product prices, partially offset by higher combined refinery throughput for the year ended December 31, 2014 compared to the year ended December 31, 2013.
Combined refinery average throughput for the year ended December 31, 2014 was 136,378 bpd, consisting of 66,033 bpd at the Big Spring refinery and 70,345 bpd at the Krotz Springs refinery, compared to a combined refinery average throughput of 131,808 bpd for the year ended December 31, 2013, consisting of 67,103 bpd at the Big Spring refinery and 64,705 bpd at the Krotz Springs refinery. The lower refinery throughput at the Big Spring refinery was the result of downtime necessary to complete both the planned turnaround and the vacuum tower project during the second quarter of 2014. Refinery throughput at the Krotz Springs refinery was lower for 2013 due to the unplanned shut down and repair of the reformer unit for approximately one month.
Refined product prices decreased during the year ended December 31, 2014 compared to the year ended December 31, 2013. The average per gallon price of Gulf Coast gasoline for the year ended December 31, 2014 decreased $0.21, or 7.8%, to $2.49, compared to $2.70 for the year ended December 31, 2013. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the year ended December 31, 2014 decreased $0.26, or 8.8%, to $2.71, compared to $2.97 for the year ended December 31, 2013. The average per gallon price for Gulf Coast high sulfur diesel for the year ended December 31, 2014 decreased $0.28, or 9.8%, to $2.59, compared to $2.87 for the year ended December 31, 2013.
Asphalt Segment. Net sales for our asphalt segment were $457.4 million for the year ended December 31, 2014, compared to $612.4 million for the year ended December 31, 2013, a decrease of $155.0 million, or 25.3%. This decrease was primarily due to lower asphalt sales as part of a supply and offtake arrangement of approximately $40.0 million and decreased sales volumes associated with reduced asphalt demand in local markets in which we operate. The asphalt sales volume decreased 26.4% to 581 thousand tons for the year ended December 31, 2014 from 789 thousand tons for the year ended December 31, 2013.
Retail Segment. Net sales for our retail segment were $939.7 million for the year ended December 31, 2014, compared to $944.2 million for the year ended December 31, 2013, a decrease of $4.5 million, or 0.5%. This decrease was primarily due to lower retail fuel sales prices, partially offset by higher retail fuel sales volumes and merchandise sales.
Cost of Sales
Consolidated. Cost of sales for the year ended December 31, 2014 were $6,002.3 million, compared to $6,325.1 million for the year ended December 31, 2013, a decrease of $322.8 million, or 5.1%. This decrease was primarily due to lower crude oil prices, partially offset by higher combined refinery throughput.
Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $5,329.6 million for the year ended December 31, 2014, compared to $5,561.8 million for the year ended December 31, 2013, a decrease of $232.2 million, or 4.2%. This decrease was primarily due to lower crude oil prices, partially offset by higher combined refinery throughput and higher RINs costs. The average price of WTI Cushing decreased 5.0% to $93.10 per barrel for the year ended December 31, 2014 from $97.97 per barrel for the year ended December 31, 2013. Cost of sales for the year ended December 31, 2014 includes $27.1 million of costs to purchase RINs needed to satisfy our obligation to blend biofuels into the products we produce, compared to RINs costs of $14.9 million for the year ended December 31, 2013.
Asphalt Segment. Cost of sales for our asphalt segment were $431.9 million for the year ended December 31, 2014, compared to $558.3 million for the year ended December 31, 2013, a decrease of $126.4 million, or 22.6%. This decrease was primarily due to decreased sales volumes and lower asphalt purchases as part of a supply and offtake arrangement of approximately $40.0 million, partially offset by higher costs of asphalt purchased during the year ended December 31, 2014 compared to the year ended December 31, 2013.
Retail Segment. Cost of sales for our retail segment were $796.4 million for the year ended December 31, 2014, compared to $805.9 million for the year ended December 31, 2013, a decrease of $9.5 million, or 1.2%. This decrease was primarily due to lower retail fuel prices, partially offset by higher retail fuel sales volumes and merchandise costs.


42


Direct Operating Expenses
Consolidated. Direct operating expenses were $281.7 million for the year ended December 31, 2014, compared to $287.8 million for the year ended December 31, 2013, a decrease of $6.1 million, or 2.1%.
Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the year ended December 31, 2014 were $241.8 million, compared to $244.8 million for the year ended December 31, 2013, a decrease of $3.0 million, or 1.2%. This decrease was primarily due to lower major maintenance and insurance costs, partially offset by higher natural gas costs during the year ended December 31, 2014.
Asphalt Segment. Direct operating expenses for our asphalt segment for the year ended December 31, 2014 were $39.9 million, compared to $43.0 million for the year ended December 31, 2013, a decrease of $3.1 million, or 7.2%. This decrease was primarily due to reduced insurance costs during the year ended December 31, 2014.
Selling, General and Administrative Expenses
Consolidated. SG&A expenses for the year ended December 31, 2014 were $170.1 million, compared to $168.2 million for the year ended December 31, 2013, an increase of $1.9 million, or 1.1%. This increase was primarily due to higher employee related costs during the year ended December 31, 2014.
Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the year ended December 31, 2014 were $56.0 million, compared to $52.8 million for the year ended December 31, 2013, an increase of $3.2 million, or 6.1%. This increase was primarily due to higher employee related costs during the year ended December 31, 2014.
Asphalt Segment. SG&A expenses for our asphalt segment for the year ended December 31, 2014 were $7.9 million, compared to $8.9 million for the year ended December 31, 2013, a decrease of $1.0 million, or 11.2%. This decrease was primarily due to lower corporate expense allocated to the asphalt segment, partially offset by higher employee related costs during the year ended December 31, 2014.
Retail Segment. SG&A expenses for our retail segment for the year ended December 31, 2014 were $105.6 million, compared to $105.7 million for the year ended December 31, 2013, a decrease of $0.1 million, or 0.1%.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2014 was $124.1 million, compared to $125.5 million for the year ended December 31, 2013, a decrease of $1.4 million, or 1.1%.
Operating Income
Consolidated. Operating income for the year ended December 31, 2014 was $201.6 million, compared to $149.4 million for the year ended December 31, 2013, an increase of $52.2 million. This increase was primarily due to higher refinery operating margins and lower direct operating expenses during the year ended December 31, 2014.
Refining and Marketing Segment. Operating income for our refining and marketing segment was $204.6 million for the year ended December 31, 2014, compared to $133.0 million for the year ended December 31, 2013, an increase of $71.6 million. This increase was primarily due to higher refinery operating margins and higher combined refinery throughput, partially offset by impacts from derivative transactions during the year ended December 31, 2014. Operating income for the year ended December 31, 2014 includes gains on commodity swaps of $4.7 million, compared to gains on commodity swaps of $23.9 million for the year ended December 31, 2013.
Refinery operating margin at the Big Spring refinery was $16.69 per barrel for the year ended December 31, 2014, compared to $14.59 per barrel for the year ended December 31, 2013. This increase in operating margin was primarily due to a widening of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread, partially offset by a lower Gulf Coast 3/2/1 crack spread. The WTI Cushing to WTS spread for the year ended December 31, 2014 was $6.04 per barrel, compared to $3.72 per barrel for the year ended December 31, 2013. The WTI Cushing to WTI Midland spread for the year ended December 31, 2014 was $6.93 per barrel, compared to $2.59 per barrel for the year ended December 31, 2013. The average Gulf Coast 3/2/1 crack spread decreased 24.2% to $14.52 per barrel for the year ended December 31, 2014, compared to $19.16 per barrel for the year ended December 31, 2013, which was primarily influenced by a decrease in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the year ended December 31, 2014 was $7.30 per barrel compared to $12.41 per barrel for the year ended December 31, 2013.
Refinery operating margin at the Krotz Springs refinery was $7.57 per barrel for the year ended December 31, 2014, compared to $6.16 per barrel for the year ended December 31, 2013. This increase in operating margin was primarily due to a higher Gulf Coast 2/1/1 high sulfur diesel crack spread and a widening WTI Cushing to WTI Midland spread, partially offset by a narrowing LLS to WTI Cushing spread and the impact of RINs costs during the year ended December 31, 2014. The


43


average Gulf Coast 2/1/1 high sulfur diesel crack spread for the year ended December 31, 2014 was $9.76 per barrel, compared to $7.89 per barrel for the year ended December 31, 2013, which was primarily influenced by an increase in the Brent to LLS spread. The average Brent to LLS spread for the year ended December 31, 2014 was $3.45 per barrel compared to $1.35 per barrel for the year ended December 31, 2013. The LLS to WTI Cushing spread for the year ended December 31, 2014 was $3.85 per barrel, compared to $11.06 per barrel for the year ended December 31, 2013. The Krotz Springs refinery operating margin was impacted by RINs costs of $21.4 million, or $0.83 per barrel of throughput, for the year ended December 31, 2014. The Krotz Springs refinery received an exemption from the RFS requirements for 2013 and as a result did not record costs associated with RINs.
Asphalt Segment. Operating loss for our asphalt segment was $25.6 million for the year ended December 31, 2014, compared to $4.1 million for the year ended December 31, 2013, an increase in loss of $21.5 million. This increase in loss was primarily due to lower asphalt margins and lower asphalt sales volumes associated with reduced asphalt demand in local markets in which we operate. Asphalt margins for the year ended December 31, 2014 were $43.86 per ton, compared to $68.67 per ton for the year ended December 31, 2013.
Retail Segment. Operating income for our retail segment was $25.7 million for the year ended December 31, 2014, compared to $23.9 million for the year ended December 31, 2013, an increase of $1.8 million. This increase was primarily due to higher retail fuel margins, higher retail fuel sales volumes and higher merchandise sales, partially offset by lower merchandise margins.
Interest Expense
Interest expense was $111.1 million for the year ended December 31, 2014, compared to $94.7 million for the year ended December 31, 2013, an increase of $16.4 million, or 17.3%. This increase was primarily due to higher financing costs associated with crude oil purchases under our supply and offtake agreements as a result of a backwardated crude oil market, partially offset by lower interest costs on the reduced balance of our long-term debt obligations during the year ended December 31, 2014. Interest expense for the year ended December 31, 2013 includes a charge of $8.5 million for a prepayment premium and write-offs of unamortized original issuance discount and debt issuance costs recognized for prepayment of a portion of the Alon Refining Krotz Springs senior secured notes.
Income Tax Expense
Income tax expense was $22.9 million for the year ended December 31, 2014, compared to $12.2 million for the year ended December 31, 2013. This increase resulted from our higher pre-tax income for the year ended December 31, 2014 compared to the year ended December 31, 2013, and an increase in the effective tax rate. Our effective tax rate was 24.7% for the year ended December 31, 2014, compared to an effective tax rate of 20.2% for the year ended December 31, 2013. The lower effective tax rate compared to the statutory rate was due to the impact of the non-controlling interest’s share of Partnership income.
Net Income Attributable to Non-controlling Interest
Net income attributable to non-controlling interest includes the proportional share of the Partnership’s income attributable to limited partner interests held by the public. Additionally, net income attributable to non-controlling interest includes the proportional share of net income related to non-voting common stock of our subsidiary, Alon Assets, Inc., owned by non-controlling interest shareholders. Net income attributable to non-controlling interest was $31.4 million for the year ended December 31, 2014, compared to $25.1 million for the year ended December 31, 2013, an increase of $6.3 million.
Net Income Available to Stockholders
Net income available to stockholders was $38.5 million for the year ended December 31, 2014, compared to $23.0 million for the year ended December 31, 2013, an increase of $15.5 million. This increase was attributable to the factors discussed above.
Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012
Net Sales
Consolidated. Net sales for the year ended December 31, 2013 were $7,046.4 million, compared to $8,017.7 million for the year ended December 31, 2012, a decrease of $971.3 million. This decrease was primarily due to lower refinery throughput and lower refined product prices.
Refining and Marketing Segment. Net sales for our refining and marketing segment were $6,090.7 million for the year ended December 31, 2013, compared to $7,241.9 million for the year ended December 31, 2012, a decrease of $1,151.2 million. This decrease was primarily due to lower refinery throughput and lower refined product prices for the year ended December 31, 2013.


44


Combined refinery average throughput for the year ended December 31, 2013 was 131,808 bpd, consisting of 67,103 bpd at the Big Spring refinery and 64,705 bpd at the Krotz Springs refinery, compared to a combined refinery average throughput of 154,700 bpd for the year ended December 31, 2012, consisting of 68,946 bpd at the Big Spring refinery, 67,877 bpd at the Krotz Springs refinery and 17,877 bpd at the California refineries. The lower throughput for the year ended December 31, 2013 was primarily due to our California refineries not processing crude oil during the year, which had processed crude oil for approximately eight months during 2012. The reduced refinery throughput for the Krotz Springs refinery during 2013 reflects the impact of the unplanned shut down and repair of the reformer unit for approximately one month.
Refined product prices decreased for all of our products during the year ended December 31, 2013 compared to the year ended December 31, 2012. The average per gallon price of Gulf Coast gasoline for the year ended December 31, 2013 decreased $0.12, or 4.3%, to $2.70, compared to $2.82 for the year ended December 31, 2012. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the year ended December 31, 2013 decreased $0.08, or 2.6%, to $2.97, compared to $3.05 for the year ended December 31, 2012. The average per gallon price for Gulf Coast high sulfur diesel for the year ended December 31, 2013 decreased $0.12, or 4.0%, to $2.87, compared to $2.99 for the year ended December 31, 2012.
Asphalt Segment. Net sales for our asphalt segment were $612.4 million for the year ended December 31, 2013, compared to $603.9 million for the year ended December 31, 2012, an increase of $8.5 million or 1.4%. This increase was primarily due to higher asphalt sales as part of a supply and offtake arrangement of approximately $109.0 million, partially offset by decreased asphalt sales volumes and lower blended asphalt sales prices in 2013. The asphalt sales volume decreased 16.7% to 789 thousand tons for the year ended December 31, 2013 from 947 thousand tons for the year ended December 31, 2012. The average blended asphalt sales price decreased 2.7% to $573.87 per ton for the year ended December 31, 2013 from $589.63 per ton for the year ended December 31, 2012.
Retail Segment. Net sales for our retail segment were $944.2 million for the year ended December 31, 2013, compared to $907.9 million for the year ended December 31, 2012, an increase of $36.3 million or 4.0%. This increase was primarily due to increased retail fuel sales volumes and merchandise sales, partially offset by lower retail fuel sales prices.
Cost of Sales
Consolidated. Cost of sales for the year ended December 31, 2013 were $6,325.1 million, compared to $7,149.4 million for the year ended December 31, 2012, a decrease of $824.3 million, or 11.5%. This decrease was primarily due to lower refinery throughput, partially offset by higher crude oil prices.
Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $5,561.8 million for the year ended December 31, 2013, compared to $6,551.5 million for the year ended December 31, 2012, a decrease of $989.7 million, or 15.1%. This decrease was primarily due to lower refinery throughput, partially offset by higher crude oil prices. Cost of sales for the year ended December 31, 2013 includes $14.9 million of costs to purchase RINs needed to satisfy our obligation to blend biofuels into the products we produce.
The average price of WTI Cushing increased 4.1% to $97.97 per barrel for the year ended December 31, 2013 from $94.14 per barrel for the year ended December 31, 2012. The average WTI Cushing to WTS spread narrowed to $3.72 per barrel for the year ended December 31, 2013, compared to $4.09 per barrel for the year ended December 31, 2012. The average WTI Cushing to WTI Midland spread narrowed to $2.59 per barrel for the year ended December 31, 2013, compared to $2.92 per barrel for the year ended December 31, 2012. The average LLS to WTI Cushing spread narrowed to $11.06 per barrel for the year ended December 31, 2013, compared to $16.46 per barrel for the year ended December 31, 2012.
Asphalt Segment. Cost of sales for our asphalt segment were $558.3 million for the year ended December 31, 2013, compared to $563.5 million for the year ended December 31, 2012, a decrease of $5.2 million or 0.9%. The decrease was primarily due to lower asphalt sales volumes, partially offset by higher asphalt purchases as part of a supply and offtake arrangement for the year ended December 31, 2013 compared to the year ended December 31, 2012.
Retail Segment. Cost of sales for our retail segment were $805.9 million for the year ended December 31, 2013, compared to $770.4 million for the year ended December 31, 2012, an increase of $35.5 million, or 4.6%. This increase was primarily due to increased retail fuel sales volumes and merchandise costs, partially offset by lower retail fuel prices.
Direct Operating Expenses
Consolidated. Direct operating expenses were $287.8 million for the year ended December 31, 2013, compared to $313.2 million for the year ended December 31, 2012, a decrease of $25.4 million, or 8.1%.
Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the year ended December 31, 2013 were $244.8 million, compared to $278.7 million for the year ended December 31, 2012, a decrease of $33.9 million, or 12.2%. This decrease was primarily due to the California refineries not processing crude oil during 2013, partially offset by higher natural gas costs.


45


Asphalt Segment. Direct operating expenses for our asphalt segment for the year ended December 31, 2013 were $43.0 million, compared to $34.5 million for the year ended December 31, 2012, an increase of $8.5 million, or 24.6%. This increase was primarily due to higher natural gas costs and higher facilities maintenance costs.
Selling, General and Administrative Expenses
Consolidated. SG&A expenses for the year ended December 31, 2013 were $168.2 million, compared to $161.4 million for the year ended December 31, 2012, an increase of $6.8 million, or 4.2%. This increase was primarily due to higher employee related costs.
Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the year ended December 31, 2013 were $52.8 million, compared to $51.2 million for the year ended December 31, 2012, an increase of $1.6 million, or 3.1%. This increase was primarily due to higher employee related costs.
Asphalt Segment. SG&A expenses for our asphalt segment for the year ended December 31, 2013 were $8.9 million, compared to $4.2 million for the year ended December 31, 2012, an increase of $4.7 million, or 111.9%. This increase was primarily due to higher corporate expense allocated to the asphalt segment.
Retail Segment. SG&A expenses for our retail segment for the year ended December 31, 2013 were $105.7 million, compared to $105.0 million for the year ended December 31, 2012, an increase of $0.7 million, or 0.7%.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2013 was $125.5 million, compared to $121.9 million for the year ended December 31, 2012, an increase of $3.6 million, or 3.0%.
Operating Income
Consolidated. Operating income for the year ended December 31, 2013 was $149.4 million, compared to $269.5 million for the year ended December 31, 2012, a decrease of $120.1 million. This decrease was primarily due to lower refinery operating margins and lower refinery throughput, partially offset by lower direct operating expenses and favorable impacts from derivative transactions during the year ended December 31, 2013.
Refining and Marketing Segment. Operating income for our refining and marketing segment was $133.0 million for the year ended December 31, 2013, compared to $254.4 million for the year ended December 31, 2012, a decrease of $121.4 million. This decrease was primarily due to lower refinery operating margins and lower refinery throughput, partially offset by lower direct operating expenses and gains on commodity swaps during the year ended December 31, 2013 of $23.9 million, compared to losses on commodity swaps of $130.1 million during the year ended December 31, 2012.
Refinery operating margin at the Big Spring refinery was $14.59 per barrel for the year ended December 31, 2013, compared to $23.50 per barrel for the year ended December 31, 2012. This decrease was primarily due to a lower Gulf Coast 3/2/1 crack spread and a narrowing of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread. The average Gulf Coast 3/2/1 crack spread decreased 30.1% to $19.16 per barrel for the year ended December 31, 2013, compared to $27.43 per barrel for the year ended December 31, 2012, which was primarily influenced by a decrease in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the year ended December 31, 2013 was $12.41 per barrel compared to $17.19 per barrel for the year ended December 31, 2012. Operating income and refinery operating margin at the Big Spring refinery for the year ended December 31, 2013 were also impacted by $14.9 million of costs for the purchase of RINs needed to satisfy our obligation to blend biofuels into the products we produce, which we were not subject to in 2012.
Refinery operating margin at the Krotz Springs refinery was $6.16 per barrel for the year ended December 31, 2013, compared to $8.30 per barrel for the year ended December 31, 2012. This decrease was primarily due to a lower Gulf Coast 2/1/1 high sulfur diesel crack spread and a narrowing of both the LLS to WTI Cushing spread and the WTI Cushing to WTI Midland spread during the year ended December 31, 2013. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the year ended December 31, 2013 was $7.89 per barrel, compared to $11.29 per barrel for the year ended December 31, 2012.
Asphalt Segment. Operating loss for our asphalt segment was $4.1 million for the year ended December 31, 2013, compared to $3.7 million for the year ended December 31, 2012, an increase in loss of $0.4 million, or 10.8%. This increase in loss was primarily due to higher direct operating costs and SG&A expenses, partially offset by increased asphalt margins. Asphalt margins for the year ended December 31, 2013 were $68.67 per ton compared to $42.64 per ton for the year ended December 31, 2012.


46


Retail Segment. Operating income for our retail segment was $23.9 million for the year ended December 31, 2013, compared to $21.9 million for the year ended December 31, 2012, an increase of $2.0 million. This increase was primarily due to higher retail fuel sales volumes and higher merchandise sales, partially offset by lower retail fuel margins and merchandise margins.
Interest Expense
Interest expense was $94.7 million for the year ended December 31, 2013, compared to $129.6 million for the year ended December 31, 2012, a decrease of $34.9 million, or 26.9%. This decrease was primarily due to lower costs included in interest expense related to prepayments of our long-term debt obligations during the year ended December 31, 2013 compared to the year ended December 31, 2012. Interest expense for the year ended December 31, 2013 includes charges of $8.5 million for a prepayment premium and write-offs of unamortized original issuance discount and debt issuance costs recognized for prepayment of a portion of the Alon Refining Krotz Springs senior secured notes. Interest expense for the year ended December 31, 2012, includes a charge of $9.6 million for the write-off of unamortized original issuance discount associated with our repayment of the Alon Brands Term Loan and charges of $27.6 million for the write-offs of unamortized original issuance discount and debt issuance costs associated with the repayment of the Alon USA Energy, Inc. term loan credit facilities.
Income Tax Expense
Income tax expense was $12.2 million for the year ended December 31, 2013, compared to $49.9 million for the year ended December 31, 2012. This decrease was the result of lower pre-tax income for the year ended December 31, 2013, compared to the year ended December 31, 2012, and a decrease in the effective tax rate. Our effective tax rate was 20.2% for the year ended December 31, 2013, compared to an effective tax rate of 35.5% for the year ended December 31, 2012. The lower effective tax rate was due to the impact of the non-controlling interest’s share of Partnership income.
Net Income Attributable to Non-controlling Interest
Net income attributable to non-controlling interest includes the proportional share of the Partnership’s income attributable to limited partner interests held by the public. Additionally, net income attributable to non-controlling interest includes the proportional share of net income related to non-voting common stock of our subsidiary, Alon Assets, Inc. Net income attributable to non-controlling interest was $25.1 million for the year ended December 31, 2013, compared to $11.5 million for the year ended December 31, 2012, an increase of $13.6 million. This increase was due to the impact of the non-controlling interest’s share of Partnership income as a result of the Partnership’s initial public offering in November 2012.
Net Income Available to Stockholders
Net income available to stockholders was $23.0 million for the year ended December 31, 2013, compared to $79.1 million for the year ended December 31, 2012, a decrease of $56.1 million. This decrease was attributable to the factors discussed above.
Liquidity and Capital Resources
Our primary sources of liquidity are cash on hand, cash generated from our operating activities, borrowings under our revolving credit facilities, inventory supply and offtake arrangements, other credit lines and advances from affiliates.
We have agreements with J. Aron for the supply of crude oil that will support the operations of all our refineries as well as most of our asphalt terminals. These agreements substantially reduce our physical inventories and our associated need to issue letters of credit to support crude oil and asphalt purchases. In addition, the structure allows us to acquire crude oil and asphalt without the constraints of a maximum facility size during periods of high crude oil prices.
We believe that the aforementioned sources of funds and other sources of capital available to us will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control.
Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or equity securities, or other possible capital markets transactions, the proceeds of which could be used to refinance current indebtedness, extend or replace existing revolving credit facilities or for other corporate purposes.
As of December 31, 2014, our total cash and cash equivalents were $215.0 million and we had total debt of $563.7 million.


47


Cash Flows
The following table sets forth our consolidated cash flows for the years ended December 31, 2014, 2013 and 2012:
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(dollars in thousands)
Cash provided by (used in):
 
 
 
 
 
Operating activities
$
193,658

 
$
162,233

 
$
387,810

Investing activities
(108,995
)
 
(51,441
)
 
(104,980
)
Financing activities
(94,201
)
 
(2,589
)
 
(323,600
)
Net increase (decrease) in cash and cash equivalents
$
(9,538
)
 
$
108,203

 
$
(40,770
)
Cash Flows Provided by Operating Activities
Net cash provided by operating activities for the year ended December 31, 2014 was $193.7 million, compared to $162.2 million for the year ended December 31, 2013. The increase in cash provided by operating activities of $31.5 million was primarily due to higher net income after adjusting for non-cash items of $28.8 million, increased cash collected on accounts receivable of $119.1 million and a reduction in non-current liabilities of $47.0 million, partially offset by increased cash used for inventories of $50.2 million, increased cash used for other non-current assets of $33.5 million, increased cash used for accounts payable and accrued liabilities of $63.7 million and increased cash used for prepaid expenses and other current assets of $16.1 million.
Net cash provided by operating activities for the year ended December 31, 2013 was $162.2 million, compared to $387.8 million for the year ended December 31, 2012. The reduction in cash provided by operating activities of $225.6 million was primarily due to lower net income after adjusting for non-cash items of $152.2 million, lower cash on a reduction of other non-current liabilities of $116.3 million and lower cash collected on accounts receivable of $65.7 million, partially offset by lower cash used on reduction of inventories of $91.8 million and lower cash used for prepaid expenses and other current assets of $19.4 million.
Cash Flows Used In Investing Activities
Net cash used in investing activities was $109.0 million for the year ended December 31, 2014, compared to $51.4 million for the year ended December 31, 2013. The increase in cash used in investing activities of $57.6 million was primarily due to an increase in capital expenditures and capital expenditures for turnarounds and catalysts of $73.8 million, partially offset by increased cash proceeds from the disposition of assets of $13.9 million. The increase in capital expenditures and capital expenditures from turnarounds and catalysts is related to the completion of the planned turnaround, including the vacuum tower revamp project, at our Big Spring refinery during the second quarter of 2014.
Net cash used in investing activities was $51.4 million for the year ended December 31, 2013, compared to $105.0 million for the year ended December 31, 2012. The decrease in cash used in investing activities of $53.6 million was primarily due to a decrease in capital expenditures of $25.4 million and an increase in proceeds from the sale of assets of $26.7 million during the year ended December 31, 2013 compared to 2012.
Cash Flows Used In Financing Activities
Net cash used in financing activities was $94.2 million for the year ended December 31, 2014, compared to $2.6 million for the year ended December 31, 2013. The increase in cash used in financing activities of $91.6 million was primarily due to increased net payments on debt related transactions of $89.5 million and increased payments to shareholders and non-controlling interests of $4.1 million.
Net cash used in financing activities was $2.6 million for the year ended December 31, 2013, compared to $323.6 million for the year ended December 31, 2012. The decrease in cash used in financing activities of $321.0 million was primarily due to reduced payments on debt, net, of $513.5 million, partially offset by changes in Partnership related transactions of $199.5 million, comprised of payments for Partnership distributions of $31.7 million during the year ended December 31, 2013, compared to proceeds received from the Partnership’s initial public offering, net of fees, of $167.8 million during the year ended December 31, 2012.
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.


48


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 semiannually in arrears on March 15 and September 15 of each year, beginning on March 15, 2014. The Convertible Notes are not redeemable at our option prior to maturity. Under the terms of the Convertible Notes, the holders of the Convertible Notes cannot require us to repurchase all or part of the notes except for instances of a fundamental change, as defined in the indenture. The 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 Convertible Notes had an initial conversion rate of 67.627 shares of our common stock per each $1 (in thousands) principal amount of the Convertible Notes, equivalent to an initial conversion price of approximately $14.79 per share, which represents a conversion premium of 32.5% on our last reported common stock price of $11.16 per share on the date of the Convertible Notes offering. The conversion rate is subject to adjustment upon the occurrence of certain events, including cash dividend adjustments, but will not be adjusted for any accrued and unpaid interest. As of December 31, 2014, the conversion rate was adjusted to 68.910 shares of our common stock per each $1 (in thousands) principal amount of Convertible Notes, equivalent to a per share conversion price of approximately $14.51, to reflect cash dividend adjustments. As of December 31, 2014, 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. In October 2013, we used the remaining net proceeds from the Convertible Notes offering, along with cash on hand, to redeem $140.0 million of the outstanding principal balance on the 13.50% Alon Refining Krotz Springs senior secured notes.
Convertible Note Hedge Transactions
In connection with the Convertible Notes offering, we also entered into convertible note hedge transactions with respect to our common stock (the “Purchased Options”) with the initial purchasers of the Convertible Notes (the “Hedge Counterparties”). We paid an aggregate amount of $28.5 million to the Hedge Counterparties for the Purchased Options. As of December 31, 2014, the Purchased Options, with a strike price of $14.51 per share of our common stock, cover 10,144,050 shares of our common stock, subject to customary anti-dilution adjustments, that initially underlie the Convertible Notes sold in the offering. The Purchased Options will expire in September 2018.
The Purchased Options are intended to reduce the potential dilution with respect to our common stock upon conversion of the Convertible Notes as well as offset any potential cash payments we are required to make in excess of the principal amount upon any conversion of the notes.
The Purchased Options are separate transactions and are not part of the terms of the Convertible Notes. Holders of the Convertible Notes do not have any rights with respect to the Purchased Options.
Warrant Transactions
In connection with the Convertible Notes offering, we also entered into warrant transactions (the “Warrants”), whereby we sold to the Hedge Counterparties warrants in an aggregate amount of $13.2 million to acquire, subject to customary anti-dilution adjustments, up to 10,144,050 shares of our common stock at a strike price of approximately $19.71 per share of our common stock as of December 31, 2014. 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, Alon 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


49


our obligations under the Alon Energy Letter of Credit Facility in the event of default. The Alon Energy Letter of Credit Facility contains certain restrictive covenants including maintenance financial covenants.
At December 31, 2014 and 2013, we had outstanding letters of credit under this facility of $54.2 million and $56.8 million, respectively.
Alon Energy Term Loan. In March 2014, we entered into a five-year Term Loan Agreement (“Alon Energy Term Loan”) for a principal amount of $25.0 million, maturing in March 2019. Repayments are monthly, commencing June 2014. Borrowings under this agreement incur interest at an annual rate equal to LIBOR plus a margin of 3.75%. We pledged 2,200,000 of the Partnership’s common units as collateral for the Alon Energy Term Loan. Additionally, Alon Assets guarantees all payments under the Alon Energy Term Loan. The Alon Energy Term Loan contains certain restrictive covenants including maintenance financial covenants.
Proceeds from the Alon Energy Term Loan were used to purchase equipment for a capital project at our Big Spring refinery.
At December 31, 2014, the Alon Energy Term Loan had an outstanding balance of $22.0 million.
Alon USA Partners, LP
Partnership Term Loan Credit Facility. In connection with the Offering, the Partnership was assigned $250.0 million of the aggregate principal balance of the Alon USA Term Loan (the “Partnership Term Loan”). The Partnership Term Loan requires principal payments of $2.5 million per annum paid in quarterly installments until maturity in November 2018.
The Partnership Term Loan bears interest at a rate equal to the sum of (i) the Eurodollar rate (with a floor of 1.25% per annum) plus (ii) a margin of 8.00% per annum for a per annum rate of 9.25%, based on current Eurodollar market rates at December 31, 2014.
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, 2014 and 2013, the Partnership Term Loan had an outstanding balance (net of unamortized discount) of $242.4 million and $244.3 million, respectively.
Revolving Credit Facility. We have a $240.0 million revolving credit facility (the “Alon USA, LP Credit Facility”) that will mature in March 2016. The Alon USA, LP Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility amount or the borrowing base amount under the facility.
Borrowings under the Alon USA, LP Credit Facility bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%.
The Alon USA, LP Credit Facility is secured by a first lien on the Partnership’s cash, accounts receivables, inventories and related assets and a second lien on the Partnership’s fixed assets and other specified property.
The Alon USA, LP Credit Facility contains certain restrictive covenants including maintenance financial covenants.
Borrowings of $60.0 million and $100.0 million were outstanding under the Alon USA, LP Credit Facility at December 31, 2014 and 2013, respectively. At December 31, 2014 and 2013, outstanding letters of credit under the Alon USA, LP Credit Facility were $23.5 million and $109.8 million, respectively.
Retail
Term Credit Agreement. Southwest Convenience Stores, LLC and Skinny’s LLC, (“Alon Retail”) were party to a credit agreement (the “Credit Agreement”) with a maturity in December 2015. At December 31, 2013, the outstanding balance under the Credit Agreement was $72.7 million. In March 2014, Alon Retail entered into a new credit agreement (“Alon Retail Credit Agreement”) and repaid in full its obligations under the Credit Agreement.
The Alon Retail Credit Agreement will mature in March 2019 and includes a $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. Borrowings under the Alon Retail Credit Agreement bear interest at a Eurodollar rate plus an applicable margin between 2.00% and 2.75%, determined quarterly based upon Alon Retail’s leverage ratio. Principal payments are made in quarterly installments based on a 15-year amortization


50


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.
Proceeds from the Alon Retail Credit Agreement were used to fully repay the remaining obligations under the Credit Agreement and pay a dividend distribution of $40.0 million to Alon Brands, Inc., our wholly-owned subsidiary, while the remainder was used for general corporate purposes.
At December 31, 2014, the Alon Retail Credit Agreement had an outstanding balance of $112.7 million, consisting of a term loan balance of $102.7 million and a revolving credit loan balance of $10.0 million.
Financial Covenants. We have certain credit facilities with maintenance financial covenants. At December 31, 2014, 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 2015 is $121.8 million, which includes approximately $16.7 million of special regulatory projects.
The following table summarizes our expected capital expenditures for 2015 by operating segment (dollars in thousands):
 
Refining and
Marketing
 
Asphalt
 
Retail
 
Corporate
 
Consolidated
Total
Sustaining maintenance, regulatory and turnarounds and catalysts
$
99,164

 
$

 
$

 
$

 
$
99,164

Sustaining maintenance

 
4,750

 
12,585

 
5,344

 
22,679

Total
99,164

 
4,750

 
12,585

 
5,344

 
121,843

Our estimated capital expenditures are subject to change due to unanticipated increases/decreases in the cost, scope and completion time for our capital projects. For example, we may experience increases/decreases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of our refineries, asphalt terminals and retail locations.
Contractual Obligations
Information regarding our known contractual obligations of the types described below as of December 31, 2014 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
 
$
15,089

 
$
90,147

 
$
458,451

 
$

 
$
563,687

Operating lease obligations
 
28,263

 
51,412

 
26,242

 
43,426

 
149,343

Pipelines and terminals agreements (1)
 
38,069

 
67,077

 
84,764

 
50,247

 
240,157

Other commitments (2)
 
3,741

 
7,482

 
7,482

 
8,417

 
27,122

Total obligations
 
$
85,162

 
$
216,118

 
$
576,939

 
$
102,090

 
$
980,309

_____________________
(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.
(2)
Other commitments include refinery maintenance services costs.


51


As of December 31, 2014, 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.
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 crude oil and refined products 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 for our plans’ overfunded status or a liability if the plans are underfunded. The funded status represents the difference between the fair value of our plans’ assets and its projected benefit obligations. While we believe the assumptions we used are appropriate, significant differences in actual experience or significant changes in assumptions would affect pension and other postretirement benefits costs and obligations. For example, a 0.25 percent change in the assumptions related to the expected return on plan assets and discount rate for the funded qualified employee retirement plan would have the following effects on the projected benefit obligation as of December 31, 2014 and net periodic benefit cost for the year ending December 31, 2015 (in thousands):
 
 
0.25-Percentage Point Change
Expected rate of return:
 
 
Effect on net periodic pension expense
 
$
205

Discount rate:
 
 
Effect on net periodic pension expense
 
517

Effect on projected benefit obligation
 
5,721

Environmental and Other Loss Contingencies. We expense or capitalize environmental expenditures depending on their future economic benefit. We expense expenditures that relate to an existing condition caused by past operations and that have no future economic benefit. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Environmental liabilities represent the estimated costs to investigate and remediate contamination at our properties. 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


52


determinable. At December 31, 2014, for those payments we considered fixed or reliably determinable, payments were discounted at a 2.32% 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.
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 should be recorded if the carrying amount of the asset exceeds its fair value.
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 bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
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 impairment testing purposes.
At December 31, 2014, we had three reporting units with goodwill; California refining, California asphalt, and Retail operations. We compared the carrying values of the assets and liabilities of the three reporting units to their fair values. The fair values of our reporting units in 2014 that contain goodwill were determined based on discounted cash flow models with estimated cash flows based on internal forecasts of revenues, expenses and capital expenditures. Each reporting unit was evaluated separately. Cash flows were discounted at rates that approximate a market participants’ weighted average cost of capital; 12.1% for both California refining and California asphalt and 8.8% for Retail operations. We also compared these fair values to market earnings multiples over the internal forecasts of revenues and expenses. We believe this approach is an appropriate valuation technique for the purposes of our impairment testing. As of December 31, 2014, we concluded from our valuations that the fair value of each reporting unit substantially exceeded its carrying value and therefore none of our goodwill was impaired.
If we are unable to achieve these margins for a sustained period in the future, it could result in impairment of goodwill. In addition if, (1) our equity value declines, (2) the fair value of our reporting units decline, or (3) the impact of economic or competitive factors adversely affect beyond what was anticipated, we could conclude in future periods that impairment losses are required in order to reduce the carrying value of our goodwill, and, to a lesser extent, long-lived assets. Depending on the severity of the changes in the key factors underlying the valuation of our reporting units, such losses could be significant.
A significant portion of the fair value of our California refining reporting unit is dependent on cash flows expected to be derived from future operations of assets and projects currently not producing income. Changes to our estimated timetable for these projects could impact the conclusion of future goodwill impairment tests. If these projects do not materialize, approximately $39.0 million in goodwill is reasonably likely to be impaired.


53


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 and gain (loss) on disposition of assets. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of net income attributable to non-controlling interest, income tax expense, interest expense, gain (loss) on disposition of assets and the accounting effects of capital expenditures and acquisitions, items that may vary for different companies for reasons unrelated to overall operating performance.
Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:
Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;
Adjusted EBITDA does not reflect the prior claim that non-controlling interest have on the income generated by non-wholly-owned subsidiaries;
Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and
Our calculation of Adjusted EBITDA may differ from EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.
Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.
The following table reconciles net income available to stockholders to Adjusted EBITDA for the years ended December 31, 2014, 2013 and 2012:
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(dollars in thousands)
Net income available to stockholders
$
38,457

 
$
22,986

 
$
79,134

Net income attributable to non-controlling interest
31,411

 
25,129

 
11,463

Income tax expense
22,913

 
12,151

 
49,884

Interest expense
111,143

 
94,694

 
129,572

Depreciation and amortization
124,063

 
125,494

 
121,929

(Gain) loss on disposition of assets
(274
)
 
(9,558
)
 
2,309

Adjusted EBITDA
$
327,713

 
$
270,896

 
$
394,291

Adjusted EBITDA for the year ended December 31, 2014 does not exclude unrealized gains on commodity swaps of $3,778. Adjusted EBITDA for the year ended December 31, 2014 excluding the impact of this item would be $323,935.
Adjusted EBITDA for the year ended December 31, 2012 does not exclude unrealized losses on commodity swaps of $31,936 and losses on heating oil call option crack spread contracts of $7,297. Adjusted EBITDA for the year ended December 31, 2012 excluding the impact of these items would be $433,524.


54


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Changes in commodity prices, purchased fuel prices and interest rates are our primary sources of market risk. Our risk management committee oversees all activities associated with the identification, assessment and management of our market risk exposure.
Commodity Price Risk
We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels and governmental regulatory initiatives. Our risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations.
In order to manage the uncertainty relating to inventory price volatility, we have consistently applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as timing of crude oil cargo deliveries, turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. Upon the review and approval of our risk management committee, we may utilize the commodity futures market to manage these anticipated inventory variances.
We maintain inventories of crude oil, refined products, asphalt and blendstocks, the values of which are subject to wide fluctuations in market prices driven by world economic conditions, regional and global inventory levels and seasonal conditions. As of December 31, 2014, we held 1.6 million barrels of crude oil, refined product and asphalt inventories valued under the LIFO valuation method. Market value exceeded carrying value of LIFO costs by $8.3 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced by $1.6 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.


55


The following table provides information about our derivative commodity instruments as of December 31, 2014:
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)
 
543,339

 
$
59.67

 
$

 
$
32,421

 
$
29,259

 
$
(3,162
)
Forwards-short (Crude)
 
(150,108
)
 

 
71.29

 
(10,701
)
 
(10,744
)
 
(43
)
Forwards-long (Gasoline)
 
246,213

 
65.08

 

 
16,023

 
14,598

 
(1,425
)
Forwards-short (Gasoline)
 
(48,000
)
 

 
48.67

 
(2,336
)
 
(2,550
)
 
(214
)
Forwards-long (Distillate)
 
283,500

 
76.07

 

 
21,567

 
21,463

 
(104
)
Forwards-short (Distillate)
 
(104,935
)
 

 
71.71

 
(7,525
)
 
(7,817
)
 
(292
)
Forwards-long (Jet)
 
72,105

 
75.83

 

 
5,468

 
5,040

 
(428
)
Forwards-short (Jet)
 
(77,072
)
 

 
67.29

 
(5,186
)
 
(5,320
)
 
(134
)
Forwards-short (Slurry)
 
(17,193
)
 

 
43.64

 
(750
)
 
(645
)
 
105

Forwards-long (Catfeed)
 
159,989

 
64.98

 

 
10,396

 
9,821

 
(575
)
Forwards-short (Catfeed)
 
(30,448
)
 

 
64.98

 
(1,978
)
 
(2,067
)
 
(89
)
Forwards-long (Slop)
 
5,088

 
49.29

 

 
251

 
223

 
(28
)
Forwards-short (Slop)
 
(32,791
)
 

 
52.13

 
(1,709
)
 
(1,635
)
 
74

Forwards-short (Propane)
 
(30,922
)
 

 
22.42

 
(693
)
 
(611
)
 
82

Forwards-long (Asphalt)
 
14,097

 
84.34

 

 
1,189

 
1,069

 
(120
)
Forwards-short (Asphalt)
 
(22,739
)
 

 
13.43

 
(305
)
 
(226
)
 
79

Futures-long (Crude)
 
155,000

 
59.61

 

 
9,239

 
8,324

 
(915
)
Futures-short (Crude)
 
(362,000
)
 

 
64.88

 
(23,486
)
 
(19,284
)
 
4,202

Futures-long (Gasoline)
 
24,000

 
69.56

 

 
1,669

 
1,484

 
(185
)
Futures-short (Gasoline)
 
(356,000
)
 

 
68.17

 
(24,268
)
 
(22,011
)
 
2,257

Futures-long (Distillate)
 
25,000

 
101.42

 

 
2,536

 
1,926

 
(610
)
Futures-short (Distillate)
 
(237,000
)
 

 
82.04

 
(19,444
)
 
(18,252
)
 
1,192

 
 
 
 
 
 
 
 
 
 
 
 
 
Description of Activity
 
Contract Volume
(in barrels)
 
Wtd Avg Contract Spread
 
Wtd Avg
Market
Price
 
Contract Value
 
Market
Value
 
Gain (Loss)
 
 
 
 
 
 
 
 
(in thousands)
Futures-swaps (Jet-LLS)
 
(3,600,000
)
 
$
22.58

 
$
15.82

 
$
(81,270
)
 
$
(56,961
)
 
$
24,309

Futures-swaps (LLS-WTI)
 
6,210,000

 
3.18

 
2.35

 
22,369

 
15,904

 
(6,465
)
Futures-swaps (Brent-WTI)
 
(5,850,000
)
 
10.50

 
5.79

 
(61,555
)
 
(36,659
)
 
24,896

Interest Rate Risk
As of December 31, 2014, $439.7 million, excluding discounts, of our outstanding debt was subject to floating interest rates, of which $60.0 million was charged interest at the Eurodollar rate plus 3.50%, subject to a minimum interest rate of 4.00%, and $245.0 million was charged interest at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00%.
As of December 31, 2014, we had three interest rate swap contracts, maturing March 2019, that effectively fix the variable interest component on approximately 75% of the outstanding principal of the term loan within the Alon Retail Credit Agreement. As of December 31, 2014, the outstanding balance of the term loan was $102.7 million and the interest rate swaps had an average fixed interest rate of 0.25%.
An increase of 1% in the variable rate on our indebtedness, after considering the instruments subject to minimum interest rates and the interest rate swap contracts, would result in an increase to our interest expense of approximately $1.0 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.


56


ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES.
Disclosure Controls and Procedures
Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended (the “Exchange Act”)) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or furnish under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or furnish under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate “internal control over financial reporting” (as defined in Rule 13a-15(f) under the Exchange Act) for Alon. Our management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2014. In management’s evaluation, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (1992). Management believes that as of December 31, 2014, our internal control over financial reporting was effective based on those criteria. We are transitioning our assessment of our internal control effectiveness over financial reporting from the criteria outlined by the 1992 framework of the Committee of Sponsoring Organizations of the Treadway Commission to its 2013 framework. We expect to complete this transition during 2015.
The independent registered public accounting firm of KPMG LLP, as auditors of our consolidated financial statements, has issued an attestation report on the effectiveness of our internal control over financial reporting, included with the Consolidated Financial Statements as an annex of this Annual Report on Form 10-K.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the quarter ended December 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION.
None.


57


PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
The information concerning our directors set forth under “Corporate Governance Matters — The Board of Directors” in the proxy statement for our 2015 annual meeting of stockholders (the “Proxy Statement”) is incorporated herein by reference. Certain information concerning our executive officers is set forth under the heading “Business and Properties — Executive Officers of the Registrant” in Items 1 and 2 of this Annual Report on Form 10-K, which is incorporated herein by reference. The information concerning compliance with Section 16(a) of the Exchange Act set forth under “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement is incorporated herein by reference.
The information concerning our audit committee set forth under “Corporate Governance Matters — Committees of the Board and — Audit Committee” in the Proxy Statement is incorporated herein by reference.
The information regarding our Code of Ethics set forth under “Corporate Governance Matters — Corporate Governance Guidelines, Code of Business Conduct and Ethics and Committee Charters” in the Proxy Statement is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION.
The information set forth under “Executive Compensation” in the Proxy Statement is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The information set forth under “Security Ownership of Certain Beneficial Holders and Management” in the Proxy Statement is incorporated herein by reference. The information regarding our equity plans under which shares of our common stock are authorized for issuance as set forth under “Equity Compensation Plan Information” in the Proxy Statement is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
The information set forth under “Certain Relationships and Related Transactions” and under “Corporate Governance Matters — Independent Directors” in the Proxy Statement is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
The information set forth under “Independent Public Accountants” in the Proxy Statement is incorporated herein by reference.


58


PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
The following documents are filed as part of this report:
1.
Financial Statements. See “Index to Consolidated Financial Statements” on page F-1.
2.
Financial Statement Schedules and Other Financial Information. All financial statement schedules are omitted because either they are not applicable or the required information is included in the consolidated financial statements or notes included herein.
3.
Exhibits. Exhibits filed as part of this Form 10-K are as follows:

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


59


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


60


Exhibit No.
 
Description of Exhibit
10.24*
 
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).
10.25*
 
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).
10.26*
 
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).
10.27*
 
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).
10.28*
 
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).
10.29*
 
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).
10.30*
 
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).
10.31*
 
Management Employment Agreement, dated as of May 1, 2008, between Kyle C. McKeen and Alon USA GP, LLC (incorporated by reference to Exhibit 10.47 to Form 10-K, filed by the Company on March 14, 2013 SEC File No. 001-32567).
10.32*
 
Description of Annual Bonus Plans (incorporated by reference to Exhibit 10.56 to Form 10-K, filed by the Company on March 15, 2011 SEC File No. 001-32567).
10.33*
 
Change of Control Incentive Bonus Program (incorporated by reference to Exhibit 10.29 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.34*
 
Description of Director Compensation (incorporated by reference to Exhibit 10.30 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.35*
 
Form of Director Indemnification Agreement (incorporated by reference to Exhibit 10.31 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.36*
 
Form of Officer Indemnification Agreement (incorporated by reference to Exhibit 10.32 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.37*
 
Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.33 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.38*
 
Alon Assets, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.36 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.39*
 
Alon USA Operating, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.37 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.40*
 
Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.38 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.41
 
Second Amendment to Incentive Stock Option Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon Assets, Inc. (incorporated by reference to Exhibit 10.15 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
10.42*
 
Shareholder Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.39 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.43*
 
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).
10.44
 
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).


61


Exhibit No.
 
Description of Exhibit
10.45
 
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).
10.46*
 
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).
10.47
 
Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.42 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.48
 
Shareholder Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.43 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.49*
 
Amendment to Shareholder Agreements among the Company, Alon Assets, Inc., Alon Operating, Inc., Claire Hart and Claire Hart/IRA, dated June 20, 2012 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on June 26, 2012, SEC File No. 001-32567).
10.50
 
Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.44 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.51*
 
Shareholder Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.45 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.52
 
Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III, as amended by the Amendment to the Incentive Stock Option Agreement, dated July 25, 2002 (incorporated by reference to Exhibit 10.46 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.53*
 
Shareholder Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.47 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.54
 
Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III, as amended by the Amendment to the Incentive Stock Option Agreement, dated July 25, 2002 (incorporated by reference to Exhibit 10.48 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.55
 
Shareholder Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.49 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.56
 
Amendment to Shareholder Agreements – Option Shares, between Alon Assets, Inc., Alon Operating, Inc., Alon USA Energy, Inc. and Joseph A. Concienne, dated October 3, 2011 (incorporated by reference to Exhibit 10.68 to Form 10-K Filed by the Company on March13, 2012, SEC File No. 001-32567).
10.57*
 
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).
10.58*
 
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).
10.59*
 
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).
10.60*
 
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).
10.61*
 
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).
10.62*
 
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).


62


Exhibit No.
 
Description of Exhibit
10.63*
 
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).
10.64*
 
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).
10.65*
 
Award Agreement between the Company and Paul Eisman, dated May 5, 2011, (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 9, 2011, SEC File No. 001-32567).
10.66
 
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).
10.67
 
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).
10.68
 
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).
10.69
 
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).
10.70
 
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).
10.71
 
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).
10.72
 
Series A Preferred Stock Purchase Agreement, dated as of July 3, 2008, by and between Alon Refining Louisiana, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
10.73
 
Stockholders Agreement, dated as of July 3, 2008, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
10.74
 
Amended and Restated Stockholders Agreement dated as of March 31, 2009, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.88 to Form 10-K, filed by the Company on April 10, 2009, SEC File No. 001-32567).
10.75†
 
First Amendment to Amended and Restated Stockholders Agreement dated as of December 31, 2009, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 5, 2010, SEC File No. 001-32567).
10.76
 
Amended and Restated Supply and Offtake Agreement, dated May 26, 2010 by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.76 to Form 10-K, filed by the Company on March 14, 2014, SEC File No. 001-32567).
10.77
 
First Amendment to the Supply and Offtake Agreement, dated January 20, 2011, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 10, 2011, SEC File No. 001-32567).
10.78
 
Amended and Restated Second Amendment to the Supply and Offtake Agreement, dated March 1, 2011, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.3 to Form 10-Q, filed by the Company on May 10, 2011, SEC File No. 001-32567).
10.79†
 
Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on November 7, 2011, SEC File No. 001-32567).


63


Exhibit No.
 
Description of Exhibit
10.80
 
Amendment, dated as of July 20, 2012, to the Amended and Restated Supply and Offtake Agreement, dated May 26, 2010, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.80 to Form 10-K, filed by the Company on March 14, 2014, SEC File No. 001-32567).
10.81†
 
Amendment, dated as of February 1, 2013, to the Amended and Restated Supply and Offtake Agreement, dated May 26, 2010, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 10, 2013, SEC File No. 001-32567).
10.82
 
Amended and Restated Supply and Offtake Agreement by and between Alon USA, LP and J. Aron & Company, dated March 1, 2011 (incorporated by reference to Exhibit 10.82 to Form 10-K, filed by the Company on March 14, 2014, SEC File No. 001-32567).
10.83†
 
Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon USA, LP and J.Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on November 11, 2011, SEC File No. 001-32567).
10.84
 
Amendment, dated as of July 20, 2012, to the Amended and Restated Supply and Offtake Agreement by and between Alon USA, LP, and J. Aron & Company, dated March 1, 2011 (incorporated by reference to Exhibit 10.84 to Form 10-K, filed by the Company on March 14, 2014, SEC File No. 001-32567).
10.85†
 
Amendment to Supply and Offtake Agreement dated as of February 1, 2013 between J. Aron & Company and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on May 10, 2013, SEC File No. 001-32567).
10.86†
 
Supply and Offtake Agreement by and between J. Aron & Company and Alon Supply, Inc., dated May 30, 2012 (incorporated by reference to Exhibit 10.86 to Form 10-K, filed by the Company on March 14, 2014, SEC File No. 001-32567).
10.87
 
Amendment, dated as of July 20, 2012, to the Supply and Offtake Agreement, dated May 30, 2012, by and between Alon Supply, Inc., and J. Aron and Company (incorporated by reference to Exhibit 10.87 to Form 10-K, filed by the Company on March 14, 2014, SEC File No. 001-32567).
10.88
 
Amendment, dated as of February 1, 2013, to the Supply and Offtake Agreement between J. Aron & Company and Alon Supply, Inc. (incorporated by reference to Exhibit 10.3 to Form 10-Q, filed by the Company on May 10, 2013, SEC File No. 001-32567).
10.89
 
Form of Series A Convertible Preferred Stock Purchase Agreement (incorporated by reference to Exhibit 10.105 to Form S-1/A, filed by the Company on October 22, 2010, SEC File No. 333-169583).
10.90
 
Warrant Agreement, dated March 14, 2011, between the Company and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.106 to Form 10-K, filed by the Company on March 15, 2011 SEC File No. 001-32567).
10.91
 
Form of Series B Convertible Preferred Stock Purchase Agreement (incorporated by reference to Exhibit 10.106 to Form 10-K, filed by the Company on March 13, 2012 SEC File No. 001-32567).
10.92
 
Omnibus Agreement by and among Alon USA Partners, LP, Alon USA Partners GP, LLC, Alon Assets, Inc. and Alon Energy, Inc., dated November 26, 2012 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.93
 
Services Agreement by and among Alon USA Partners, LP, Alon USA Partners GP, LLC by and Alon Energy, Inc., dated November 26, 2012 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.94
 
Tax Sharing Agreement by and among Alon USA Partners, LP and Alon USA Energy, Inc., dated November 26, 2012 (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.95
 
Distributor Sales Agreement by and among Alon USA Partners, LP and Southwest Convenience Stores, LLC, dated November 26, 2012 (incorporated by reference to Exhibit 10.4 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.96
 
Offtake Agreement by and among Alon USA, LP and Paramount Petroleum Corporation, dated November 26, 2012 (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.97
 
Contribution, Conveyance and Assumption Agreement by and among Alon Assets, Inc., Alon USA Partners GP, LLC, Alon USA Partners, LP, Alon USA Energy, Inc., Alon USA Refining, LLC, Alon USA Operating, Inc., Alon USA, LP and Alon USA GP, LLC, dated November 26, 2012 (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.98
 
Second Amended Revolving Credit Agreement, dated as of May 23, 2013, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 24, 2013, SEC File No. 001-32567).


64


Exhibit No.
 
Description of Exhibit
10.99
 
Base Bond Hedge Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.100
 
Base Bond Hedge Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.101
 
Additional Bond Hedge Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.102
 
Additional Bond Hedge Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.4 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.103
 
Base Warrant Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.104
 
Base Warrant Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.105
 
Additional Warrant Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.7 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.106
 
Additional Warrant Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.8 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
21.1
 
Subsidiaries of Alon USA Energy, Inc.
23.1
 
Consent of KPMG LLP.
31.1
 
Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2
 
Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1
 
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
100
 
The following financial information from Alon USA Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014, formatted in XBRL (Extensible Business Reporting Language): (i) Balance Sheets, (ii) Statements of Operations, (iii) Statements of Comprehensive Income, (iv) Statement of Stockholders’ Equity, (v) Statements of Cash Flows and (vi) Notes to Financial Statements.
___________
*
Identifies management contracts and compensatory plans or arrangements.
Filed under confidential treatment request.


65


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, 2014 and 2013
 
F-4
Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012
 
F-5
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013, and 2012
 
F-6
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012
 
F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012
 
F-8
Notes to Consolidated Financial Statements
 
F-9




Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Alon USA Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Alon USA Energy, Inc. and subsidiaries as of December 31, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2014, 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, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 13, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Dallas, Texas
March 13, 2015



F-2


Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Alon USA Energy, Inc.:
We have audited Alon USA Energy, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Alon USA Energy, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Alon USA Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Alon USA Energy, Inc. and subsidiaries as of December 31, 2014 and 2013, 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, 2014, and our report dated March 13, 2015 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Dallas, Texas
March 13, 2015


F-3


ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except per share data)
 
As of December 31,
 
2014
 
2013
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
214,961

 
$
224,499

Accounts and other receivables, net
153,859

 
200,398

Income tax receivable
9,196

 
16,053

Inventories
122,803

 
128,770

Deferred income tax asset
11,228

 
13,045

Prepaid expenses and other current assets
26,315

 
18,629

Total current assets
538,362

 
601,394

Equity method investments
25,376

 
26,251

Property, plant and equipment, net
1,372,344

 
1,429,342

Goodwill
101,913

 
105,943

Other assets, net
162,879

 
82,210

Total assets
$
2,200,874

 
$
2,245,140

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
292,217

 
$
336,499

Accrued liabilities
104,391

 
120,858

Current portion of long-term debt
15,089

 
83,174

Total current liabilities
411,697

 
540,531

Other non-current liabilities
182,659

 
189,474

Long-term debt
548,598

 
529,074

Deferred income tax liability
384,142

 
360,657

Total liabilities
1,527,096

 
1,619,736

Commitments and contingencies (Note 21)

 

Stockholders’ equity:
 
 
 
Preferred stock, par value $0.01, 15,000,000 shares authorized; 68,180 shares issued and outstanding at December 31, 2014 and 2013
682

 
682

Common stock, par value $0.01, 150,000,000 shares authorized; 69,606,944 and 68,641,428 shares issued and outstanding at December 31, 2014 and 2013, respectively
696

 
686

Additional paid-in capital
517,127

 
509,170

Accumulated other comprehensive loss, net of tax
(8,458
)
 
(37,515
)
Retained earnings
126,851

 
124,936

Total stockholders’ equity
636,898

 
597,959

Non-controlling interest in subsidiaries
36,880

 
27,445

Total equity
673,778

 
625,404

Total liabilities and equity
$
2,200,874

 
$
2,245,140


The accompanying notes are an integral part of these consolidated financial statements.
F-4


ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(dollars in thousands, except per share data)

 
Year Ended December 31,
 
2014
 
2013
 
2012
Net sales (1)
$
6,779,456

 
$
7,046,381

 
$
8,017,741

Operating costs and expenses:
 
 
 
 
 
Cost of sales
6,002,270

 
6,325,088

 
7,149,385

Direct operating expenses
281,686

 
287,752

 
313,242

Selling, general and administrative expenses
170,139

 
168,172

 
161,401

Depreciation and amortization
124,063

 
125,494

 
121,929

Total operating costs and expenses
6,578,158

 
6,906,506

 
7,745,957

Gain (loss) on disposition of assets
274

 
9,558

 
(2,309
)
Operating income
201,572

 
149,433

 
269,475

Interest expense
(111,143
)
 
(94,694
)
 
(129,572
)
Equity earnings of investees
1,678

 
5,309

 
7,162

Other income (loss), net
674

 
218

 
(6,584
)
Income before income tax expense
92,781

 
60,266

 
140,481

Income tax expense
22,913

 
12,151

 
49,884

Net income
69,868

 
48,115

 
90,597

Net income attributable to non-controlling interest
31,411

 
25,129

 
11,463

Net income available to stockholders
$
38,457

 
$
22,986

 
$
79,134

Earnings per share, basic
$
0.56

 
$
0.33

 
$
1.29

Weighted average shares outstanding, basic (in thousands)
68,985

 
63,538

 
57,501

Earnings per share, diluted
$
0.55

 
$
0.32

 
$
1.24

Weighted average shares outstanding, diluted (in thousands)
69,373

 
64,852

 
63,917

Cash dividends per share
$
0.53

 
$
0.38

 
$
0.16

___________________________________
(1)
Includes excise taxes on sales by the retail segment of $75,409, $73,597 and $66,563 for the years ended December 31, 2014, 2013 and 2012, respectively.


The accompanying notes are an integral part of these consolidated financial statements.
F-5


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

 
Year Ended December 31,
 
2014
 
2013
 
2012
Net income
$
69,868

 
$
48,115

 
$
90,597

Other comprehensive income (loss):
 
 
 
 
 
Postretirement benefit plans:
 
 
 
 
 
Unrealized gain (loss) arising during the year related to:
 
 
 
 
 
Net actuarial gain (loss)
(16,498
)
 
15,610

 
(15,183
)
Curtailment

 
126

 

(Gain) loss reclassified to earnings

 
 
 
 
Amortization of net actuarial loss (1)
3,466

 
4,071

 
2,633

Amortization of prior service credit (1)
(364
)
 
(51
)
 
(51
)
Net gain (loss), before tax
(13,396
)
 
19,756

 
(12,601
)
Income tax expense (benefit)
(4,559
)
 
7,224

 
(4,602
)
Net gain (loss), net of tax
(8,837
)
 
12,532

 
(7,999
)
Interest rate derivatives designated as cash flow hedges:
 
 
 
 
 
Unrealized holding gain (loss) arising during period
(1,292
)
 

 
132

Loss reclassified to earnings - interest expense
54

 

 
4,065

Net gain (loss), before tax
(1,238
)
 

 
4,197

Income tax expense (benefit)
(458
)
 

 
1,469

Net gain (loss), net of tax
(780
)
 

 
2,728

Commodity contracts designated as cash flow hedges:
 
 
 
 
 
Unrealized holding gain (loss) arising during period
50,288

 
(9,475
)
 
(74,583
)
(Gain) loss reclassified to earnings - cost of sales

 
(22,021
)
 
76,097

Amortization of unrealized loss on de-designated cash flow hedges - cost of sales

15,572

 

 

Net gain (loss), before tax
65,860

 
(31,496
)
 
1,514

Income tax expense (benefit)
24,358

 
(11,644
)
 
546

Net gain (loss), net of tax
41,502

 
(19,852
)
 
968

Total other comprehensive income (loss), net of tax
31,885

 
(7,320
)
 
(4,303
)
Comprehensive income
101,753

 
40,795

 
86,294

Comprehensive income attributable to non-controlling interest
34,239

 
24,877

 
11,124

Comprehensive income attributable to stockholders
$
67,514

 
$
15,918

 
$
75,170

_________________
(1)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost, as further discussed in Note 14. Net periodic benefit cost is reflected in direct operating expenses and selling, general and administrative expenses in the consolidated statements of operations.


The accompanying notes are an integral part of these consolidated financial statements.
F-6


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, 2011
$
40,000

 
$
561

 
$
318,659

 
$
(26,483
)
 
$
63,273

 
$
396,010

 
$
(226
)
 
$
395,784

Stock compensation expense

 
4

 
4,629

 

 

 
4,633

 
(503
)
 
4,130

Dividends

 

 

 

 
(9,196
)
 
(9,196
)
 
(524
)
 
(9,720
)
Dividends of common stock on preferred stock

 
7

 
4,127

 

 
(4,892
)
 
(758
)
 

 
(758
)
Preferred stock issuance
30,000

 

 
9,270

 

 

 
39,270

 

 
39,270

Stock issuance costs

 

 
(10
)
 

 

 
(10
)
 

 
(10
)
Warrants retired

 

 
(10,988
)
 

 

 
(10,988
)
 

 
(10,988
)
Preferred stock conversion
(27,800
)
 
41

 
27,759

 

 

 

 

 

Alon USA Partners, LP initial public offering

 

 
90,576

 

 

 
90,576

 
26,608

 
117,184

Net income

 

 

 

 
79,134

 
79,134

 
11,463

 
90,597

Other comprehensive loss, net of tax

 

 

 
(3,964
)
 

 
(3,964
)
 
(339
)
 
(4,303
)
Balance at December 31, 2012
42,200

 
613

 
444,022

 
(30,447
)
 
128,319

 
584,707

 
36,479

 
621,186

Stock compensation expense

 
9

 
8,285

 

 

 
8,294

 
(1,279
)
 
7,015

Dividends

 

 

 

 
(24,081
)
 
(24,081
)
 
(886
)
 
(24,967
)
Dividends of common stock on preferred stock

 

 
1,984

 

 
(2,288
)
 
(304
)
 

 
(304
)
Stock issuance costs

 

 
(1,012
)
 

 

 
(1,012
)
 

 
(1,012
)
Equity component related to issuance of convertible notes, net of tax of $11,171

 

 
19,194

 

 

 
19,194

 

 
19,194

Convertible note hedge transactions, net of tax of $10,468

 

 
(17,987
)
 

 

 
(17,987
)
 

 
(17,987
)
Warrant transactions

 

 
13,230

 

 

 
13,230

 

 
13,230

Preferred stock conversion
(41,518
)
 
64

 
41,454

 

 

 

 

 

Distributions to non-controlling interest in the Partnership

 

 

 

 

 

 
(31,746
)
 
(31,746
)
Net income

 

 

 

 
22,986

 
22,986

 
25,129

 
48,115

Other comprehensive loss, net of tax

 

 

 
(7,068
)
 

 
(7,068
)
 
(252
)
 
(7,320
)
Balance at December 31, 2013
682

 
686

 
509,170

 
(37,515
)
 
124,936

 
597,959

 
27,445

 
625,404

Stock compensation expense

 
9

 
7,915

 

 

 
7,924

 
(428
)
 
7,496

Dividends

 

 

 

 
(36,483
)
 
(36,483
)
 
(1,134
)
 
(37,617
)
Preferred stock conversion

 
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


The accompanying notes are an integral part of these consolidated financial statements.
F-7


ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
 
Year Ended December 31,
 
2014
 
2013
 
2012
Cash flows from operating activities:
 
 
 
 
 
Net income
$
69,868

 
$
48,115

 
$
90,597

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
124,063

 
125,494

 
121,929

Stock compensation
7,496

 
7,015

 
4,130

Deferred income taxes
5,961

 
8,278

 
42,022

Equity earnings of investees, net of dividends

 
(3,266
)
 
(1,240
)
Amortization of debt issuance costs
3,759

 
4,496

 
6,296

Amortization of original issuance discount
6,306

 
4,300

 
2,570

Write-off of unamortized debt issuance costs
558

 
1,871

 
8,826

Write-off of unamortized original issuance discount
391

 
1,871

 
28,374

(Gain) loss on disposition of assets
(274
)
 
(9,558
)
 
2,309

Unrealized (gain) loss on commodity swaps
(3,778
)
 
(3,085
)
 
31,936

Changes in operating assets and liabilities:
 
 
 
 
 
Accounts and other receivables, net
77,658

 
(19,053
)
 
28,624

Income tax receivable
6,857

 
(15,547
)
 
2,516

Inventories
4,983

 
55,149

 
(36,647
)
Prepaid expenses and other current assets
(7,686
)
 
8,410

 
(10,946
)
Other assets, net
(27,506
)
 
6,042

 
(9,260
)
Accounts payable
(68,482
)
 
1,726

 
10,977

Accrued liabilities
3,733

 
(2,794
)
 
5,718

Other non-current liabilities
(10,249
)
 
(57,231
)
 
59,079

Net cash provided by operating activities
193,658

 
162,233

 
387,810

Cash flows from investing activities:
 
 
 
 
 
Capital expenditures
(88,429
)
 
(68,513
)
 
(93,901
)
Capital expenditures for turnarounds and catalysts
(62,473
)
 
(8,617
)
 
(11,460
)
Dividends from investees, net of equity earnings
1,472

 

 

Contribution to equity method investment
(597
)
 
(1,403
)
 

Proceeds from disposition of assets
41,032

 
27,092

 
381

Net cash used in investing activities
(108,995
)
 
(51,441
)
 
(104,980
)
Cash flows from financing activities:
 
 
 
 
 
Dividends paid to stockholders
(36,483
)
 
(24,081
)
 
(9,196
)
Dividends paid to non-controlling interest
(1,134
)
 
(886
)
 
(524
)
Distributions paid to non-controlling interest in the Partnership
(23,242
)
 
(31,746
)
 

Contributions from non-controlling interest in Alon USA Partners, LP

 

 
167,765

Equity issuance costs

 
(1,012
)
 
(10
)
Inventory agreement transactions
24,200

 
25,200

 

Deferred debt issuance costs
(2,284
)
 
(4,264
)
 
(17,512
)
Revolving credit facilities, net
(40,000
)
 
51,000

 
(259,341
)
Additions to long-term debt
145,000

 
150,000

 
427,500

Payments on long-term debt
(160,258
)
 
(151,575
)
 
(632,282
)
Proceeds from issuance of warrants

 
13,230

 

Payments for purchases of hedges on convertible debt

 
(28,455
)
 

Net cash used in financing activities
(94,201
)
 
(2,589
)
 
(323,600
)
Net increase (decrease) in cash and cash equivalents
(9,538
)
 
108,203

 
(40,770
)
Cash and cash equivalents, beginning of period
224,499

 
116,296

 
157,066

Cash and cash equivalents, end of period
$
214,961

 
$
224,499

 
$
116,296

Supplemental cash flow information:
 
 
 
 
 
Cash paid for interest, net of capitalized interest
$
106,065

 
$
85,329

 
$
84,492

Cash paid for income tax, net of refunds
$
10,957

 
$
18,184

 
$
5,498

Supplemental disclosure of non-cash activities:
 
 
 
 
 
Capital expenditures included in accounts payable and accrued liabilities
$

 
$
6,161

 
$

Financing activity — payment on long-term debt from issuance of preferred stock
$

 
$

 
$
(30,000
)

The accompanying notes are an integral part of these consolidated financial statements.
F-8

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except as noted)



(1)
Description and Nature of Business
As used in this report, unless otherwise specified, the terms “Alon,” “we,” “us” or “our” refer to Alon USA Energy, Inc. and its consolidated subsidiaries or to Alon USA Energy, Inc. or an individual subsidiary. The “Partnership,” as used in this report, refers to Alon USA Partners, LP and its consolidated subsidiaries.
We are engaged in the business of refining and marketing of petroleum products, primarily in the South Central, Southwestern and Western regions of the United States. Our business consists of three operating segments: (i) refining and marketing, (ii) asphalt and (iii) retail.
Refining and Marketing Segment. Our refining and marketing segment includes a sour crude oil refinery located in Big Spring, Texas, a light sweet crude oil refinery located in Krotz Springs, Louisiana and heavy crude oil refineries located in Paramount, Bakersfield and Long Beach, California (the “California refineries”). Our California refineries did not process crude oil in 2014 and 2013 due to the high cost of crude oil relative to product yield and low asphalt demand. Our refineries have a combined throughput capacity of approximately 217,000 barrels per day (“bpd”). We refine crude oil into petroleum products, including various grades of gasoline, diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum-based products, which are marketed primarily in the South Central, Southwestern and Western regions of the United States.
We own the Big Spring refinery and wholesale marketing operations through the Partnership. We market transportation fuels produced at the Big Spring refinery in West and Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in these regions as our “physically integrated system” because it supplies our Alon branded and unbranded distributors in these regions with motor fuels produced at our Big Spring refinery and distributed through a network of pipelines and terminals which we either own or have access to through leases or long-term throughput agreements.
We supply gasoline and diesel to 644 Alon branded retail sites, including our retail segment convenience stores. In 2014, approximately 58% of the gasoline and 29% of the diesel produced at our Big Spring refinery was transferred to our branded marketing business at prices substantially determined by wholesale market prices. Additionally, we license the use of the Alon brand name and provide credit card processing services to 73 licensed locations that are not under fuel supply agreements.
We market transportation fuel production from our Krotz Springs refinery through bulk sales and exchange channels. These bulk sales and exchange arrangements are entered into with various oil companies and traders and are transported to markets on the Mississippi River and the Atchafalaya River as well as to the Colonial Pipeline.
Asphalt Segment. We own or operate 10 asphalt terminals located in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Washington (Richmond Beach), Arizona (Phoenix and Flagstaff) and Nevada (Fernley) (50% interest) as well as through a 50% interest in Wright Asphalt Products Company, LLC (“Wright”), which specializes in patented ground tire rubber modified asphalt products. The operations in which we have a 50% interest are recorded under the equity method of accounting and the investments are included as part of total assets in the asphalt segment data.
We have an exclusive license to use advanced asphalt-blending technology in West Texas, Arizona, New Mexico and Colorado, and a non-exclusive license in Idaho, Montana, Nevada, North Dakota, Utah and Wyoming, with respect to asphalt produced at our Big Spring refinery, and a ground tire rubber (“GTR”) asphalt manufacturing process with respect to asphalt sold in California.
Asphalt produced by our Big Spring refinery is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude, which is intended to approximate wholesale market prices. We market asphalt primarily as paving asphalt to road and materials manufacturers and highway construction/maintenance contractors as GTR, polymer modified or emulsion asphalt. Sales of asphalt are seasonal with the majority of our sales occurring between May and October.
Retail Segment. Our retail segment operates 295 convenience stores located in Central and West Texas and New Mexico. These convenience stores typically offer various grades of gasoline, diesel fuel, 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.


F-9

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


(2)
Basis of Presentation and Certain Significant Accounting Policies
(a)
Basis of Presentation
The consolidated financial statements include the accounts of Alon USA Energy, Inc. and its consolidated subsidiaries. All significant intercompany balances and transactions have been eliminated.
(b)
Use of Estimates
These consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”), which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(c)
Revenue Recognition
Revenues from sales of refined products are earned and realized upon transfer of title to the customer based on the contractual terms of delivery (including payment terms and prices). Generally, title transfers at the refinery or terminal when the refined product is loaded into the common carrier pipelines, trucks or railcars (free on board origin). In some situations, title transfers at the customer’s destination (free on board destination).
We occasionally enter into refined product buy/sell arrangements, which involve linked purchases and sales related to refined product sales contracts entered into to address location, quality or grade requirements. These buy/sell transactions are included on a net basis in sales in the consolidated statements of operations and profits are recognized when the exchanged product is sold.
Revenues from our inventory financing agreements (Note 9) are reported on a gross basis as we are considered a principal in these agreements.
In the ordinary course of business, logistical and refinery production schedules necessitate the occasional sale of crude oil to third parties. All purchases and sales of crude oil are recorded net, in cost of sales in the consolidated statements of operations.
Excise taxes on sales by our retail segment are presented on a gross basis. Supplemental information regarding the amount of such taxes included in revenues are provided in a footnote on the face of the consolidated statements of operations. All other excise taxes are presented on a net basis in the consolidated statements of operations.
(d)
Cost Classifications
Refining and marketing cost of sales includes crude oil and other raw materials, inclusive of transportation costs, which include costs associated with our crude oil and product pipelines. Asphalt cost of sales includes costs of purchased asphalt, blending materials and transportation costs. Retail cost of sales includes motor fuels and merchandise. Retail fuel cost of sales represents the cost of purchased fuel, including transportation costs and associated excise taxes. Merchandise cost of sales includes the delivered cost of merchandise purchases, net of merchandise rebates and commissions. Cost of sales excludes depreciation and amortization, which is presented separately in the consolidated statements of operations.
Direct operating expenses, which relate to our refining and marketing and asphalt segments, include costs associated with the actual operations of our refineries and terminals, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs.
Selling, general and administrative expenses consist primarily of costs relating to the operations of the convenience stores, including labor, utilities, maintenance and retail corporate overhead costs. Refining and marketing and asphalt segments corporate overhead and marketing expenses are also included in selling, general and administrative expenses.
Interest expense includes interest expense on debt, letters of credit, financing costs associated with crude oil purchases, financing fees, and both the amortization and write-off of original issuance discount and deferred debt issuance costs but excludes capitalized interest. Original issuance discount and debt issuance costs are amortized over the term of the related debt using the effective interest method.
(e)
Cash and Cash Equivalents
All highly-liquid instruments with a maturity of three months or less at the time of purchase are considered to be cash equivalents. Cash equivalents are stated at cost, which approximates market value.


F-10

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


(f)
Accounts Receivable
Financial instruments that potentially subject us to concentration of credit risk consist primarily of trade accounts receivables. Credit is extended based on evaluation of the customer’s financial condition. We perform ongoing credit evaluations of our customers and require letters of credit, prepayments or other collateral or guarantees as management deems appropriate. Allowance for doubtful accounts is based on a combination of current sales and specific identification methods.
Credit risk is minimized as a result of the ongoing credit assessment of our customers and a lack of concentration in our customer base. Credit losses are charged to allowance for doubtful accounts when deemed uncollectible. Our allowance for doubtful accounts is reflected as a reduction of accounts receivable in the consolidated balance sheets.
(g)
Inventories
Crude oil, refined products, blendstocks and asphalt (including crude oil consignment inventory) are stated at the lower of cost or market in aggregate. Cost is determined using the last-in, first-out (“LIFO”) inventory valuation method and market is determined using current estimated selling prices. Under the LIFO valuation method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. An inventory write-down to market value results in a non-cash accounting adjustment, decreasing the value of our inventory and increasing our cost of sales. Such charges are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods.
Materials and supplies are stated at average cost. Cost for retail merchandise inventories is determined under the retail inventory method and cost for retail fuel inventories is determined under the first-in, first-out (“FIFO”) method.
Crude oil inventory consigned to others represents inventory that was sold to third parties, which we are obligated to repurchase at the end of the respective agreements (Note 9). As a result of this requirement to repurchase the inventory, no revenue was recorded on these transactions and the inventory volumes remain valued under the LIFO method.
(h)
Hedging Activity
All derivative instruments are recorded in the consolidated balance sheets as either assets or liabilities measured at their fair value. We consider all commodity forwards, futures, swaps and option contracts to be part of our risk management strategy. For commodity derivative contracts not designated as cash flow hedges, the net unrealized gains and losses for changes in fair value are recognized in cost of sales or in other income (loss), net on the consolidated statements of operations.
We selectively designate certain commodity derivative contracts and interest rate derivatives as cash flow hedges. The effective portion of the gains or losses associated with these derivative contracts designated and qualifying as cash flow hedges are initially recorded in accumulated other comprehensive income in the consolidated balance sheet and reclassified into the statement of operations in the period in which the underlying hedged forecasted transaction affects income. The amounts recorded into the consolidated statement of operations for commodity derivative contracts are recognized as cost of sales and the amounts recorded for interest rate derivatives are recognized as interest expense. The ineffective portion of the gains or losses on the derivative contracts, if any, is recognized in the consolidated statement of operations as it is incurred.
Derivative transactions related to our inventory financing agreements have been designated as fair value hedges of inventory. The gain or loss on the derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk, is recognized in earnings in the same period.
(i)
Property, Plant and Equipment
The carrying value of property, plant and equipment includes the fair value of the asset retirement obligation and has been reflected in the consolidated balance sheets at cost, net of accumulated depreciation.
Property, plant and equipment, net of salvage value, are depreciated using the straight-line method at rates based on the estimated useful lives for the assets or groups of assets, beginning in the first month of operation following acquisition or completion. The useful lives used to determine depreciation for our assets are as follows:
Refining facilities
3 – 20 years
Pipelines and terminals
5 – 25 years
Retail
5 – 40 years
Other
3 – 15 years


F-11

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


We capitalize interest costs associated with major construction projects based on the effective interest rate on aggregate borrowings. Leasehold improvements are depreciated on the straight-line method over the shorter of the contractual lease terms or the estimated useful lives.
Expenditures for major replacements and additions are capitalized. Refining and marketing segment and asphalt segment expenditures for routine repairs and maintenance costs are charged to direct operating expense as incurred. Retail segment routine repairs and maintenance costs are charged to selling, general and administrative expense as incurred. The applicable costs and accumulated depreciation of assets that are sold, retired, or otherwise disposed of are removed from the accounts and the resulting gain or loss is recognized as a gain or loss on disposition of assets in the consolidated statements of operations.
(j)
Impairment of Long-Lived Assets and Assets to be Disposed Of
We review long-lived assets and certain identifiable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of an asset to future net cash flows expected to be generated by the asset. If the carrying value of an asset exceeds its expected future cash flows, an impairment loss is recognized based on the excess of the carrying value of the impaired asset over its fair value. The future cash flows and fair values used in this assessment are estimates based on management’s judgment and assumptions. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs of disposition.
(k)
Asset Retirement Obligations
We have asset retirement obligations with respect to our refineries due to various legal obligations to clean and/or dispose of these assets at the time they are retired. However, the majority of these assets can be used for extended and indeterminate periods of time provided that they are properly maintained and/or upgraded. It is our practice and intent to continue to maintain these assets and make improvements based on technological advances. When a date or range of dates can reasonably be estimated for the retirement of these assets or any component part of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using established present value techniques.
We also have asset retirement obligations with respect to the removal of underground storage tanks and the removal of brand signage at our owned and leased retail sites. The asset retirement obligation for storage tank removal on leased retail sites is accreted over the expected life of the underground storage tank, which approximates the average retail site lease term (Note 13).
(l)
Turnarounds and Catalysts Costs
Our refinery units require regular major maintenance and repairs that are commonly referred to as “turnarounds.” Catalysts used in certain refinery process units are typically replaced in conjunction with planned turnarounds. We record the turnaround and catalysts costs as deferred charges in other assets in the consolidated balance sheets. We amortize the deferred costs on a straight-line basis over the period of time estimated until the next turnaround occurs, beginning the month after the completion of the turnaround. The amortization of deferred turnaround and catalysts costs are presented in depreciation and amortization in our consolidated statements of operations.
(m)
Income Taxes
We account for income taxes under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
(n)
Stock-Based Compensation
Our stock-based compensation plan includes granting of awards in the form of options to purchase common stock, stock appreciation rights, restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses to our directors, officers and key employees. We use the grant date fair value based method for calculating and accounting for stock-based compensation. Expenses related to stock-based compensation are included in selling, general and administrative expenses in our consolidated statements of operations (Note 17).
(o)
Environmental Expenditures
Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for


F-12

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Environmental liabilities represent the estimated costs to investigate and remediate contamination at our properties. These estimates are based on internal and third-party assessments of the extent of the contaminations, the selected remediation technology and review of applicable environmental regulations.
Costs of future expenditures for environmental remediation obligations are not discounted to their present value unless payments are fixed or reliably determinable. Recoveries of environmental remediation costs from other parties are recorded as assets when the receipt is deemed probable (Note 21). Estimates are updated to reflect changes in factual information, available technology or applicable laws and regulations.
Substantially all amounts accrued are expected to be paid out over the next 15 years. The amount of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.
(p)
Earnings Per Share
We compute basic earnings per share by dividing net income available to common stockholders by the weighted average number of participating common shares outstanding during the reporting period. Diluted earnings per share are calculated to give effect to all potentially dilutive common shares that were outstanding during the period (Note 19).
(q)
Other Comprehensive Income
Comprehensive income consists of net income and other gains and losses affecting stockholders’ equity that, under U.S. GAAP, are excluded from net income, such as defined postretirement benefit plan adjustments and gains and losses related to certain derivative instruments designated in qualifying hedging relationships. The balance in accumulated other comprehensive loss, net of tax reported in the consolidated balance sheets consists of defined postretirement benefit plans and the fair value of interest rate derivatives and commodity derivative contract adjustments.
(r)
Postretirement Benefits
We recognize the underfunded status of our defined pension and postretirement plans as a liability. Changes in the funded status of our defined pension and postretirement plans are recognized in other comprehensive income in the period the changes occur. The funded status represents the difference between the projected benefit obligation and the fair value of the plan assets. The projected benefit obligation is the present value of benefits earned to date by plan participants, including the effect of assumed future salary increases. Plan assets are measured at fair value. We use December 31 as the measurement date for plan assets and obligations for all of our plans.
(s)
Commitments and Contingencies
Liabilities for loss contingencies, arising from claims, assessments, litigation, fines and penalties and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recorded as assets, and are not offset against the related environmental liability.
(t)
Goodwill and Intangibles
Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over 1 to 40 years. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. We use December 31 of each year as the valuation date for annual impairment testing purposes.
(u)
New Accounting Standards
In May 2014, the Financial Accounting Standards Board (“FASB”) and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard that provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. This standard is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. The requirements from the new standard are effective for interim and annual periods beginning after December 15, 2016, and early adoption is not permitted. The standard allows for either full retrospective adoption or modified retrospective adoption. We are evaluating the guidance to determine the method of adoption and the impact of this standard on our consolidated financial statements.


F-13

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


In February 2015, the FASB issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the way certain decisions are made related to substantive rights, related parties, and decision making fees when applying the variable interest entity consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. We are evaluating the effect that adopting the updated guidance will have on our consolidated financial statements and related disclosures.
(3)
Alon USA Partners, LP
The Partnership is a publicly traded limited partnership that was formed to own and operate the assets and operations of the Big Spring refinery and associated wholesale marketing operations. On November 26, 2012, the Partnership completed its initial public offering (NYSE: ALDW) of 11,500,000 common units representing limited partner interests. As of December 31, 2014, the 11,506,550 common units held by the public represent 18.4% of the Partnership’s common units outstanding. We own the remaining 81.6% of the Partnership’s common units and Alon USA Partners GP, LLC (the “General Partner”), our wholly-owned subsidiary, owns 100% of the non-economic general partner interest in the Partnership.
The limited partner interests in the Partnership not owned by us are reflected in the consolidated statements of operations in net income attributable to non-controlling interest and in our consolidated balance sheets in non-controlling interest in subsidiaries. The Partnership is consolidated within the refining and marketing segment.
We have agreements with the Partnership which establish fees for certain administrative and operational services provided by us and our subsidiaries to the Partnership, provide certain indemnification obligations and other matters and establish terms for the supply of products by the Partnership to us.
Partnership Distributions
The Partnership has adopted a policy pursuant to which it will distribute all of the available cash it generates each quarter, as defined in the partnership agreement and subject to the approval of the board of directors of the General Partner. The per unit amount of available cash to be distributed each quarter, if any, will be distributed within 60 days following the end of such quarter.
During the year ended December 31, 2014, the Partnership paid cash distributions of $126,262, or $2.02 per unit. The total cash distribution paid to non-affiliated common unitholders was $23,242. During the year ended December 31, 2013, the Partnership paid cash distributions of $172,506, or $2.76 per unit. The total cash distribution paid to non-affiliated common unitholders was $31,746. As the initial public offering was completed in November 2012, no cash distributions were paid during the year ended December 31, 2012.
(4)
Segment Data
Our revenues are derived from three operating segments: (i) refining and marketing, (ii) asphalt and (iii) retail. The reportable operating segments are strategic business units that offer different products and services. The segments are managed separately as each segment requires unique technology, marketing strategies and distinct operational emphasis. Each operating segment’s performance is evaluated primarily based on operating income.
Operating income (loss) for each segment consists of net sales less cost of sales, direct operating expenses, selling, general and administrative expenses, depreciation and amortization and gain (loss) on disposition of assets. Intersegment sales are intended to approximate wholesale market prices. Consolidated totals presented are after intersegment eliminations.
Operations that are not included in any of the three segments are included in the corporate category. These operations consist primarily of corporate headquarters operating and depreciation expenses.
Total assets of each segment consist of net property, plant and equipment, inventories, cash and cash equivalents, accounts and other receivables, goodwill and other assets directly associated with the segment’s operations. Corporate assets consist primarily of corporate headquarters information technology and administrative equipment.


F-14

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


Segment data as of and for the years ended December 31, 2014, 2013 and 2012 are presented below:
 
Refining and
Marketing
 
Asphalt
 
Retail
 
Corporate
 
Consolidated
Total
Year ended December 31, 2014
 
 
 
 
 
 
 
 
 
Net sales to external customers
$
5,382,360

 
$
457,412

 
$
939,684

 
$

 
$
6,779,456

Intersegment sales/purchases
555,622

 
(59,615
)
 
(496,007
)
 

 

Depreciation and amortization
104,676

 
4,747

 
12,241

 
2,399

 
124,063

Operating income (loss)
204,609

 
(25,597
)
 
25,665

 
(3,105
)
 
201,572

Total assets
1,851,344

 
110,139

 
216,679

 
22,712

 
2,200,874

Turnarounds, catalysts and capital expenditures
125,621

 
5,777

 
16,748

 
2,756

 
150,902

 
Refining and
Marketing
 
Asphalt
 
Retail
 
Corporate
 
Consolidated
Total
Year ended December 31, 2013
 
 
 
 
 
 
 
 
 
Net sales to external customers
$
5,489,745

 
$
612,443

 
$
944,193

 
$

 
$
7,046,381

Intersegment sales/purchases
600,943

 
(86,089
)
 
(514,854
)
 

 

Depreciation and amortization
105,597

 
6,398

 
10,826

 
2,673

 
125,494

Operating income (loss)
133,020

 
(4,097
)
 
23,904

 
(3,394
)
 
149,433

Total assets
1,871,255

 
154,143

 
197,966

 
21,776

 
2,245,140

Turnarounds, catalysts and capital expenditures
48,889

 
9,425

 
17,935

 
881

 
77,130

 
Refining and
Marketing
 
Asphalt
 
Retail
 
Corporate
 
Consolidated
Total
Year ended December 31, 2012
 
 
 
 
 
 
 
 
 
Net sales to external customers
$
6,505,927

 
$
603,896

 
$
907,918

 
$

 
$
8,017,741

Intersegment sales/purchases
736,008

 
(244,010
)
 
(491,998
)
 

 

Depreciation and amortization
103,638

 
5,866

 
10,298

 
2,127

 
121,929

Operating income (loss)
254,372

 
(3,728
)
 
21,918

 
(3,087
)
 
269,475

Total assets
1,859,600

 
139,891

 
202,033

 
22,050

 
2,223,574

Turnarounds, catalysts and capital expenditures
79,572

 
9,420

 
14,141

 
2,228

 
105,361

(5)
Fair Value
We determine fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We classify financial assets and financial liabilities into the following fair value hierarchy:
Level 1 -     valued based on quoted prices in active markets for identical assets and liabilities;
Level 2 -     valued based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability; and
Level 3 -     valued based on unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
As required, we utilize valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy. We generally apply the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.
The carrying amounts of our cash and cash equivalents, receivables, payables and accrued liabilities approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of long-term debt approximate fair value. Derivative instruments are carried at fair value, which are based on quoted market prices. Derivative instruments and the Renewable Identification Numbers (“RINs”) obligation are our only assets and liabilities measured at fair value on a recurring basis.


F-15

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


The RINs obligation represents the period-end deficit, if any, after considering any RINs acquired or under contract, necessary to meet our requirements to blend biofuels into the products we have produced. The RINs obligation is categorized as level 2 in the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.
The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the consolidated balance sheets as of December 31, 2014 and 2013:
 
Level 1
 
Level 2
 
Level 3
 
Total
As of December 31, 2014
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts (swaps)
$

 
$
42,740

 
$

 
$
42,740

Fair value hedges

 
24,903

 

 
24,903

Liabilities:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
333

 

 

 
333

Interest rate swaps

 
1,238

 

 
1,238

 
 
 
 
 
 
 
 
As of December 31, 2013
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
335

 
$

 
$

 
$
335

Liabilities:
 
 
 
 
 
 
 
Commodity contracts (swaps)

 
15,328

 
11,569

 
26,897

Fair value hedges

 
3,339

 

 
3,339

RINs obligation

 
334

 

 
334

Level 3 Financial Instruments
As of December 31, 2013, we had commodity price swap contracts related to forecasted sales of jet fuel and forecasted purchases of crude oil for which quoted forward market prices were not readily available. The forward rate used to value these commodity price swaps was derived using a projected forward rate using quoted market rates for similar products, adjusted for product grade differentials, a level 3 input. In January 2014, quoted forward market prices for these commodities became available, and the related financial liability was reclassified to level 2.
The following table presents the changes in fair value of our level 3 assets and liabilities (all related to commodity price swap contracts) for the years ended December 31, 2014 and 2013:
 
 
Year Ended December 31,
 
 
2014
 
2013
Balance at beginning of period
 
$
(11,569
)
 
$

Change in fair value of level 3 trades open at the beginning of the period
 

 

Fair value of trades entered into during the period - Recognized in other comprehensive income
 

 
(11,569
)
Fair value of reclassification from level 3 to level 2
 
11,569

 

Settlement value of contractual maturities - Recognized in cost of sales
 

 

Balance at end of period
 
$

 
$
(11,569
)
(6)
Derivative Financial Instruments
We selectively utilize crude oil and refined product commodity derivative contracts to reduce the risk associated with potential price changes on committed obligations as well as to reduce earnings volatility. We also utilize interest rate swaps to manage our exposure to interest rate risk. We do not speculate using derivative instruments. Credit risk on our derivative instruments is mitigated by transacting with counterparties meeting established collateral and credit criteria.


F-16

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


Mark to Market
We have certain contracts that serve as economic hedges, which are derivatives used for risk management but not designated as hedges for financial accounting purposes. All economic hedge transactions are recorded at fair value and any changes in fair value between reporting periods are recognized in earnings.
We have contracts that are used to fix prices on forecasted purchases of inventory. 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 executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period.
We also have economic hedges in the form of swap contracts that fix the price differential between Brent crude oil and the crude oil that we process at our refineries. At December 31, 2014, we have swap contracts for 6,210 thousand barrels of crude oil, with contract terms through December 2016.
Fair Value Hedges
Fair value hedges are used to hedge price volatility of certain refining inventories and firm commitments to purchase inventories. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk, is recognized in earnings in the same period.
We have certain commodity contracts associated with the Supply and Offtake Agreements discussed in Note 9 that have been accounted for as fair value hedges, which had contract purchase volumes of 736 thousand barrels of crude oil as of December 31, 2014.
Cash Flow Hedges
To designate a derivative as a cash flow hedge, we document at the inception of the hedge the assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the hedged item. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the hedged item. If, during the term of the derivative, the hedge is determined to be no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings when the underlying transactions occur.
Commodity Derivatives. As of December 31, 2014, we have accounted for certain commodity swap contracts as cash flow hedges with net contract purchase volumes of 3,600 thousand barrels of crude and net contract sales volumes of 3,600 thousand barrels of refined products with the longest remaining contract term of twelve months. Related to our commodity swap cash flow hedges in other comprehensive income (“OCI”), we recognized unrealized gains (losses) of $65,860, $(31,496) and $1,514 for the years ended December 31, 2014, 2013 and 2012, respectively.
In November 2013 and April 2014, we elected to de-designate certain commodity swap contracts that were previously designated as cash flow hedges. Net unrealized losses of $15,572, deferred in OCI as a result of de-designation, were fully amortized into earnings as the underlying transactions occurred during the year ended December 31, 2014.
Interest Rate Derivatives. In April 2014, we entered into three interest rate swap agreements, maturing March 2019, that effectively fix the variable LIBOR interest component of the term loan feature of the Alon Retail Credit Agreement, as defined in Note 15. The interest rate swaps have been accounted for as cash flow hedges. The aggregate notional amount under these agreements covers approximately 75% of the outstanding principal of the term loan throughout the duration of the interest rate swaps. As of December 31, 2014, the outstanding principal of the term loan was $102,667. The interest rate swaps lock in an average fixed interest rate of 0.60% in 2015; 1.47% in 2016; 2.35% in 2017; 3.09% in 2018 and 3.28% in 2019. Related to these interest rate swap cash flow hedges, we recognized in OCI unrealized losses of $(1,238) for the year ended December 31, 2014. Related to previously expired interest rate swap agreements, we recognized in OCI unrealized gains of $4,197 for the year ended December 31, 2012.
For the years ended December 31, 2014 and 2012, there was no hedge ineffectiveness recognized in income. For the year ended December 31, 2013, there was $1,879 of hedge ineffectiveness recognized in cost of sales. For the years ended December 31, 2014, 2013 and 2012, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.
As of December 31, 2014, we have net unrealized gains of $34,640 classified in OCI related to cash flow hedges. Assuming commodity prices and interest rates remain unchanged, unrealized gains of $35,688 will be reclassified from OCI into earnings as the underlying transactions occur over the next twelve-month period.


F-17

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


The following tables present the effect of derivative instruments on the consolidated balance sheets:
 
As of December 31, 2014
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet
 
 
 
Balance Sheet
 
 
 
Location
 
Fair Value
 
Location
 
Fair Value
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
Accounts receivable
 
$
7,168

 
Accrued liabilities
 
$
7,501

Commodity contracts (swaps)
Accounts receivable
 
6,809

 
 
 

Commodity contracts (swaps)
Other assets
 
11,622

 
 
 

Total derivatives not designated as hedging instruments
 
 
25,599

 
 
 
7,501

 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (swaps)
Accounts receivable
 
$
24,309

 
 
 
$

Interest rate swaps
 
 

 
Other non-current liabilities
 
1,238

Fair value hedges
Other assets
 
24,903

 
 
 

Total derivatives designated as hedging instruments
 
 
49,212

 
 
 
1,238

Total derivatives
 
 
$
74,811

 
 
 
$
8,739

 
As of December 31, 2013
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet
 
 
 
Balance Sheet
 
 
 
Location
 
Fair Value
 
Location
 
Fair Value
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
Accounts receivable
 
$
1,533

 
Accrued liabilities
 
$
1,198

Total derivatives not designated as hedging instruments
 
 
1,533

 
 
 
1,198

 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
 
$

 
Accrued liabilities
 
$
15,328

Commodity contracts (swaps)
 
 

 
Other non-current liabilities
 
11,569

Fair value hedges
 
 

 
Other non-current liabilities
 
3,339

Total derivatives designated as hedging instruments
 
 

 
 
 
30,236

Total derivatives
 
 
$
1,533

 
 
 
$
31,434



F-18

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


The following tables present the effect of derivative instruments on the consolidated statements of operations and accumulated other comprehensive income:
Derivatives designated as hedging instruments:
Cash Flow Hedging Relationships
 
Gain (Loss) Recognized
in OCI
 
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
 
Gain (Loss) Reclassified
from Accumulated OCI into
Income (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)
 
 
 
 
Location
 
Amount
 
Location
 
Amount
For the Year Ended December 31, 2014
 
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
$
65,860

 
Cost of sales
 
$
(15,572
)
 
 
 
$

Interest rate swaps
 
(1,238
)
 
Interest expense
 
(54
)
 
 
 

Total derivatives
 
$
64,622

 
 
 
$
(15,626
)
 
 
 
$

 
 
 
 
 
 
 
 
 
 
 
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
$
(31,496
)
 
Cost of sales
 
$
23,900

 
Cost of sales
 
$
(1,879
)
Total derivatives
 
$
(31,496
)
 
 
 
$
23,900

 
 
 
$
(1,879
)
 
 
 
 
 
 
 
 
 
 
 
For the Year Ended December 31, 2012
 
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
$
1,514

 
Cost of sales
 
$
(76,097
)
 
 
 
$

Interest rate swaps
 
4,197

 
Interest expense
 
(4,065
)
 
 
 

Total derivatives
 
$
5,711

 
 
 
$
(80,162
)
 
 
 
$

Derivatives in fair value hedging relationships:
 
 
 
Gain (Loss) Recognized in Income
 
 
 
Year Ended December 31,
 
Location
 
2014
 
2013
 
2012
Fair value hedges (1)
Interest expense
 
$
28,242

 
$
(1,619
)
 
$
(1,720
)
Total derivatives
 
 
$
28,242

 
$
(1,619
)
 
$
(1,720
)
___________
(1)
Changes in the fair value hedges are substantially offset by changes in the hedged items.
Derivatives not designated as hedging instruments:
 
 
 
Gain (Loss) Recognized in Income
 
 
 
Year Ended December 31,
 
Location
 
2014
 
2013
 
2012
Commodity contracts (futures and forwards)
Cost of sales
 
$
(18,950
)
 
$
8,359

 
$
15,640

Commodity contracts (swaps)
Cost of sales
 
20,232

 
4,964

 
(54,011
)
Commodity contracts (call options)
Other income (loss), net
 

 

 
(7,297
)
Total derivatives
 
 
$
1,282

 
$
13,323

 
$
(45,668
)


F-19

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


Offsetting Assets and Liabilities
Our derivative instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives, and we offset the fair value amounts recorded for derivative instruments to the extent possible under these agreements on our consolidated balance sheets.
The following table presents offsetting information regarding our derivatives by type of transaction as of December 31, 2014 and 2013:
 
Gross Amounts of Recognized Assets/ Liabilities
 
Gross Amounts offset in the Statement of Financial Position
 
Net Amounts Presented in the Statement of Financial Position
 
Gross Amounts Not offset in the Statement of Financial Position
 
Net Amount
 
 
 
Financial Instruments
 
Cash Collateral Pledged
 
As of December 31, 2014
 
 
 
 
 
 
 
 
 
 
Derivative Assets:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
8,508

 
$
(1,340
)
 
$
7,168

 
$
(7,168
)
 
$

 
$

Commodity contracts (swaps)
49,204

 
(6,464
)
 
42,740

 

 

 
42,740

Fair value hedges
24,903

 

 
24,903

 

 

 
24,903

Derivative Liabilities:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
8,841

 
$
(1,340
)
 
$
7,501

 
$
(7,168
)
 
$

 
$
333

Commodity contracts (swaps)
6,464

 
(6,464
)
 

 

 

 

Interest rate swaps
1,238

 

 
1,238

 

 

 
1,238

 
 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2013
 
 
 
 
 
 
 
 
 
 
Derivative Assets:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
2,287

 
$
(754
)
 
$
1,533

 
$
(1,198
)
 
$

 
$
335

Derivative Liabilities:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
1,952

 
$
(754
)
 
$
1,198

 
$
(1,198
)
 
$

 
$

Commodity contracts (swaps)
26,897

 

 
26,897

 

 

 
26,897

Fair value hedges
3,339

 

 
3,339

 

 

 
3,339

Compliance Program Market Risk
We are obligated by government regulations to blend a certain percentage of biofuels into the products that we produce and are consumed in the U.S. We purchase biofuels from third parties and blend those biofuels into our products, and each gallon of biofuel purchased includes a renewable identification number, or RIN. To the degree we are unable to blend biofuels at the required percentage, a RINs deficit is generated and we must acquire that number of RINs by the annual reporting deadline in order to remain in compliance with applicable regulations. Alternatively, if we have a RINs surplus, some of those RINs could be sold. Any such sales would be subject to our normal credit evaluation process.
We are exposed to market risk related to the volatility in the price of credits needed to comply with these governmental and regulatory programs. We manage this risk by purchasing RINs when prices are deemed favorable utilizing fixed price purchase contracts. Some of these contracts are derivative instruments; however, we elect the normal purchase and sale exception and do not record these contracts at their fair values.
The cost of meeting our obligations under these compliance programs was $27,110 and $14,917 for the years ended December 31, 2014 and 2013, respectively. These amounts are reflected in cost of sales in the consolidated statements of operations. We were not subject to the renewable fuel standards requirements for the year ended December 31, 2012.


F-20

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


(7)
Accounts and Other Receivables
Financial instruments that potentially subject us to concentration of credit risk consist primarily of trade accounts receivables. Credit risk is minimized as a result of the ongoing credit assessment of our customers and a lack of concentration in our customer base. We perform ongoing credit evaluations of our customers and require letters of credit, prepayments or other collateral or guarantees as management deems appropriate. J. Aron & Company (“J. Aron”) accounted for more than 10% of our net sales for the years ended December 31, 2014 and 2013. Valero Energy Corporation and J. Aron each accounted for more than 10% of our net sales for the year ended December 31, 2012. The allowance for doubtful accounts is reflected as a reduction of accounts and other receivables in the consolidated balance sheets.
Accounts and other receivables, net consisted of the following:
 
As of December 31,
 
2014
 
2013
Trade accounts receivable
$
99,207

 
$
182,190

Other receivables
55,413

 
18,669

Allowance for doubtful accounts
(761
)
 
(461
)
Total accounts and other receivables, net
$
153,859

 
$
200,398

The following table sets forth the allowance for doubtful accounts for the years ended December 31, 2014, 2013 and 2012:
 
Balance at
Beginning of
Period
 
Additions
Charged to
Expense
 
Deductions
 

Balance at End
of Period
2014
$
461

 
300

 

 
$
761

2013
$
583

 
175

 
(297
)
 
$
461

2012
$
437

 
146

 

 
$
583

(8)
Inventories
Carrying value of inventories consisted of the following:
 
As of December 31,
 
2014
 
2013
Crude oil, refined products, asphalt and blendstocks
$
48,027

 
$
34,326

Crude oil consignment inventory (Note 9)
18,350

 
44,081

Materials and supplies
22,269

 
21,685

Store merchandise
27,418

 
20,526

Store fuel
6,739

 
8,152

Total inventories
$
122,803

 
$
128,770

Reductions of inventory volumes during 2013 and 2012 resulted in a liquidation of LIFO inventory layers. The liquidation increased cost of sales by $1,455 during 2013 and decreased cost of sales by $13,572 during 2012. There were no liquidations of LIFO inventory layers during 2014.
Market values of crude oil, refined products, asphalt and blendstock inventories exceeded LIFO costs by $8,341 and $61,199 at December 31, 2014 and 2013, respectively.
(9)
Inventory Financing Agreements
We have entered into Supply and Offtake Agreements and other associated agreements (together the “Supply and Offtake Agreements”) with J. Aron to support the operations of our Big Spring, Krotz Springs and California refineries and most of our asphalt terminals. Pursuant to the Supply and Offtake Agreements, (i) J. Aron agreed to sell to us, and we agreed to buy from J. Aron, at market prices, crude oil for processing at the refineries and (ii) we agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at the refineries.


F-21

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


The Supply and Offtake Agreements also provided for the sale, at market prices, of our crude oil and certain refined product inventories to J. Aron, the lease to J. Aron of crude oil and refined product storage facilities, and to identify prospective purchasers of refined products on J. Aron’s behalf. The Supply and Offtake Agreements have initial terms that expire in May 2019. J. Aron may elect to terminate the Supply and Offtake Agreements prior to the expiration of the initial term beginning in May 2016 and upon each anniversary thereof, on six months prior notice. We may elect to terminate in May 2018 on six months prior notice.
In February 2015, the Supply and Offtake Agreements for the Big Spring and Krotz Springs refineries were amended and the initial term was extended to May 2021. J. Aron may elect to terminate the Supply and Offtake Agreements for the Big Spring and Krotz Springs refineries prior to the expiration of the initial term beginning in May 2018 and upon each anniversary thereof, on six months prior notice. We may elect to terminate in May 2020 on six months prior notice.
Following expiration or termination of the Supply and Offtake Agreements, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the leased storage facilities at market prices at that time.
Associated with the Supply and Offtake Agreements, we have fair value hedges of our inventory purchase commitments with J. Aron and crude oil inventory consigned to J. Aron (“crude oil consignment inventory”). Additionally, financing charges related to the Supply and Offtake Agreements are recorded as interest expense in the consolidated statements of operations.
In association with the Supply and Offtake Agreement at the Krotz Springs refinery, we had a secured Credit Agreement (the “Krotz Springs Standby LC Facility”) by and between Alon, as Borrower, and Goldman Sachs Bank USA, as Issuing Bank. The Krotz Springs Standby LC Facility provided for up to $200,000 of letters of credit to be issued to J. Aron. As of December 31, 2013, there was no further availability under the Krotz Springs Standby LC Facility. In November 2014, we amended the Supply and Offtake Agreement to remove the requirement to maintain a standby letter of credit and the Krotz Springs Standby LC Facility was terminated.
In connection with the Supply and Offtake Agreement for our Krotz Springs refinery, we have granted a security interest to J. Aron in all of its accounts and inventory to secure its obligations to J. Aron. In addition, we have granted a security interest in all of its real property and equipment to J. Aron to secure its obligations under a commodity hedge and sale agreement in lieu of posting cash collateral and being subject to cash margin calls.
At December 31, 2014 and 2013, we had net current payables to J. Aron for purchases of $46,303 and $16,917, respectively, and a consignment inventory receivable representing a deposit paid to J. Aron of $26,179 and $26,179, respectively. Additionally, at December 31, 2014 and 2013, we had non-current liabilities for the original financing of $39,060 and $67,889, respectively, net of the related fair value hedges.
Additionally, we had net current payables of $4,212 and $539 at December 31, 2014 and 2013, respectively, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.
(10)
Property, Plant and Equipment, Net
Property, plant and equipment, net consisted of the following:
 
As of December 31,
 
2014
 
2013
Refining facilities
$
1,820,565

 
$
1,804,445

Pipelines and terminals
43,439

 
43,445

Retail
200,354

 
184,858

Other
17,988

 
15,326

Property, plant and equipment, gross
2,082,346

 
2,048,074

Accumulated depreciation
(710,002
)
 
(618,732
)
Property, plant and equipment, net
$
1,372,344

 
$
1,429,342

Depreciation expense for the years ended December 31, 2014, 2013 and 2012 was $106,623, $107,845 and $103,134, respectively.


F-22

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


Disposition of Assets
In January 2014, we sold our Willbridge, Oregon asphalt terminal for $40,000. The terminal was included in our asphalt segment and allocated goodwill of $4,030. For the year ended December 31, 2014, a pre-tax gain of $1,943 was recognized and has been included in gain (loss) on disposition of assets in our consolidated statements of operations.
(11)
Goodwill
The following table provides a summary of changes to our goodwill balance by segment for the year ended December 31, 2014:
 
 
Refining and Marketing
 
Asphalt
 
Retail
 
Total
Balance at December 31, 2013
 
$
39,028

 
$
16,726

 
$
50,189

 
$
105,943

Disposition of assets with allocated goodwill
 

 
(4,030
)
 

 
(4,030
)
Balance at December 31, 2014
 
$
39,028

 
$
12,696

 
$
50,189

 
$
101,913

During the year ended December 31, 2014, we sold our Willbridge, Oregon asphalt terminal, which was allocated goodwill of $4,030 at the time of disposition.
(12)
Other Assets, Net
Other assets, net consisted of the following:
 
As of December 31,
 
2014
 
2013
Deferred turnaround and catalyst costs
$
60,753

 
$
16,034

Environmental receivables
3,030

 
4,273

Deferred debt issuance costs
10,569

 
12,602

Intangible assets, net
7,647

 
7,497

Receivable from supply and offtake agreements (Note 9)
26,179

 
26,179

Commodity contracts
11,622

 

Fair value hedges (Note 9)
24,903

 

Other, net
18,176

 
15,625

Total other assets
$
162,879

 
$
82,210



F-23

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


(13)
Accrued Liabilities and Other Non-Current Liabilities
Accrued liabilities and other non-current liabilities consisted of the following:
 
As of December 31,
 
2014
 
2013
Accrued Liabilities:
 
 
 
Taxes other than income taxes, primarily excise taxes
$
47,071

 
$
37,645

Employee costs
13,297

 
13,793

Commodity contracts
7,501

 
16,526

Accrued finance charges
1,826

 
8,733

Environmental accrual (Note 21)
8,189

 
12,898

Other
26,507

 
31,263

Total accrued liabilities
$
104,391

 
$
120,858

 
 
 
 
Other Non-Current Liabilities:
 
 
 
Pension and other postemployment benefit liabilities, net
$
52,135

 
$
40,351

Environmental accrual (Note 21)
43,546

 
45,484

Asset retirement obligations
12,328

 
12,468

Consignment inventory obligations (Note 9)
63,963

 
64,550

Fair value hedges (Note 9)

 
3,339

Commodity contracts

 
11,569

Interest rate swaps
1,238

 

Other
9,449

 
11,713

Total other non-current liabilities
$
182,659

 
$
189,474

The following table summarizes the activity relating to the asset retirement obligations for the years ended December 31, 2014 and 2013:
 
As of December 31,
 
2014
 
2013
Balance at beginning of year
$
12,468

 
$
11,867

Accretion expense
651

 
592

Retirements
(791
)
 

Additions

 
9

Balance at end of year
$
12,328

 
$
12,468

Retirements include $707 related to the disposal of the Willbridge, Oregon asphalt terminal in January 2014 (Note 10).


F-24

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


(14)
Postretirement Benefits
(a)
Retirement Plans
We have four defined benefit pension plans covering substantially all of our employees, excluding employees of our retail segment. The benefits are based on years of service and the employee’s final average monthly compensation. Our funding policy is to contribute annually no less than the minimum required nor more than the maximum amount that can be deducted for federal income tax purposes. Contributions are intended to provide not only for benefits attributed to service to date but also for those benefits expected to be earned in the future.
Financial information related to our pension plans is presented below:
 
Pension Benefits
 
2014
 
2013
Change in projected benefit obligation:
 
 
 
Benefit obligation at beginning of year
$
106,028

 
$
111,531

Service cost
3,424

 
3,962

Interest cost
4,952

 
4,408

Actuarial (gain) loss
17,801

 
(10,890
)
Benefits paid
(3,152
)
 
(2,857
)
Curtailment

 
(126
)
Projected benefit obligations at end of year
$
129,053

 
$
106,028

Change in plan assets:
 
 
 
Fair value of plan assets at beginning of year
$
73,918

 
$
57,630

Actual gain on plan assets
7,904

 
12,978

Employer contribution
6,223

 
6,167

Benefits paid
(3,152
)
 
(2,857
)
Fair value of plan assets at end of year
$
84,893

 
$
73,918

Reconciliation of funded status:
 
 
 
Fair value of plan assets at end of year
$
84,893

 
$
73,918

Less projected benefit obligations at end of year
129,053

 
106,028

Under-funded status at end of year
$
(44,160
)
 
$
(32,110
)
The pre-tax amounts related to the defined benefit plans recognized in the consolidated balance sheets as of December 31, 2014 and 2013 were as follows:
 
Pension Benefits
 
2014
 
2013
Amounts recognized in the consolidated balance sheets:
 
 
 
Pension benefit liability
$
(44,160
)
 
$
(32,110
)
The pre-tax amounts in accumulated other comprehensive income (loss) as of December 31, 2014 and 2013 that have not yet been recognized as components of net periodic benefit cost were as follows:
 
Pension Benefits
 
2014
 
2013
Net actuarial loss
$
(44,660
)
 
$
(31,719
)
Prior service credit
276

 
327

Total
$
(44,384
)
 
$
(31,392
)


F-25

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


The following amounts included in accumulated other comprehensive income (loss) as of December 31, 2014 are expected to be recognized as components of net periodic benefit cost during the year ending December 31, 2015:
 
Pension
Benefits
Amortization of prior service credit
$
(51
)
Amortization of loss
3,408

Total
$
3,357

As of December 31, 2014 and 2013, the accumulated benefit obligation for each of our pension plans was in excess of the fair value of plan assets. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans were as follows:
 
As of December 31,
 
2014
 
2013
Projected benefit obligation
$
129,053

 
$
106,028

Accumulated benefit obligation
118,931

 
96,130

Fair value of plan assets
84,893

 
73,918

The weighted-average assumptions used to determine benefit obligations at December 31, 2014, 2013 and 2012 were as follows:
 
Pension Benefits
 
2014
 
2013
 
2012
Discount rate
3.95
%
 
4.75
%
 
4.00
%
Rate of compensation increase
2.50
%
 
3.00
%
 
3.00
%
The discount rate used reflects the expected future cash flow based on our funding valuation assumptions and participant data as of the beginning of the plan year. The expected future cash flow is discounted by the Principal Pension Discount Yield Curve for the fiscal year end because it has been specifically designed to help pension funds comply with statutory funding guidelines.
The weighted-average assumptions used to determine net periodic benefit costs for the years ended December 31, 2014, 2013 and 2012 were as follows:
 
Pension Benefits
 
2014
 
2013
 
2012
Discount rate
4.75
%
 
4.00
%
 
4.75
%
Expected return on plan assets
8.60
%
 
8.60
%
 
8.60
%
Rate of compensation increase
3.00
%
 
3.00
%
 
1.50
%
Our overall expected long-term rate of return on assets is 8.60%. The expected long-term rate of return is based on the portfolio as a whole and not on the sum of the returns on individual asset categories. The components of net periodic benefit cost for the years and periods were as follows:
 
Pension Benefits
 
Year Ended December 31,
 
2014
 
2013
 
2012
Components of net periodic benefit cost:
 
 
 
 
 
Service cost
$
3,424

 
$
3,962

 
$
3,577

Interest cost
4,952

 
4,408

 
4,128

Amortization of prior service credit
(51
)
 
(51
)
 
(51
)
Expected return on plan assets
(5,478
)
 
(4,628
)
 
(4,305
)
Recognized net actuarial loss
2,432

 
4,071

 
2,633

Net periodic benefit cost
$
5,279

 
$
7,762

 
$
5,982



F-26

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


Plan Assets
The weighted-average asset allocation of our pension benefits at December 31, 2014 and 2013 was as follows:
 
Pension Benefits
 
Plan Assets
 
2014
 
2013
Asset Category:
 
 
 
Equity securities
79.3
%
 
81.0
%
Debt securities
10.0
%
 
9.7
%
Real estate investment trust
10.7
%
 
9.3
%
Total
100.0
%
 
100.0
%
The fair value of our pension assets by category as of December 31, 2014 and 2013 were as follows:
 
Quoted Prices in
Active Markets
For Identical
Assets or
Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Consolidated
Total
Year ended December 31, 2014
 
 
 
 
 
 
 
Equity securities:
 
 
 
 
 
 
 
U.S. companies
$
55,322

 
$

 
$

 
$
55,322

International companies
11,991

 

 

 
11,991

Debt securities:
 
 
 
 
 
 


Preferred securities
3,492

 

 

 
3,492

Bond & mortgage backed securities

 
5,039

 

 
5,039

Real estate securities
9,049

 

 

 
9,049

Total
$
79,854

 
$
5,039

 
$

 
$
84,893

Year ended December 31, 2013
 
 
 
 
 
 
 
Equity securities:
 
 
 
 
 
 
 
U.S. companies
$
48,530

 
$

 
$

 
$
48,530

International companies
11,346

 

 

 
11,346

Debt securities:
 
 
 
 
 
 
 
Preferred securities
3,136

 

 

 
3,136

Bond & mortgage backed securities

 
4,049

 

 
4,049

Real estate securities
6,857

 

 

 
6,857

Total
$
69,869

 
$
4,049

 
$

 
$
73,918

The investment policies and strategies for the assets of our pension benefits is to, over a five year period, provide returns in excess of the benchmark. The portfolio is expected to earn long-term returns from capital appreciation and a stable stream of current income. This approach recognizes that assets are exposed to price risk and the market value of the plans’ assets may fluctuate from year to year. Risk tolerance is determined based on our specific risk management policies. In line with the investment return objective and risk parameters, the plans’ mix of assets includes a diversified portfolio of equity, fixed-income and real estate investments. Equity investments include domestic and international stocks of various sizes of capitalization. The asset allocation of the plan is reviewed on at least an annual basis.
Cash Flows
We contributed $6,223 and $6,167 to the pension plan for the years ended December 31, 2014 and 2013, respectively, and expect to contribute $5,552 to the pension plan in 2015. There were no employee contributions to the plans.
The benefits expected to be paid in each year 20152019 are $3,859; $4,846; $4,500; $4,760 and $5,070, respectively. The aggregate benefits expected to be paid in the five years from 20202024 are $31,090. The expected benefits are based on


F-27

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


the same assumptions used to measure our benefit obligation at December 31, 2014 and include estimated future employee service.
401(k) Savings Plans
We sponsor a 401(k) savings plan that is available to all employees, excluding employees of our retail segment. We match 100% of individual participant contributions up to 3% of compensation. In 2012, we revised our 401(k) savings plan that is available to certain employees represented by a union at our Big Spring refinery, in which we match individual participant contributions up to 8% of compensation. For the years ended December 31, 2014 and 2013, our contributions were $3,186 and $2,840, respectively.
We also sponsor a 401(k) savings plan that is available to the employees of our retail segment. Retail employees may contribute up to 50% of their pay after completing three months of service. We match from 1% to 4.5% of employee compensation. For the years ended December 31, 2014 and 2013, our contributions were $1,011 and $959, respectively.
(b)
Postretirement Medical Plan
In addition to providing pension benefits, we adopted an unfunded postretirement medical plan covering certain health care and life insurance benefits (other benefits) for active and certain retired employees who met eligibility requirements in the plan documents. This plan is closed to new participants. The health care benefits in excess of certain limits are insured. The accrued benefit liability related to this plan reflected in the consolidated balance sheets was $8,624 and $8,941 at December 31, 2014 and 2013, respectively.
As of December 31, 2014, the total accumulated postretirement benefit obligation under the postretirement medical plan was $8,624.
(15)
Indebtedness
Debt consisted of the following:
 
As of December 31,
 
2014
 
2013
Term loan credit facilities
$
264,359

 
$
244,322

Alon USA, LP Credit Facility
60,000

 
100,000

Senior secured notes

 
73,706

Convertible senior notes
126,298

 
121,090

Retail credit facilities
113,030

 
73,130

Total debt
563,687

 
612,248

Less: Current portion
15,089

 
83,174

Total long-term debt
$
548,598

 
$
529,074

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


F-28

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


The Convertible Notes had an initial conversion rate of 67.627 shares of our common stock per each $1 (in thousands) principal amount of the Convertible Notes, equivalent to an initial conversion price of approximately $14.79 per share, which represents a conversion premium of 32.5% on our last reported common stock price of $11.16 per share on the date of the Convertible Notes offering. The conversion rate is subject to adjustment upon the occurrence of certain events, including cash dividend adjustments, but will not be adjusted for any accrued and unpaid interest. As of December 31, 2014, the conversion rate was adjusted to 68.910 shares of our common stock per each $1 (in thousands) principal amount of Convertible Notes, equivalent to a per share conversion price of approximately $14.51, to reflect cash dividend adjustments. As of December 31, 2014, 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 $150,000 (before fees and expenses related to the offering). We used $15,225 of the proceeds to fund the cost of entering into convertible note hedge transactions (after such cost was partially offset by the proceeds we received from entering into warrant transactions) described below. In October 2013, we used the remaining net proceeds from the Convertible Notes offering, along with cash on hand, to redeem $140,000 of the outstanding principal balance on the 13.50% Alon Refining Krotz Springs, Inc. (“ARKS”) senior secured notes.
The $150,000 principal amount of the Convertible Notes was separated between the liability component and the equity component (i.e. the embedded conversion feature). The fair value of the liability component was calculated using a discount rate of an identical unsecured instrument without a conversion feature. Based on this borrowing rate, the fair value of the liability component of the Convertible Notes on the issuance date was $119,635, with a corresponding debt discount of $30,365, to be amortized at an effective interest rate of 8.15% over the term of the Convertible Notes. The carrying amount of the embedded conversion feature was determined to be $30,365, by deducting the fair value of the liability component from the $150,000 principal amount of the Convertible Notes. The embedded conversion feature was recorded to additional paid-in capital because this financial instrument could be settled in our common stock and does not meet the definition of a derivative instrument. Additionally, $4,933 of transaction costs were allocated on a proportionate basis between other assets and additional paid-in capital in the consolidated balance sheets.
For the years ended December 31, 2014 and 2013, interest expense on the Convertible Notes’ contractual coupon rates was $4,500 and $1,313, respectively. The amounts charged to interest expense for amortization of the original issuance discount on the Convertible Notes for the years ended December 31, 2014 and 2013 were $5,208 and $1,455, respectively.
As of December 31, 2014, the if-converted value of the Convertible Notes did not exceed the outstanding principal balance.
The principal balance, unamortized discount and net carrying amount of the liability and equity components of the Convertible Notes as of December 31, 2014 and 2013 are as follows:
 
As of December 31,
 
2014
 
2013
Equity component, pretax (1)
$
30,365

 
$
30,365

Convertible Notes:
 
 
 
Principal balance
150,000

 
150,000

Less: Unamortized discount
(23,702
)
 
(28,910
)
Convertible Notes, net
$
126,298

 
$
121,090

_______________________
(1)A deferred tax liability of $11,171 was recognized related to the issuance of the Convertible Notes.
Convertible Note Hedge Transactions
In connection with the Convertible Notes offering, we also entered into convertible note hedge transactions with respect to our common stock (the “Purchased Options”) with the initial purchasers of the Convertible Notes (the “Hedge Counterparties”). We paid an aggregate amount of $28,455 to the Hedge Counterparties for the Purchased Options. As of December 31, 2014, the Purchased Options, with a strike price of $14.51 per share of our common stock, cover 10,144,050 shares of our common stock, subject to customary anti-dilution adjustments, that initially underlie the Convertible Notes sold in the offering. The Purchased Options will expire in September 2018.
The Purchased Options are intended to reduce the potential dilution with respect to our common stock upon conversion of the Convertible Notes as well as offset any potential cash payments we are required to make in excess of the principal amount


F-29

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


upon any conversion of the notes. The Purchased Options have been included in additional paid-in capital on the consolidated balance sheets, net of deferred tax assets of $10,468.
The Purchased Options are separate transactions and are not part of the terms of the Convertible Notes and are excluded from classification as a derivative as the amount could be settled in our stock. Holders of the Convertible Notes do not have any rights with respect to the Purchased Options.
Warrant Transactions
In connection with the Convertible Notes offering, we also entered into warrant transactions (the “Warrants”), whereby we sold to the Hedge Counterparties warrants in an aggregate amount of $13,230 to acquire, subject to customary anti-dilution adjustments, up to 10,144,050 shares of our common stock at a strike price of approximately $19.71 per share of our common stock as of December 31, 2014. The Warrants will be settled on a net-share basis and will expire in April 2019. The Warrants have been included in additional paid-in capital on the consolidated balance sheets.
The Warrants are separate transactions and are not part of the terms of the Convertible Notes and are excluded from classification as a derivative as the amount could be settled in our stock. Holders of the Convertible Notes do not have any rights with respect to the Warrants.
2006 Term Loan Credit Facility. In June 2006, we entered into a $450,000 term loan (“2006 Term Loan”). The 2006 Term Loan required principal repayments of $4,500 per annum paid in quarterly installments until maturity in August 2013. In November 2012, we repaid in full our obligations under the 2006 Term Loan. As a result of the prepayment of the 2006 Term Loan, a write-off of unamortized debt issuance costs of $1,459 is included in interest expense on the consolidated statements of operations for the year ended December 31, 2012.
Alon USA Term Loan Credit Facility. In November 2012, we entered into a term loan (“Alon USA Term Loan”) with an aggregate principal amount of $450,000, issued at an offering price of 95% that matures in November 2018. Proceeds from the Alon USA Term Loan were used to repay in full our obligations under the 2006 Term Loan and for general corporate purposes.
In connection with the closing of the Partnership’s initial public offering in November 2012 (the “Offering”), we assigned $250,000 of the aggregate principal balance of the Alon USA Term Loan to the Partnership and used proceeds from the Offering to fully repay the remaining outstanding balance of the Alon USA Term Loan.
As a result of the prepayment of the Alon USA Term Loan, write-offs of unamortized original issuance discount and debt issuance costs of $18,750 and $7,367, respectively, are included in interest expense on the consolidated statements of operations for the year ended December 31, 2012.
Letter of Credit Facilities. In December 2013, Alon entered into a Letter of Credit Facility (the “Alon Energy Letter of Credit Facility”). The Alon Energy Letter of Credit Facility is for the issuance of standby letters of credit in an amount not to exceed $60,000. We are required to pledge $100,000 of the Partnership’s common units as collateral for the Alon Energy Letter of Credit Facility. Additionally, Alon Assets, Inc. (“Alon Assets”) was named as a guarantor, guaranteeing all of our obligations under the Alon Energy Letter of Credit Facility in the event of default. The Alon Energy Letter of Credit Facility contains certain restrictive covenants including maintenance financial covenants.
At December 31, 2014 and 2013, we had outstanding letters of credit under this facility of $54,227 and $56,827, respectively.
Alon Energy Term Loan. In March 2014, we entered into a five-year Term Loan Agreement (“Alon Energy Term Loan”) for a principal amount of $25,000, maturing in March 2019. Repayments are monthly, commencing June 2014. Borrowings under this agreement incur interest at an annual rate equal to LIBOR plus a margin of 3.75%. We pledged 2,200,000 of the Partnership’s common units as collateral for the Alon Energy Term Loan. Additionally, Alon Assets guarantees all payments under the Alon Energy Term Loan. The Alon Energy Term Loan contains certain restrictive covenants including maintenance financial covenants.
Proceeds from the Alon Energy Term Loan were used to purchase equipment for a capital project at our Big Spring refinery.
At December 31, 2014, the Alon Energy Term Loan had an outstanding balance of $21,983.


F-30

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


(b)
Alon USA Partners, LP
Partnership Term Loan Credit Facility. In connection with the Offering, the Partnership was assigned $250,000 of the aggregate principal balance of the Alon USA Term Loan (the “Partnership Term Loan”). The Partnership Term Loan requires principal payments of $2,500 per annum paid in quarterly installments until maturity in November 2018.
The Partnership Term Loan bears interest at a rate equal to the sum of (i) the Eurodollar rate (with a floor of 1.25% per annum) plus (ii) a margin of 8.00% per annum for a per annum rate of 9.25%, based on current Eurodollar market rates at December 31, 2014.
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, 2014 and 2013, the Partnership Term Loan had an outstanding balance (net of unamortized discount) of $242,376 and $244,322, respectively.
Revolving Credit Facility. We have a $240,000 revolving credit facility (the “Alon USA, LP Credit Facility”) that will mature in March 2016. The Alon USA, LP Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility amount or the borrowing base amount under the facility.
Borrowings under the Alon USA, LP Credit Facility bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%.
The Alon USA, LP Credit Facility is secured by a first lien on the Partnership’s cash, accounts receivables, inventories and related assets and a second lien on the Partnership’s fixed assets and other specified property.
The Alon USA, LP Credit Facility contains certain restrictive covenants including maintenance financial covenants.
Borrowings of $60,000 and $100,000 were outstanding under the Alon USA, LP Credit Facility at December 31, 2014 and 2013, respectively. At December 31, 2014 and 2013, outstanding letters of credit under the Alon USA, LP Credit Facility were $23,511 and $109,772, respectively.
(c)
Alon Refining Krotz Springs, Inc.
Senior Secured Notes. In October 2009, ARKS issued 13.50% senior secured notes (the “Senior Secured Notes”) in aggregate principal amount of $216,500 in a private offering. In February 2010, ARKS exchanged $216,500 of Senior Secured Notes for an equivalent amount of Senior Secured Notes registered under the Securities Act of 1933 maturing in October 2014 with the entire principal amount due at maturity.
In October 2013, we used proceeds from the Convertible Notes offering, along with cash on hand, to redeem $140,000 of the outstanding principal balance on the Senior Secured Notes. As a result of the prepayment of the Senior Secured Notes, a prepayment premium of $4,725 and write-offs of unamortized original issuance discount and debt issuance costs of $1,871 and $1,871, respectively, were charged to interest expense in the consolidated statements of operations for the year ended December 31, 2013.
During 2014, we redeemed the remaining principal balance on the Senior Secured Notes. As a result of the prepayment of the Senior Secured Notes, write-offs of unamortized original issuance discount and debt issuance costs of $391 and $358, respectively, were charged to interest expense in the consolidated statements of operations for the year ended December 31, 2014.
At December 31, 2013, the Senior Secured Notes had an outstanding balance (net of unamortized discount) of $73,706, included in long-term debt.
(d)
Retail
Alon Brands Term Loans. In March 2011, Alon Brands issued $30,000 five-year unsecured notes (the “Alon Brands Term Loans”) to a group of investors including certain shareholders of Alon Israel Oil Company, Ltd. (“Alon Israel”) and their affiliates. In conjunction with the issuance of the Alon Brands Term Loans, we issued 3,092,783 warrants to purchase shares of our common stock. The allocated fair value of the warrants was $10,988 and was recorded as additional paid-in capital at the time of issuance.


F-31

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


In March 2012, we issued $30,000 of 8.5% Series B Convertible Preferred Stock to the holders of the Alon Brands Term Loans and repaid in full the obligations under the Alon Brands Term Loans. Also as part of the transaction, the warrants issued in conjunction with the Alon Brands Term Loans were surrendered to Alon Energy. As the Alon Brands Term Loans were originally issued at a discount, the remaining $9,624 of unamortized original issuance discount was charged to interest expense in the consolidated statements of operations for the year ended December 31, 2012.
Term Credit Agreement. Southwest Convenience Stores, LLC and Skinny’s LLC, (“Alon Retail”) were party to a credit agreement (the “Credit Agreement”) with a maturity in December 2015. At December 31, 2013, the outstanding balance under the Credit Agreement was $72,689. In March 2014, Alon Retail entered into a new credit agreement (“Alon Retail Credit Agreement”) and repaid in full its obligations under the Credit Agreement.
The Alon Retail Credit Agreement will mature in March 2019 and includes a $110,000 term loan and a $10,000 revolving credit loan. The Alon Retail Credit Agreement also includes an accordion feature that provides for incremental term loans up to $30,000 to fund store rebuilds, new builds and acquisitions. Borrowings under the Alon Retail Credit Agreement bear interest at a Eurodollar rate plus an applicable margin between 2.00% and 2.75%, determined quarterly based upon Alon Retail’s leverage ratio. 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.
Proceeds from the Alon Retail Credit Agreement were used to fully repay the remaining obligations under the Credit Agreement and pay a dividend distribution of $40,000 to Alon Brands, Inc., our wholly-owned subsidiary, while the remainder was used for general corporate purposes.
At December 31, 2014, the Alon Retail Credit Agreement had an outstanding balance of $112,667, consisting of a term loan balance of $102,667 and a revolving credit loan balance of $10,000.
Other Retail Related Credit Facilities. In 2003, we obtained $1,545 in mortgage loans to finance the acquisition of new retail locations. The interest rates on these loans ranged between 5.50% and 9.70%, with 5 to 15 year payment terms. At December 31, 2014 and 2013, the outstanding balances were $363 and $441, respectively.
(e)
Financial Covenants
We have certain credit facilities with maintenance financial covenants. At December 31, 2014, we were in compliance with these covenants.
(f)
Maturity of Long-Term Debt
The aggregate scheduled maturities of long-term debt for each of the five years subsequent to December 31, 2014 are as follows:
Year ended December 31,
 
2015
$
15,089

2016
75,076

2017
15,071

2018
373,751

2019
84,700

Total
$
563,687



F-32

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


(g)
Interest and Financing Expense
Interest and financing expense included the following:
 
Year Ended December 31,
 
2014
 
2013
 
2012
Interest expense on debt
$
37,850

 
$
54,191

 
$
57,987

Letters of credit and finance charges
65,156

 
32,286

 
28,159

Amortization of debt issuance costs
3,759

 
4,496

 
6,296

Write-off of debt issuance costs
558

 
1,871

 
8,826

Amortization of original issuance discount
6,306

 
4,300

 
2,570

Write-off of original issuance discount
391

 
1,871

 
28,374

Less: Capitalized interest
(2,877
)
 
(4,321
)
 
(2,640
)
Total interest expense
$
111,143

 
$
94,694

 
$
129,572

(16)
Stockholders' Equity
(a)
Common stock (share value in dollars)
Our authorized common stock consists of 150,000,000 shares of common stock, $0.01 par value. Issued and outstanding shares of common stock were 69,606,944 and 68,641,428 as of December 31, 2014 and 2013, respectively.
Amended Shareholder Agreement. In 2012, we signed agreements with non-controlling interest shareholders of Alon Assets, whereby the participants would exchange shares of Alon Assets for shares of our common stock. During 2014 and 2013, 659,289 and 785,192 shares of our common stock were issued in exchange for 3,524.49 and 4,197.55 shares of Alon Assets, respectively. At December 31, 2014, 1,260,423 shares of our common stock remain available for exchange. Compensation expense associated with the difference in value between the participants’ ownership of Alon Assets, compared to our common stock of $2,432, $2,499 and $1,036 was recognized for the years ended December 31, 2014, 2013 and 2012, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.
For the years ended December 31, 2014, 2013 and 2012, activity in the number of common stock was as follows:
 
Common
Stock
 
(in thousands)
Balance as of December 31, 2011
56,108

Shares forfeited
(20
)
Shares issued in connection with stock plans
256

Shares issued for payment of preferred stock dividends
358

Shares issued in connection with preferred share conversions
4,125

Shares issued in connection with amended shareholder agreement
445

Balance as of December 31, 2012
61,272

Shares issued in connection with stock plans
237

Shares issued for payment of preferred stock dividends
197

Shares issued in connection with preferred share conversions
6,160

Shares issued in connection with amended shareholder agreement
775

Balance as of December 31, 2013
68,641

Shares issued in connection with stock plans
304

Shares issued for payment of preferred stock dividends
3

Shares issued in connection with amended shareholder agreement
659

Balance as of December 31, 2014
69,607

(b)
Preferred stock (share value in dollars)
Our authorized preferred stock consists of 15,000,000 shares of convertible preferred stock, $0.01 par value. Issued and outstanding shares of preferred stock were 68,180 as of December 31, 2014 and 2013.


F-33

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


In October 2010, we completed a registered direct offering of 4,000,000 shares of Alon’s 8.5% Series A Convertible Preferred Stock (the “Series A Preferred Stock”) for an aggregate offering price of $40,000 less offering expenses, of which Alon Israel purchased $35,000. As of December 31, 2014, all shares of Series A Preferred Stock have been converted into shares of our common stock.
In March 2012, we issued 3,000,000 shares of 8.5% Series B Convertible Preferred Stock (the “Series B Preferred Stock”) to a group of investors who held, in the aggregate, $30,000 of the Alon Brands Term Loans and 3,092,783 warrants to purchase shares of our common stock. We repaid in full the obligations under the Alon Brands Term Loans and the warrants were surrendered to us. The holders of the Series B Preferred Stock can convert, at the holder’s option, the Series B Preferred Stock into shares of our common stock based on an initial conversion price of $6.74 per share, in each case subject to adjustments. We have the right to convert the Series B Preferred Stock into shares of our common stock from March 2015. At December 31, 2014, 68,180 shares of Series B Convertible Preferred Stock remain outstanding. If all of the outstanding Series B Preferred Stock were to be converted into shares of our common stock based on the initial conversion price of $6.74 per share, then approximately 101,150 shares of our common stock would be issued.
During the year ended December 31, 2014, there were no conversions of Preferred Stock to shares of our common stock. During the year ended December 31, 2013, certain holders converted 3,500,000 shares of Series A Preferred Stock and 651,820 shares of Series B Preferred Stock to 6,160,057 shares of our common stock.
(c)
Dividends
During the year ended December 31, 2014, we paid cash dividends on common stock totaling $0.53 per share which included a special non-recurring dividend of $0.21 per share paid in December. We also increased our regular quarterly cash dividend from $0.06 per share to $0.10 per share during the third quarter. During the year ended December 31, 2013, we paid cash dividends on common stock totaling $0.38 per share which included a special non-recurring dividend of $0.16 per share paid in June as well as an increase in our regular quarterly dividend from $0.04 per share to $0.06 per share during the second quarter. During the year ended December 31, 2012, we paid cash dividends on common stock totaling $0.16 per share. Additionally, the non-controlling interest shareholders of Alon Assets received aggregate cash dividends of $1,134, $886 and $524 during 2014, 2013, and 2012, respectively.
Preferred Stock Dividends. We issued 3,174 and 196,648 shares in aggregate of our common stock for payment of the quarterly 8.5% preferred stock dividends to preferred stockholders for the years ended December 31, 2014 and 2013, respectively.
(d)
Accumulated Other Comprehensive Loss
The following table displays the change in accumulated other comprehensive loss, net of tax:
 
Unrealized Gain (Loss) on Cash Flow Hedges
 
Postretirement Benefit Plans
 
Total
Balance at December 31, 2013
$
(18,248
)
 
$
(19,267
)
 
$
(37,515
)
Other comprehensive income (loss) before reclassifications
29,956

 
(8,611
)
 
21,345

Amounts reclassified from accumulated other comprehensive income (loss)
9,622

 
(1,910
)
 
7,712

Net current-period other comprehensive income (loss)
39,578

 
(10,521
)
 
29,057

Balance at December 31, 2014
$
21,330

 
$
(29,788
)
 
$
(8,458
)
(17)
Stock-Based Compensation
Amended and Restated 2005 Incentive Compensation Plan (share value in dollars)
The Alon USA Energy, Inc. Second Amended and Restated 2005 Incentive Compensation Plan (“the Plan”) is a component of our overall executive incentive compensation program. The Plan permits the granting of awards in the form of options to purchase common stock, stock appreciation rights, restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses to our directors, officers and key employees.
Restricted Stock. Non-employee directors are awarded an annual grant of $25 in shares of restricted stock, which vest over a period of three years, assuming continued service at vesting. In May 2014, we granted awards of 4,965 restricted shares at a


F-34

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


grant date price of $15.11 per share. In May 2013, we granted awards of 4,257 restricted shares at a grant date price of $17.62 per share.
In August 2014, we granted awards of 69,980 restricted shares to certain executive officers at a grant date price of $13.65 per share. These August 2014 restricted shares will vest as follows: 50% in August 2015 and 50% in August 2019, assuming continued service at vesting.
In May 2014, we granted awards of 255,000 restricted shares to certain executive officers at a grant date price of $15.11 per share. These May 2014 restricted shares will vest as follows:  50% in May 2015 and 50% in May 2016, assuming continued service at vesting.
In May 2013, we granted awards of 255,000 restricted shares to certain executive officers at a grant date price of $17.25 per share. These May 2013 restricted shares are 50% vested as of December 31, 2014, with the remaining 50% vesting in May 2016, assuming continued service at vesting.
The following table summarizes the restricted share activity from January 1, 2013:
 
 
 
 
Weighted
Average
Grant Date
Fair Values
Nonvested Shares
 
Shares
 
(per share)
Nonvested at January 1, 2013
 
326,130

 
$
10.71

Granted
 
259,257

 
17.26

Vested
 
(136,693
)
 
10.21

Forfeited
 

 

Nonvested at December 31, 2013
 
448,694

 
$
14.64

Granted
 
329,945

 
14.80

Vested
 
(134,640
)
 
16.95

Forfeited
 

 

Nonvested at December 31, 2014
 
643,999

 
$
14.24

The number of restricted shares expected to vest in each year of 2015 - 2019, assuming continued service, are 169,280; 438,074; 1,655; 0; and 34,990, respectively. Compensation expense for the restricted stock grants amounted to $4,151, $3,005 and $1,656 for the years ended December 31, 2014, 2013 and 2012, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations. The fair value of shares vested in 2014 was $2,044.
Restricted Stock Units. In May 2011, we granted 500,000 restricted stock units to the CEO and President of Alon at a grant date fair value of $11.47 per share. Each restricted unit represents the right to receive one share of our common stock upon the vesting of the restricted stock unit. All 500,000 restricted stock units vested in March 2015. Compensation expense for the restricted stock units amounted to $1,496 for each of the years ended December 31, 2014, 2013 and 2012, and is included in selling, general and administrative expenses in the consolidated statements of operations.
Senior Executive Plan Bonuses.  In August 2012, we granted 37,500 shares of common stock to certain executive officers at a weighted average grant date price of $13.95 per share. These shares vested immediately upon issuance. Compensation expense for the bonuses amounted to $523 for the year ended December 31, 2012, and is included in selling, general and administrative expenses in the consolidated statements of operations.
Unrecognized Compensation. As of December 31, 2014, there was $4,515 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 1.3 years.


F-35

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


(18)
Income Taxes
Income tax expense included the following:
 
Year Ended December 31,
 
2014
 
2013
 
2012
Current:
 
 
 
 
 
Federal
$
15,171

 
$
1,348

 
$
3,074

State
1,781

 
2,525

 
4,788

Total current
$
16,952

 
$
3,873

 
$
7,862

Deferred:
 
 
 
 
 
Federal
$
7,176

 
$
9,770

 
$
41,868

State
(1,215
)
 
(1,492
)
 
154

Total deferred
5,961

 
8,278

 
42,022

Income tax expense
$
22,913

 
$
12,151

 
$
49,884

A reconciliation between the income tax expense computed on pre-tax income at the statutory federal rate and the actual provision for income tax expense is as follows:
 
Year Ended December 31,
 
2014
 
2013
 
2012
Computed expected tax expense
$
32,474

 
$
21,093

 
$
49,169

State and local income taxes, net of federal benefit
532

 
844

 
3,373

Tax effect of non-controlling interest in Partnership income
(11,097
)
 
(8,927
)
 
(2,426
)
Other, net
1,004

 
(859
)
 
(232
)
Income tax expense
$
22,913

 
$
12,151

 
$
49,884

The following table sets forth the tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities.
 
As of December 31,
 
2014
 
2013
Deferred income tax assets:
 
 
 
Accounts receivable, allowance
$
198

 
$
155

Inventories
8,420

 
10,402

Accrued liabilities and other
1,718

 
1,521

Post-retirement benefits
19,627

 
14,846

Non-current accrued liabilities and other
24,994

 
22,631

Net operating loss carryover
22,122

 
22,399

Tax credits
1,154

 
3,279

Other
3,484

 
5,428

Deferred income tax assets
$
81,717

 
$
80,661

Deferred income tax liabilities:
 
 
 
Deferred gain on the Offering of the Partnership
$
50,178

 
$
50,491

Derivative instruments designated as cash flow hedges
12,817

 
(11,083
)
Deferred charges
469

 
524

Unrealized gains
2,346

 
925

Property, plant and equipment
375,330

 
374,852

Other non-current
3,316

 
3,793

Intangibles
10,175

 
8,771

Deferred income tax liabilities
$
454,631

 
$
428,273



F-36

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of taxable income and projections for future taxable income, over the periods which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the benefits of these deductible differences in future periods.
At December 31, 2014, we have net operating loss carryforwards for state and local income tax purposes of $413,815 which are available to offset future state taxable income in various years through 2031.
We have elected to recognize interest expense related to the underpayment of income taxes in interest expense, and penalties relating to underpayment of income taxes as a reduction to other income (loss), net, in the consolidated statements of operations. We are subject to U.S. federal income tax, and income tax in multiple state jurisdictions with California, Texas, New Mexico, Oklahoma and Louisiana comprising the majority of our state income tax. The federal tax years 2000 to 2010 are closed to audit. In general, the state tax years open to audit range from 2007 to 2013. Our liability for unrecognized tax benefits and accrued interest did not increase during the year ended December 31, 2014, as there were no unrecognized tax benefits recorded in 2014.
(19)
Earnings Per Share
Basic earnings per share is calculated as net income available to common stockholders divided by the weighted average number of participating shares of common stock. Diluted earnings per share includes the dilutive effect of granted stock appreciation rights, granted restricted common stock units, granted restricted common stock awards, convertible debt and warrants using the treasury stock method and the dilutive effect of convertible preferred shares using the if-converted method.
The calculation of earnings per share, basic and diluted, for the years ended December 31, 2014, 2013 and 2012, is as follows (shares in thousands, per share value in dollars):
 
Year Ended December 31,
 
2014
 
2013
 
2012
Net income available to stockholders
$
38,457

 
$
22,986

 
$
79,134

less: preferred stock dividends
59

 
2,288

 
4,892

Net income available to common stockholders
38,398

 
20,698

 
74,242

 
 
 
 
 
 
Weighted average shares outstanding, basic
68,985

 
63,538

 
57,501

Dilutive common stock equivalents
388

 
1,314

 
6,416

Weighted average shares outstanding, diluted
69,373

 
64,852

 
63,917

Earnings per share, basic
$
0.56

 
$
0.33

 
$
1.29

Earnings per share, diluted
$
0.55

 
$
0.32

 
$
1.24

For the years ended December 31, 2014 and 2012, the weighted average number of diluted shares includes all potentially dilutive securities. For the year ended December 31, 2013, we have excluded 4,509 common stock equivalents from the weighted average number of diluted shares outstanding as the effect of including such shares would be anti-dilutive.
(20)
Related Party Transactions
(a)Preferred Stock Conversions
In 2012, we issued 1,200,000 shares of 8.5% Series B Convertible Preferred Stock for $12,000 to certain shareholders of Alon Israel and their affiliates. During the years ended December 31, 2013 and 2012, 651,820 and 480,000 shares of Series B Convertible Preferred Stock were converted into 967,107 and 712,176 shares of our common stock, respectively. During the year ended December 31, 2014, there were no conversions of Preferred Stock to shares of our common stock. At December 31, 2014, 68,180 shares of Series B Convertible Preferred Stock remain outstanding.


F-37

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


(b)Development Agreement
We entered into a development agreement with BSRE Point Wells, LP (“BSRE”), a subsidiary of Alon Holdings Blue Square-Israel, Ltd., in conjunction with the sale of a parcel of land at Richmond Beach, Washington to BSRE. In order to enhance the value of the land with a view towards maximizing the proceeds from its sale, the agreement provides that Alon and BSRE intend to cooperate in the development and construction of a mixed-use residential and planned community real estate project on the land. As part of this agreement, we agreed to pay a quarterly development fee of $439 in exchange for the right to participate in the potential profits realized by BSRE from the development of the land. During each of the years ended December 31, 2014, 2013 and 2012, $1,755 was paid to BSRE.
(c)Purchase of Equipment
During the year ended December 31, 2012, we purchased, from an affiliate, hydrotreating equipment and other refinery processing equipment for $18,000 and $8,000, respectively.
(21)
Commitments and Contingencies
(a)
Leases
We have long-term lease commitments for land, office facilities, retail facilities and related equipment and various equipment and facilities used in the storage and transportation of refined products. We also have long-term lease commitments for land at our Krotz Springs refinery. In most cases we expect that in the normal course of business, our leases will be renewed or replaced by other leases. We have commitments under long-term operating leases for certain buildings, land, equipment and pipelines expiring at various dates over the next twenty-one years. Certain long-term operating leases relating to buildings, land and pipelines include options to renew for additional periods. At December 31, 2014, minimum lease payments on operating leases were as follows:
Year ending December 31,
 
2015
$
28,263

2016
26,728

2017
24,684

2018
16,678

2019
9,564

2020 and thereafter
43,426

Total
$
149,343

Total rental expense was $35,699, $33,965 and $34,943 for the years ended December 31, 2014, 2013 and 2012, respectively. Contingent rentals and subleases were not significant.
(b)
Commitments
In the normal course of business, we have long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by our refineries, terminals, pipelines and retail locations. We are also party to various refined product and crude oil supply and exchange agreements, which are typically short-term in nature or provide terms for cancellation.
We have a pipelines and terminals agreement with Holly Energy Partners (“HEP”) through February 2020 with three additional five year renewal terms exercisable at our sole option. Pursuant to the pipelines and terminals agreement, we have committed to transport and store minimum volumes of refined products in these pipelines and terminals. The tariff rates applicable to the transportation of refined products on the pipelines are variable, with a base fee which is reduced for volumes exceeding defined volumetric targets. The agreement provides for the reduction of the minimum volume requirement under certain circumstances. The service fees for the storage of refined products in the terminals are set at rates competitive in the marketplace.
We have a throughput and deficiency agreement with Sunoco Pipeline, LP (“Sunoco”) that gives us the option to transport crude oil through the Amdel Pipeline either (1) westbound from the Nederland Terminal to the Big Spring refinery, or (2) eastbound from the Big Spring refinery to the Nederland Terminal for further barge transportation to the Krotz Springs refinery. Our minimum throughput commitment is 15,645 bpd. The agreement is for five years from the operational date of September 2012 with an option to extend the agreement by four additional thirty-month periods.


F-38

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


We have an arrangement with Centurion Pipeline L.P. (“Centurion”) through June 2021. This arrangement gives us transportation pipeline capacity to ship crude oil from Midland to the Big Spring refinery using Centurion’s approximately forty-mile long pipeline system from Midland to Roberts Junction and our three-mile pipeline from Roberts Junction to the Big Spring refinery which we lease to Centurion. Our minimum throughput commitment is 25,000 bpd.
In July 2013, we entered into offtake agreements with two investment grade oil companies that provides for the sale, at market prices, of light cycle oil and high sulfur distillate blendstock through June 2015. Both agreements will automatically extend for successive one year terms unless either we or the other party cancels the agreement by delivering written notice of termination to the other at least 180 days prior to the end of the then current term.
(c)
Contingencies
We are involved in various legal actions arising in the ordinary course of business. We believe the ultimate disposition of these matters will not have a material effect on our financial position, results of operations or liquidity.
One of our subsidiaries is a party to a lawsuit alleging breach of contract pertaining to an asphalt supply agreement. We believe that we have valid counterclaims as well as affirmative defenses that will preclude recovery. Attempts to reach a commercial arrangement to resolve the dispute have been unsuccessful to this point. This matter currently is not scheduled for trial. Due to the uncertainties of litigation, we cannot predict with certainty the ultimate resolution of this lawsuit.
(d)
Environmental
We are subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These laws and regulations govern the discharge of materials into the environment and may require us to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites and to compensate others for damage to property and natural resources. These contingent obligations relate to sites that we own and are associated with past or present operations. We are currently participating in environmental investigations, assessments and cleanups pertaining to our refineries, service stations, pipelines and terminals. We may be involved in additional future environmental investigations, assessments and cleanups. The magnitude of future costs are unknown and will depend on factors such as the nature and contamination at many sites, the timing, extent and method of the remedial actions which may be required, and the determination of our liability in proportion to other responsible parties.
We have an environmental agreement with HEP pursuant to which we agreed to indemnify HEP against costs and liabilities incurred by HEP to the extent resulting from the existence of environmental conditions at the pipelines or terminals or from violations of environmental laws with respect to the pipelines and terminals occurring prior to February 28, 2005. Our environmental indemnification obligations under the environmental agreement expired on March 1, 2015. However, with respect to any remediation required for environmental conditions existing prior to February 28, 2005, we have the option under the environmental agreement to perform such remediation ourself in lieu of indemnifying HEP for their costs of performing such remediation. Pursuant to this option, we are continuing to perform the ongoing remediation at the Abilene and Wichita Falls terminals. Any remediation required under the terms of the environmental agreement is limited to the standards under the applicable environmental laws as in effect at February 28, 2005.
We have an environmental agreement with Sunoco pursuant to which we agreed to indemnify Sunoco against costs and liabilities incurred by Sunoco to the extent resulting from the existence of environmental conditions at the pipelines or from violations of environmental laws with respect to the pipelines occurring prior to March 1, 2006. With respect to any remediation required for environmental conditions existing prior to March 1, 2006, we have the option to perform such remediation ourself in lieu of indemnifying Sunoco for their costs of performing such remediation.
We have accrued environmental remediation obligations of $51,735 ($8,189 current liability and $43,546 non-current liability) at December 31, 2014, and $58,382 ($12,898 current liability and $45,484 non-current liability) at December 31, 2013. Environmental liabilities with payments that are fixed or reliably determinable have been discounted to present value at a rate of 2.32%.
The table below summarizes our environmental liability accruals:
 
As of December 31,
 
2014
 
2013
Discounted environmental liabilities
$
46,150

 
$
35,938

Undiscounted environmental liabilities
5,585

 
22,444

Total accrued environmental liabilities
$
51,735

 
$
58,382



F-39

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


As of December 31, 2014, the estimated future payments of environmental obligations for which discounts have been applied are as follows:
Year ending December 31,
 
2015
$
5,940

2016
5,517

2017
4,012

2018
3,437

2019
3,268

2020 and thereafter
32,058

Discounted environmental liabilities, gross
54,232

Less: Discount applied
8,082

Discounted environmental liabilities
$
46,150

We have an indemnification agreement with a prior owner for remediation expenses at the Bakersfield refinery. We are required to make indemnification claims to the prior owner by March 15, 2015. We have recorded current receivables of $3,350 and $9,100 at December 31, 2014 and 2013, respectively, and non-current receivables of $1,774 at December 31, 2013.
In addition to the indemnification agreement related to the Bakersfield refinery, we have an indemnification agreement with a prior owner for part of the remediation expenses at certain other West Coast assets. We have recorded current receivables of $784 and $418 and non-current receivables of $3,030 and $2,499 at December 31, 2014 and 2013, respectively.
(22)
Quarterly Information (unaudited)
Selected financial data by quarter is set forth in the table below:
 
Quarters
 
First
 
Second
 
Third
 
Fourth
2014
 
 
 
 
 
 
 
Net sales
$
1,683,245

 
$
1,742,883

 
$
1,850,097

 
$
1,503,231

Operating income
38,960

 
18,932

 
94,005

 
49,675

Net income (loss)
8,375

 
(6,437
)
 
53,474

 
14,456

Net income (loss) available to stockholders
785

 
(7,517
)
 
38,482

 
6,707

Earnings (loss) per share:
 
 
 
 
 
 
 
Basic
$
0.01

 
$
(0.11
)
 
$
0.56

 
$
0.10

Diluted
$
0.01

 
$
(0.11
)
 
$
0.55

 
$
0.10

 
 
 
 
 
 
 
 
2013
 
 
 
 
 
 
 
Net sales
$
1,651,196

 
$
1,676,595

 
$
1,892,836

 
$
1,825,754

Operating income (loss)
125,831

 
42,032

 
(39,397
)
 
20,967

Net income (loss)
73,651

 
19,942

 
(33,185
)
 
(12,293
)
Net income (loss) available to stockholders
54,184

 
11,496

 
(28,709
)
 
(13,985
)
Earnings (loss) per share:
 
 
 
 
 
 
 
Basic
$
0.86

 
$
0.17

 
$
(0.47
)
 
$
(0.21
)
Diluted
$
0.80

 
$
0.17

 
$
(0.47
)
 
$
(0.21
)


F-40

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(dollars in thousands, except as noted)


(23)
Subsequent Events
Dividend Declared
On February 5, 2015, our board of directors approved the regular quarterly cash dividend of $0.10 per share on our common stock, payable on March 16, 2015, to holders of record at the close of business on February 26, 2015.
Partnership Distribution
On February 5, 2015, the board of directors of the General Partner declared a cash distribution to the Partnership’s common unitholders of $43,755, or $0.70 per common unit. The cash distribution was paid on March 2, 2015 to unitholders of record at the close of business on February 17, 2015. The total cash distribution paid to non-affiliated common unitholders was $8,055.
Amended Supply and Offtake Agreements
In February 2015, we amended the Supply and Offtake Agreements with J. Aron and extended the initial terms through May 2021 for the Big Spring and Krotz Springs refineries. J. Aron may elect to terminate the Supply and Offtake Agreements for the Big Spring and Krotz Springs refineries prior to the expiration of the initial term beginning in May 2018 and upon each anniversary thereof, on six months prior notice. We may elect to terminate in May 2020 on six months prior notice.



F-41


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



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



Exhibit No.
 
Description of Exhibit
10.26*
 
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).
10.27*
 
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).
10.28*
 
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).
10.29*
 
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).
10.30*
 
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).
10.31*
 
Management Employment Agreement, dated as of May 1, 2008, between Kyle C. McKeen and Alon USA GP, LLC (incorporated by reference to Exhibit 10.47 to Form 10-K, filed by the Company on March 14, 2013 SEC File No. 001-32567).
10.32*
 
Description of Annual Bonus Plans (incorporated by reference to Exhibit 10.56 to Form 10-K, filed by the Company on March 15, 2011 SEC File No. 001-32567).
10.33*
 
Change of Control Incentive Bonus Program (incorporated by reference to Exhibit 10.29 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.34*
 
Description of Director Compensation (incorporated by reference to Exhibit 10.30 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.35*
 
Form of Director Indemnification Agreement (incorporated by reference to Exhibit 10.31 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.36*
 
Form of Officer Indemnification Agreement (incorporated by reference to Exhibit 10.32 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.37*
 
Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.33 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.38*
 
Alon Assets, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.36 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.39*
 
Alon USA Operating, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.37 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.40*
 
Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.38 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.41
 
Second Amendment to Incentive Stock Option Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon Assets, Inc. (incorporated by reference to Exhibit 10.15 to Form 10-Q, filed by the Company on November 7, 2008, SEC File No. 001-32567).
10.42*
 
Shareholder Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Jeff D. Morris, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.39 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.43*
 
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).
10.44
 
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).
10.45
 
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).
10.46*
 
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).



Exhibit No.
 
Description of Exhibit
10.47
 
Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.42 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.48
 
Shareholder Agreement, dated as of July 31, 2000, between Alon Assets, Inc. and Claire A. Hart, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.43 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.49*
 
Amendment to Shareholder Agreements among the Company, Alon Assets, Inc., Alon Operating, Inc., Claire Hart and Claire Hart/IRA, dated June 20, 2012 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on June 26, 2012, SEC File No. 001-32567).
10.50
 
Incentive Stock Option Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended by the Amendment to the Incentive Stock Option Agreement, dated June 30, 2002 and July 25, 2002 (incorporated by reference to Exhibit 10.44 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.51*
 
Shareholder Agreement, dated as of July 31, 2000, between Alon USA Operating, Inc. and Claire A. Hart, as amended by the Amendment to the Shareholder Agreement, dated June 30, 2002 (incorporated by reference to Exhibit 10.45 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.52
 
Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III, as amended by the Amendment to the Incentive Stock Option Agreement, dated July 25, 2002 (incorporated by reference to Exhibit 10.46 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.53*
 
Shareholder Agreement, dated as of February 5, 2001, between Alon Assets, Inc. and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.47 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.54
 
Incentive Stock Option Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III, as amended by the Amendment to the Incentive Stock Option Agreement, dated July 25, 2002 (incorporated by reference to Exhibit 10.48 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.55
 
Shareholder Agreement, dated as of February 5, 2001, between Alon USA Operating, Inc. and Joseph A. Concienne, III (incorporated by reference to Exhibit 10.49 to Form S-1/A, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.56
 
Amendment to Shareholder Agreements – Option Shares, between Alon Assets, Inc., Alon Operating, Inc., Alon USA Energy, Inc. and Joseph A. Concienne, dated October 3, 2011 (incorporated by reference to Exhibit 10.68 to Form 10-K Filed by the Company on March13, 2012, SEC File No. 001-32567).
10.57*
 
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).
10.58*
 
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).
10.59*
 
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).
10.60*
 
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).
10.61*
 
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).
10.62*
 
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).
10.63*
 
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).
10.64*
 
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).



Exhibit No.
 
Description of Exhibit
10.65*
 
Award Agreement between the Company and Paul Eisman, dated May 5, 2011, (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 9, 2011, SEC File No. 001-32567).
10.66
 
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).
10.67
 
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).
10.68
 
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).
10.69
 
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).
10.70
 
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).
10.71
 
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).
10.72
 
Series A Preferred Stock Purchase Agreement, dated as of July 3, 2008, by and between Alon Refining Louisiana, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
10.73
 
Stockholders Agreement, dated as of July 3, 2008, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on July 10, 2008, SEC File No. 001-32567).
10.74
 
Amended and Restated Stockholders Agreement dated as of March 31, 2009, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.88 to Form 10-K, filed by the Company on April 10, 2009, SEC File No. 001-32567).
10.75†
 
First Amendment to Amended and Restated Stockholders Agreement dated as of December 31, 2009, by and among Alon USA Energy, Inc., Alon Refining Louisiana, Inc., Alon Louisiana Holdings, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on January 5, 2010, SEC File No. 001-32567).
10.76
 
Amended and Restated Supply and Offtake Agreement, dated May 26, 2010 by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.76 to Form 10-K, filed by the Company on March 14, 2014, SEC File No. 001-32567).
10.77
 
First Amendment to the Supply and Offtake Agreement, dated January 20, 2011, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 10, 2011, SEC File No. 001-32567).
10.78
 
Amended and Restated Second Amendment to the Supply and Offtake Agreement, dated March 1, 2011, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.3 to Form 10-Q, filed by the Company on May 10, 2011, SEC File No. 001-32567).
10.79†
 
Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on November 7, 2011, SEC File No. 001-32567).
10.80
 
Amendment, dated as of July 20, 2012, to the Amended and Restated Supply and Offtake Agreement, dated May 26, 2010, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.80 to Form 10-K, filed by the Company on March 14, 2014, SEC File No. 001-32567).
10.81†
 
Amendment, dated as of February 1, 2013, to the Amended and Restated Supply and Offtake Agreement, dated May 26, 2010, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 10, 2013, SEC File No. 001-32567).



Exhibit No.
 
Description of Exhibit
10.82
 
Amended and Restated Supply and Offtake Agreement by and between Alon USA, LP and J. Aron & Company, dated March 1, 2011 (incorporated by reference to Exhibit 10.82 to Form 10-K, filed by the Company on March 14, 2014, SEC File No. 001-32567).
10.83†
 
Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon USA, LP and J.Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on November 11, 2011, SEC File No. 001-32567).
10.84
 
Amendment, dated as of July 20, 2012, to the Amended and Restated Supply and Offtake Agreement by and between Alon USA, LP, and J. Aron & Company, dated March 1, 2011 (incorporated by reference to Exhibit 10.84 to Form 10-K, filed by the Company on March 14, 2014, SEC File No. 001-32567).
10.85†
 
Amendment to Supply and Offtake Agreement dated as of February 1, 2013 between J. Aron & Company and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on May 10, 2013, SEC File No. 001-32567).
10.86†
 
Supply and Offtake Agreement by and between J. Aron & Company and Alon Supply, Inc., dated May 30, 2012 (incorporated by reference to Exhibit 10.86 to Form 10-K, filed by the Company on March 14, 2014, SEC File No. 001-32567).
10.87
 
Amendment, dated as of July 20, 2012, to the Supply and Offtake Agreement, dated May 30, 2012, by and between Alon Supply, Inc., and J. Aron and Company (incorporated by reference to Exhibit 10.87 to Form 10-K, filed by the Company on March 14, 2014, SEC File No. 001-32567).
10.88
 
Amendment, dated as of February 1, 2013, to the Supply and Offtake Agreement between J. Aron & Company and Alon Supply, Inc. (incorporated by reference to Exhibit 10.3 to Form 10-Q, filed by the Company on May 10, 2013, SEC File No. 001-32567).
10.89
 
Form of Series A Convertible Preferred Stock Purchase Agreement (incorporated by reference to Exhibit 10.105 to Form S-1/A, filed by the Company on October 22, 2010, SEC File No. 333-169583).
10.90
 
Warrant Agreement, dated March 14, 2011, between the Company and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.106 to Form 10-K, filed by the Company on March 15, 2011 SEC File No. 001-32567).
10.91
 
Form of Series B Convertible Preferred Stock Purchase Agreement (incorporated by reference to Exhibit 10.106 to Form 10-K, filed by the Company on March 13, 2012 SEC File No. 001-32567).
10.92
 
Omnibus Agreement by and among Alon USA Partners, LP, Alon USA Partners GP, LLC, Alon Assets, Inc. and Alon Energy, Inc., dated November 26, 2012 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.93
 
Services Agreement by and among Alon USA Partners, LP, Alon USA Partners GP, LLC by and Alon Energy, Inc., dated November 26, 2012 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.94
 
Tax Sharing Agreement by and among Alon USA Partners, LP and Alon USA Energy, Inc., dated November 26, 2012 (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.95
 
Distributor Sales Agreement by and among Alon USA Partners, LP and Southwest Convenience Stores, LLC, dated November 26, 2012 (incorporated by reference to Exhibit 10.4 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.96
 
Offtake Agreement by and among Alon USA, LP and Paramount Petroleum Corporation, dated November 26, 2012 (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.97
 
Contribution, Conveyance and Assumption Agreement by and among Alon Assets, Inc., Alon USA Partners GP, LLC, Alon USA Partners, LP, Alon USA Energy, Inc., Alon USA Refining, LLC, Alon USA Operating, Inc., Alon USA, LP and Alon USA GP, LLC, dated November 26, 2012 (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on November 26, 2012, SEC File No. 001-32567).
10.98
 
Second Amended Revolving Credit Agreement, dated as of May 23, 2013, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 24, 2013, SEC File No. 001-32567).
10.99
 
Base Bond Hedge Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.100
 
Base Bond Hedge Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).



Exhibit No.
 
Description of Exhibit
10.101
 
Additional Bond Hedge Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.102
 
Additional Bond Hedge Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.4 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.103
 
Base Warrant Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.5 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.104
 
Base Warrant Confirmation dated as of September 10, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.6 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.105
 
Additional Warrant Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.7 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
10.106
 
Additional Warrant Confirmation dated as of September 11, 2013, by and between Alon USA Energy, Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.8 to Form 8-K, filed by the Company on September 16, 2013, SEC File No. 001-32567).
21.1
 
Subsidiaries of Alon USA Energy, Inc.
23.1
 
Consent of KPMG LLP.
31.1
 
Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2
 
Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1
 
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
100
 
The following financial information from Alon USA Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014, formatted in XBRL (Extensible Business Reporting Language): (i) Balance Sheets, (ii) Statements of Operations, (iii) Statements of Comprehensive Income, (iv) Statement of Stockholders’ Equity, (v) Statements of Cash Flows and (vi) Notes to Financial Statements.
____________
*
Identifies management contracts and compensatory plans or arrangements.
Filed under confidential treatment request.




SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
 
Date:
March 13, 2015
By:  
/s/ Paul Eisman
 
 
 
Paul Eisman
 
 
 
President and Chief Executive Officer 
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date:
March 13, 2015
By:  
/s/ David Wiessman 
 
 
 
David Wiessman 
 
 
 
Executive Chairman of the Board
 
 
 
 
Date:
March 13, 2015
By:  
/s/ Jeff D. Morris
 
 
 
Jeff D. Morris
 
 
 
Vice Chairman of the Board
 
 
 
 
Date:
March 13, 2015
By:  
/s/ Paul Eisman
 
 
 
Paul Eisman
 
 
 
President and Chief Executive Officer 
 
 
 
 
Date:
March 13, 2015
By:  
/s/ Shai Even 
 
 
 
Shai Even 
 
 
 
Senior Vice President and Chief Financial Officer
 
 
 
(Principal Accounting Officer)
 
 
 
 
Date:
March 13, 2015
By:  
/s/ Ron W. Haddock
 
 
 
Ron W. Haddock
 
 
 
Director
 
 
 
 
Date:
March 13, 2015
By:  

 
 
 
Boaz Biran
 
 
 
Director
 
 
 
 
Date:
March 13, 2015
By:  
/s/ Yonel Cohen
 
 
 
Yonel Cohen
 
 
 
Director
 
 
 
 
Date:
March 13, 2015
By:  
/s/ Yeshayuhu Pery
 
 
 
Yeshayuhu Pery
 
 
 
Director
 
 
 
 
Date:
March 13, 2015
By:  
/s/ Zalman Segal
 
 
 
Zalman Segal
 
 
 
Director
 
 
 
 
Date:
March 13, 2015
By:  
/s/ Ilan Cohen
 
 
 
Ilan Cohen
 
 
 
Director
 
 
 
 
Date:
March 13, 2015
By:  

 
 
 
Shraga F. Biran
 
 
 
Director
 
 
 
 



Date:
March 13, 2015
By:  

 
 
 
Oded Rubinstein
 
 
 
Director
 
 
 
 
Date:
March 13, 2015
By:  
/s/ Mordehay Ventura
 
 
 
Mordehay Ventura
 
 
 
Director
 
 
 
 
Date:
March 13, 2015
By:  
/s/ Amit Ben Itzhak
 
 
 
Amit Ben Itzhak
 
 
 
Director