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, 2012
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: 001-35742
ALON USA PARTNERS, LP
(Exact name of Registrant as specified in its charter)
Delaware
(State of incorporation)
 
46-0810241
(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 Limited Partner Units
 
New York Stock Exchange
Securities registered pursuant to Section 12 (g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
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 o
Non-accelerated filer þ
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 registrant completed its initial public offering in November 2012. Accordingly, there was no public market for the registrant's common limited partner units as of June 30, 2012, the last day of the registrant’s most recently completed second fiscal quarter.
The number of the Registrant’s common limited partner units outstanding as of March 1, 2013, was 62,501,043.
 
 



TABLE OF CONTENTS

 
 
 
 





PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES.
Statements in this Annual Report on Form 10-K, including those in Items 1 and 2, “Business and Properties,” and Item 3, “Legal Proceedings,” that are not historical in nature should be deemed forward-looking statements that are inherently uncertain. See “Forward-Looking Statements” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of forward-looking statements and of factors that could cause actual outcomes and results to differ materially from those projected.
Company Overview
In this Annual Report, the words “Alon,” the “partnership,” “we,” “us” and “our” or like terms refer to the businesses of Alon USA Partners, LP, a Delaware limited partnership, and its subsidiaries. References in this Annual Report to our "general partner” refer to Alon USA Partners GP, LLC, a Delaware limited liability company and the general partner of the partnership. Unless the context otherwise requires, references in this Annual Report to "Alon Energy" refer to Alon USA Energy, Inc., our parent company and the owner of our general partner, and its consolidated subsidiaries other than us.
On November 26, 2012, the Partnership completed its initial public offering (the "Offering") of 11,500,00 common units (including 1,500,000 common units issued pursuant to the exercise of the underwriters' over-allotment option), representing limited partner interests.
After completion of the Offering, Alon Energy contributed to the Partnership its equity interests in Alon USA, LP and Alon USA Refining, Inc. Prior to completion of the Offering, the assets, liabilities and results of operations of the aforementioned assets related to Alon USA Partners, LP Predecessor ("Predecessor").
We are a limited partnership formed in August 2012 and engaged principally in the business of operating a crude oil refinery in Big Spring, Texas with total throughput capacity of approximately 70,000 barrels per day (“bpd”), which we refer to as our Big Spring refinery. We refine crude oil into finished products, which we market primarily in West Texas, Central Texas, Oklahoma, New Mexico and Arizona through our wholesale distribution network to both Alon Energy’s retail convenience stores and other third-party distributors. 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.alonpartners.com.
Our common units representing limited partner interests trade on the New York Stock Exchange under the trading symbol “ALDW.” We are managed and operated by the board of directors and executive officers of our general partner, an indirect subsidiary of Alon Energy. Our general partner manages our operations and activities subject to the terms and conditions specified in our partnership agreement. Alon Energy owns, directly or indirectly, 81.6% of our outstanding common limited partner units. The operations of our general partner in its capacity as general partner are managed by its board of directors. As a result of owning our general partner, Alon Energy has the ability to appoint all of the members of the board of directors of our general partner, including all of our general partner's independent directors.
Alon Energy is an independent refiner and marketer of petroleum products, operating primarily in the South Central, Southwestern and Western regions of the United States. In addition to its ownership of 81.6% of our outstanding common limited partner units, Alon Energy owns other crude oil refineries in California, Louisiana and Oregon, with an aggregate crude oil throughput capacity of approximately 180,000 barrels per day. Alon Energy is a leading producer of asphalt, which it markets through its asphalt terminals predominately in the Western United States. Alon Energy is the largest 7-Eleven licensee in the United States and operates 298 convenience stores in Texas and New Mexico.
Alon Israel Oil Company, Ltd. (“Alon Israel”) owns a majority of Alon Energy's outstanding common stock. 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.


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We file annual, quarterly and current reports and proxy statements, and file or furnish other information, with the Securities Exchange Commission (“SEC”). Our SEC filings are available to the public at the SEC’s website at www.sec.gov. In addition, we make our SEC filings available free of charge through our website at www.alonpartners.com as soon as reasonably practicable after we file or furnish such material with the SEC. In addition, we will provide copies of our filings free of charge to our unitholders upon request to Alon USA Partners, LP, Attention: Investor Relations, 12700 Park Central Dr., Suite 1600, Dallas, Texas 75251. We have also made the following documents available free of charge through our website at www.alonpartners.com:
Audit Committee Charter;
Corporate Governance Guidelines; and
Code of Business Conduct and Ethics.
Business
Big Spring Refinery
Our Big Spring refinery has a crude oil throughput capacity of approximately 70,000 bpd and is located on 1,306 acres in the Permian Basin in West Texas. In industry terms, our Big Spring refinery is characterized as a “cracking refinery,” which generally refers to a refinery utilizing vacuum distillation and catalytic cracking processes in addition to basic distillation, naphtha reforming and hydrotreating processes, to produce higher light product yields through the conversion of heavier fuel oils into gasoline, light distillates and intermediate products. Major processing units at our Big Spring refinery include fluid catalytic cracking, naphtha reforming, vacuum distillation, hydrotreating and alkylation units.
Our Big Spring refinery has a Nelson complexity rating of 10.2. Our 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 less expensive high-sulfur, or sour, crude oils to produce a high percentage of light, high-value refined products. Typically, sour crude oil has accounted for approximately 80% of the Big Spring refinery’s crude oil input.
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 90.0% of its feedstock into finished products such as gasoline, diesel, jet fuel and petrochemicals, with the remaining 10.0% primarily converted to asphalt and liquefied petroleum gas.
Raw Material Supply
Sour crude oil has typically accounted for approximately 80% of our crude oil input at the Big Spring refinery, which is primarily West Texas Sour (“WTS”) crude oil. Our Big Spring refinery is the closest refinery to Midland, Texas, which is the largest origination terminal for West Texas crude oil. We believe the location and sour crude processing capability of our Big Spring refinery provide us strategic cost advantages for sourcing our crude oil requirements. Our close proximity to the Midland and Cushing markets allows us to source WTS and West Texas Intermediate ("WTI") crude oils, both of which currently trade at a considerable discount to imported waterborne crude oils, such as Brent. Our ability to purchase these less expensive crude oils provides us a cost advantage compared to refineries located on the U.S. Gulf Coast that utilize more expensive waterborne crude oils to produce the refined products they sell in our market area. In addition, our Big Spring refinery’s ability to process substantial volumes of WTS provides us with a further cost advantage. WTS has historically traded at a discount to WTI due to the cost associated with eliminating sulfur content from sour crude in the refining process. Because our Big Spring refinery is able to process substantial volumes of WTS, our overall feedstock costs are generally lower than those of refineries that are not capable of processing high volumes of WTS and therefore must utilize a greater percentage of sweeter, more expensive crudes such as WTI.
In addition to cost advantages resulting from our proximity to domestic crude oil sources and our refinery’s capability to process substantial volumes of WTS, we have been able to capitalize on the oversupply of West Texas crudes in Midland, the largest origination terminal for West Texas crude oil, resulting from increased production in the Permian Basin coupled with infrastructure constraints in Cushing, Oklahoma. Although West Texas crudes are typically transported to Cushing for sale, current logistical and infrastructure constraints at Cushing are limiting the ability of Permian Basin producers to transport their production to Cushing. The resulting oversupply of West Texas crudes at Midland has depressed Midland crude prices and enabled us to access an increased portion of our crude supply at discounted prices to Cushing. Moreover, by sourcing West Texas crude oils at Midland, we are able to eliminate the cost of transporting crude to and from Cushing.
Other feedstocks, including butane, isobutane and asphalt blending components, are delivered by truck and railcar, and 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.


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Prior to 2011, more than half of our crude oil input requirements was purchased through short-term contracts with several suppliers, including major oil companies. In February 2011, we entered into a supply and offtake agreement with J. Aron & Co. ("J. Aron"), pursuant to which we purchase crude oil for processing at the Big Spring refinery, and we amended our agreement with J. Aron in July 2012 and again in February 2013. For the year ended December 31, 2012, J. Aron supplied 52.0% of our crude oil feedstock through arrangements with various oil companies.
The supply and offtake agreement with J. Aron has an initial term that expires in May 2019. J. Aron may elect to terminate the agreement prior to the initial term beginning in May 2016 and upon each anniversary thereof, provided we receive notice of termination at least six months prior to that date. We may elect to terminate the agreement in May 2018, provided we give notice of termination at least six months prior to that date. Following expiration or termination of the supply and offtake agreement, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Big Spring refinery.
Crude Oil Pipelines
We receive WTS crude oil and WTI primarily from regional common carrier pipelines. We also have the ability to access offshore domestic and foreign crude oils available on the Gulf Coast through the Amdel and White Oil pipelines when the economics for processing those crude oils are more favorable than processing locally-sourced crude oils. This combination of access to Permian Basin crude oil and foreign and offshore domestic crude oil from the Gulf Coast allows us to optimize our Big Spring refinery’s crude oil supply.
Refinery Production
Gasoline. In 2012, gasoline accounted for approximately 50.3% of our Big Spring refinery’s production. We produce various grades of gasoline, ranging from 84 sub-octane regular unleaded to 91 octane premium unleaded, and use a computerized component blending system to optimize gasoline blending. Gasoline currently produced at the Big Spring refinery complies with the U.S. Environmental Protection Agency’s (“EPA”) ultra-low sulfur gasoline standard of 30 parts per million (“ppm”).
Distillates. In 2012, diesel and jet fuel accounted for approximately 32.5% of our Big Spring refinery’s production. All of the on-road specification diesel fuel we produce meets the EPA’s ultra-low sulfur diesel standard of 15 ppm. Our jet fuel production conforms to the JP-8 grade military specifications.
Asphalt. Asphalt accounted for approximately 5.9% of our Big Spring refinery’s production in 2012. 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 sold to a subsidiary of Alon Energy at prices substantially determined by reference to the cost of crude oil, which is intended to approximate bulk wholesale market prices.
Petrochemical Feedstocks and Other. We produce propane, propylene, certain aromatics, specialty solvents and benzene for use as petrochemical feedstocks, along with other by-products such as sulfur and carbon black oil. Our Big Spring refinery has sulfur processing capabilities of approximately two tons per thousand bpd of crude oil capacity, which is above the average for cracking refineries and aids in our ability to produce low sulfur motor fuels while continuing to process significant amounts of sour crude oil.
Marketing
Branded Transportation Fuel Marketing. We sell approximately 54% of the gasoline produced at our Big Spring refinery on a branded basis. We sell motor fuel under the Alon brand through various terminals to supply approximately 640 locations, including the majority of Alon Energy’s 298 retail locations and other Alon-branded independent locations. For the year ended December 31, 2012, we sold 393.6 million gallons of branded motor fuel for distribution to Alon Energy’s retail convenience stores and other retail distribution outlets.
Unbranded Transportation Fuel Marketing. We presently sell a majority of the diesel fuel and approximately 23.1% of the gasoline produced at our Big Spring refinery on an unbranded basis. For the year ended December 31, 2012, we sold over 20,648 bpd of our diesel fuel and gasoline production as unbranded fuels, which were largely sold through our physically integrated system.
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 our 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.


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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.
Distribution Network and Distributor Arrangements. We sell motor fuel to Alon Energy’s retail locations and to approximately 20 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. All supplied distributors comply with our ratability program, which involves incentives and penalties based on the consistency of their purchases.
Alon Brand Sub-Licensing. We sub-license the Alon brand and provide payment card processing services, advertising programs and loyalty and other marketing programs to 36 distributors supplying approximately 115 additional stores. We offer sub-licensing to distributors supplying geographic areas where we choose not to supply motor fuels. This sub-licensing program allows us to expand the geographic footprint of the Alon brand, thereby increasing its recognition. Each sub-licensee pays royalties on a per gallon basis and is required to comply with the minimum standards program and utilize our payment card processing services.
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, 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.
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 and Phillips 66. Our industry is also impacted by competition from integrated, multi-national oil companies, including Chevron, ExxonMobil and Shell. Because of their diversity, integration of operations and larger capitalization, these major competitors may have greater financial support and diversity with a potential better ability to bear the economic risks, operating risks and volatile market conditions associated with the petroleum industry.
Financial returns in the refining and marketing industry depend on the difference between refined product prices and the prices for crude oil and other feedstock, also referred to as refining margins. Refining margins are impacted by, among other things, levels of crude oil and refined product inventories, balance of supply and demand, utilization rates of refineries and global economic and political events.
All of our crude oil and feedstocks are purchased from third-party sources, while some of our vertically integrated competitors have their own sources of crude oil that they may use to supply their refineries. However, our Big Spring refinery is in close proximity to Midland, Texas, which is the largest origination terminal for West Texas crude oil, which we believe provides us with transportation cost advantages over many of our competitors in this region.
The market 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 wholesale marketing business are price and quality of products, reliability and availability of supply and location of distribution points.


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Government Regulation and Legislation
Environmental Controls and Expenditures
Our operations are subject to extensive and frequently changing federal, state, regional and local laws, regulations and ordinances relating to the protection of the environment, including those governing emissions or discharges to the air, water, and land, the handling, reclamation and/or disposal of petroleum hydrocarbons, hazardous substances and wastes and the remediation of contamination. We believe our operations are generally in substantial compliance with these requirements. Over the next several years our operations will have to meet new requirements being promulgated by the EPA and the states and jurisdictions in which we operate.
Fuels. The federal Clean Air Act and its implementing regulations require, 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 meets the low sulfur gasoline and diesel fuel standards. The EPA is expected to publish a proposed rule to further reduce sulfur in gasoline and diesel fuel in 2013. Depending on the final standard, our Big Spring refinery may be required to install controls to further reduce sulfur. The need for or costs of any such controls is not known at this time.
In 2007, the EPA adopted final rules to reduce the levels of benzene in gasoline on a nationwide basis. More specifically, beginning in 2011, refiners were required to meet an annual average gasoline benzene content standard of 0.62%, which may be achieved through the purchase of benzene credits, and that beginning on July 1, 2012, refiners were required to meet a maximum average gasoline benzene concentration of 1.30%, by volume on all gasoline produced, both reformulated and conventional and without benzene credits. We have spent $14.2 million through 2012 in order for our Big Spring refinery to install controls to comply with the standards.
We are subject to the renewable fuel standard which requires refiners to blend renewable fuels (e.g., ethanol, biodiesel) into their finished transportation fuels or purchase renewable energy credits, called RINs, in lieu of blending. The EPA generally establishes new annual renewable fuel percentage standards for each compliance year in the preceding year. For 2012, the EPA raised the renewable fuel percentage standard to approximately 9.0%. The EPA has not yet finalized the 2013 renewable fuel percentage standard, but has proposed to raise it to approximately 9.6%. Our Big Spring refinery received an extension of the deadline to comply with the renewable fuel standard. Therefore, we have not been required to blend renewable fuels or purchase RINs for compliance until 2013.
Air Emissions. Conditions may develop that require additional capital expenditures at our Big Spring refinery and product terminals 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.
The EPA has adopted regulations requiring certain new or modified sources of high-volume greenhouse gases ("GHG") emissions to install best achievable control technology to reduce GHG emissions. If we undertake significant improvements at our Big Spring refinery that could result in an increase in GHG emissions, we could be required under EPA’s regulations to install expensive GHG emissions control equipment. Although Congress has from time to time considered adopting legislation to reduce emissions of GHGs through establishment of a market-based “cap and trade” system that would be designed to achieve yearly reductions in GHG emissions, no such legislation has been passed. While it is possible that Congress 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.
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. Since March 2000, at least 31 refining companies (representing over 90% of the U.S. refining capacity) have entered into “global settlements” under the initiative. If we enter into a global settlement, it would apply to our Big Spring refinery. Based on prior settlements that the EPA has reached with other petroleum refineries under the initiative, we anticipate that the EPA will seek relief in the form of the payment of a civil penalty, the installation of air pollution controls, enhanced operations and maintenance programs, and the implementation of environmentally beneficial projects in consideration for a broad release from liability for violations that may have occurred historically. At this time, we cannot estimate the cost of any such controls, civil penalties or environmentally beneficial projects. See “Risk Factors—Risks Inherent in Our Business—We may incur significant costs to comply with new or changing environmental laws and regulations.”


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On July 15, 2010, the EPA disapproved Texas’ “flexible permit program” and indicated that sources operating under a flexible permit issued by the Texas Commission on Environmental Quality (“TCEQ”) are not properly permitted and are subject to enforcement. To address the EPA’s concerns, we have applied for a non-flexible permit. The Big Spring refinery is one of over one hundred regulated facilities in Texas that will be required to obtain a new, non-flexible permit. We do not anticipate that the new non-flexible permit will require new pollution control equipment or a change in our operations. On August 13, 2012, the U.S. Fifth Circuit Court of Appeals vacated the EPA’s final rule disapproving Texas’ flexible permit program and remanded the program back to the EPA for further considerations. We are presently assessing our Big Spring refinery’s air emissions permitting alternatives as a result of this ruling.
Remediation Efforts. We are currently remediating historical soil and groundwater contamination at our Big Spring refinery. To date, we have substantially completed the remediation of the potentially contaminated areas and continue to monitor and treat groundwater at the site. We currently anticipate spending an additional $6.3 million over the next 15 years to remediate soil and groundwater contamination, including contamination at the Abilene, Southlake, and Wichita Falls terminals, which we formerly owned and operated.
In addition, we may be required by the federal Resource Conservation and Recovery Act or the Comprehensive Environmental Resources Compensation and Liability Act and the Texas Solid Waste Disposal Act to pay for remediation of hazardous substance contamination on our property or on other property where wastes from our operations have been released into the environment, regardless of fault or the legality of the original conduct, and to pay for damages to natural resources.
Environmental Insurance. In 2000, we purchased two environmental insurance policies to cover expenditures in excess of $20.0 million, the premiums for which were paid in full. Under an environmental clean-up cost containment, or “cost cap policy,” we are insured for remediation costs for known conditions at the time of our acquisition of the Big Spring refinery. This policy has an initial retention of $20.0 million during the first ten years after the acquisition, which retention is increased by $1.0 million annually during the remainder of the term of the policy. Under an environmental response, compensation and liability insurance policy, or “ERCLIP,” we are insured for bodily injury, property damage, clean-up costs, legal defense expenses and civil fines and penalties relating to unknown conditions and incidents. The ERCLIP policy is subject to a $100,000 per claim/$1.0 million aggregate sublimit on liability for civil fines and penalties and a retention of $150,000 per claim in the case of civil fines or penalties. Both the cost cap policy and ERCLIP have a term of twenty years and share a maximum aggregate limit of $40.0 million. The insurer under these policies is The Kemper Insurance Companies, which has experienced significant downgrades of its credit ratings in recent years and is currently in run-off. However, we have no reason to believe at this time that Kemper will be unable to comply with its obligations under these policies.
Environmental Indemnity to HEP. In connection with our sale of pipelines and terminals to HEP, we entered into an Environmental Agreement dated January 25, 2005 pursuant to which we agreed to indemnify HEP against certain costs and liabilities incurred by HEP to the extent resulting from the existence of environmental conditions at levels requiring remediation under applicable environmental laws at the pipelines or terminals prior to the sale or from our violation of environmental laws with respect to the pipelines and terminals occurring prior to the effective closing date of the sale but, in each case, excluding any such increased costs and liabilities to the extent caused by the actions of HEP. Our environmental indemnification obligations under the Environmental Agreement expire after February 2015. In addition, our indemnity obligations under the Environmental Agreement with respect to the sale of these pipelines and terminals are subject to HEP first incurring $100,000 of damages as a result of pre-existing environmental conditions or violations. Further, our environmental indemnity obligations under the Environmental Agreement, together with any amounts paid by us to HEP with respect to indemnification for breaches of our representations and warranties under a Contribution Agreement entered into as a part of the HEP transaction, are also limited to an aggregate liability amount of $20.0 million.
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 pursuant to which we agreed to indemnify Sunoco against costs and liabilities incurred by Sunoco resulting from the existence of environmental conditions at the pipelines prior to March 1, 2006 or from violations of environmental laws with respect to the pipelines occurring prior to such date. To date, Sunoco has not made any claims against us under the Purchase and Sale Agreement.
Occupational Safety and Health Regulation. We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, process safety standards and control of occupational exposure to regulated substances, could subject us to


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significant fines or cause us to spend significant amounts on compliance, which could have a material adverse effect on our results of operations, financial condition and the cash flows of the business and, as a result, our ability to make distributions.
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 Petroleum Marketing Practices Act (“PMPA”) is a federal law that governs the relationship between a refiner and a distributor pursuant to which the refiner permits a distributor to use a trademark in connection with the sale or distribution of motor fuel. Under the PMPA, we may not terminate or fail to renew branded distributor contracts unless certain enumerated preconditions or grounds for termination or nonrenewal are met and we also comply with the prescribed notice requirements.
Employees
We do not have any employees. We are managed and operated by the directors and officers of our general partner. All of our executive management personnel will be employees of our general partner, Alon Energy or an affiliate of Alon Energy and will devote the portion of their time to our business and affairs that is required to manage and conduct our operations. We will reimburse Alon Energy for the provision of various general and administrative services for our benefit, for direct expenses incurred by Alon Energy on our behalf and for expenses allocated to us as a result of our becoming a public entity.
As of December 31, 2012, Alon Energy had approximately 2,850 employees, approximately 190 of which will be employed at our Big Spring refinery and 30 of which will be employed in our marketing operations. Approximately 120 of the 190 employees at our Big Spring refinery are covered by a collective bargaining agreement that expires on April 1, 2015.
Properties and Insurance
We believe that our properties and facilities are adequate for our operations and are maintained in a good state of repair in the ordinary course of our business.
We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities. Our property and business interruption insurance policies that cover the Big Spring refinery have a $850 million limit, with a $10 million deductible for physical damage and a 75-day waiting period before losses resulting from business interruptions are recoverable. We are fully exposed to all losses in excess of applicable limits and sub-limits and for losses due to business interruptions of fewer than 75 days.


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Executive Officers of the Registrant
The executive officers of our general partner are also executive officers of Alon Energy, and are providing their services to our general partner and us pursuant to the services agreement entered into among us, Alon Energy and our general partner. The executive officers listed below will divide their working time between the management of Alon Energy and us. The approximate weighted average percentages of the amount of time the executive officers spent on management of our business in 2012 are as follows: David Wiessman (25%), Jeff D. Morris (25%), Paul Eisman (25%), Shai Even (25%), Jimmy C. Crosby (100%), Alan Moret (25%), Claire Hart (25%), Michael Oster (25%) and Kyle McKeen (25%).
The table below sets forth the names, positions and ages of the executive officers and directors of our general partner.
 
Name
 
Age
 
Position With Our General Partner
David Wiessman
 
58
 
Executive Chairman of the Board of Directors
Jeff D. Morris
 
61
 
Vice Chairman of the Board of Directors
Paul Eisman
 
57
 
President, Chief Executive Officer and Director
Shai Even
 
44
 
Senior Vice President, Chief Financial Officer
Jimmy C. Crosby
 
53
 
Vice President of Refining and Chief Operating Officer
Alan Moret
 
58
 
Senior Vice President of Supply
Claire Hart
 
57
 
Senior Vice President
Michael Oster
 
41
 
Senior Vice President of Mergers and Acquisitions
Kyle McKeen
 
49
 
Vice President of Wholesale Marketing
David Wiessman—Executive Chairman. Mr. D. Wiessman was appointed Chairman of the board of directors of our general partner in August 2012. Mr. D. Wiessman has served as Executive Chairman of the Board of Directors of Alon Energy since July 2000 and served as President and Chief Executive Officer of Alon Energy from its formation in 2000 until May 2005. Mr. D. Wiessman has over 25 years of oil industry and marketing experience. Since 1994, Mr. D. Wiessman has been Chief Executive Officer, President and a director of Alon Israel, Alon Energy’s parent company. In 1987, Mr. D. Wiessman became Chief Executive Officer of, and a stockholder in, Bielsol Investments (1987) Ltd. (“Bielsol”), which acquired a 50% interest in Alon Israel in 1992. In 1976, after serving in the Israeli Air Force, Mr. D. Wiessman became Chief Executive Officer of Bielsol Ltd., a privately owned Israeli company that owns and operates gasoline stations and owns real estate in Israel. Mr. D. 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 (the “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, all of which are subsidiaries of Alon Israel. Mr. D. Wiessman has also served as Executive Chairman of the Board of Directors of Alon Refining Krotz Springs, Inc. (“Krotz Springs”) since May 2008. Krotz Springs is a subsidiary of Alon Energy through which Alon Energy conducts its Louisiana refining business and which has publicly traded debt in the United States. We believe Mr. D. Wiessman’s vision, business expertise, industry experience, leadership skills and devotion to community service qualify him to serve as Executive Chairman of the board of directors of our general partner. David Wiessman is the father of Snir Wiessman, who joined the board of directors of our general partner in November 2012.
Jeff D. Morris—Vice Chairman. Mr. Morris was appointed Vice Chairman of the board of directors of our general partner in November 2012. Mr. Morris has served as Vice Chairman of the Board of Directors of Alon Energy since May 2011 and a director since May 2005. Prior to this Mr. Morris served as Alon Energy’s Chief Executive Officer from May 2005 to May 2011, as Chief Executive Officer of Alon Energy’s operating subsidiaries from July 2000 to May 2011, Alon Energy’s President from May 2005 until March 2010 and President of its operating subsidiaries from July 2000 until March 2010. Prior to joining Alon Energy, he held various positions at Fina, Inc., where he began his career in 1974. Mr. Morris served as Vice President of Fina’s SouthEastern Business Unit from 1998 to 2000 and as Vice President of its SouthWestern Business Unit from 1995 to 1998. In these capacities, he was responsible for both the Big Spring refinery and Fina’s Port Arthur refinery and the crude oil gathering assets and marketing activities for both business units. Mr. Morris has also been a director of Krotz Springs since 2008. We believe that Mr. Morris’ position as Chief Executive Officer of Alon Energy, detailed knowledge of Alon Energy’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 of directors of our general partner.


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Paul Eisman—President, Chief Executive Officer and Director. Mr. Eisman was appointed President, Chief Executive Officer and Director of our general partner in August 2012. Mr. Eisman became president of Alon Energy in March 2010. Prior to joining Alon Energy, Mr. Eisman was Executive Vice President, Refining & Marketing Operations at Frontier Oil Corporation from March 2006 to October 2009 and held various positions at KBC Advanced Technologies from June 2003 to March 2006, including Vice President of North American Operations. In 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 Refinery Manager at the McKee refinery. Mr. Eisman has also been a director of Alon Refining Krotz Springs, Inc. since May 2010. Mr. Eisman was selected to serve as a director of our general partner because of his position as president of Alon Energy, extensive management experience, leadership skills and knowledge of our operations.
Shai Even—Senior Vice President, Chief Financial Officer. Mr. Even was appointed Senior Vice President, Chief Financial Officer and Director of our general partner in August 2012. Mr. Even has served as Senior Vice President of Alon Energy since August 2008, Vice President of Alon Energy from May 2005 to August 2008 and as Alon Energy’s Chief Financial Officer since December 2004. Mr. Even also served as Alon Energy’s Treasurer from August 2003 until March 2007. Prior to joining Alon Energy, 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 our general partner 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 our general partner in November 2012.
Jimmy C. Crosby—Vice President of Refining and Chief Operating Officer. Mr. Crosby was appointed Vice President of Refining of our general partner in August 2012 and the Chief Operating Officer of our general partner in November 2012. Mr. Crosby has served as Vice President of Refining–Big Spring of Alon Energy since January 2010, with responsibility for operations at the Big Spring refinery. Prior to this, Mr. Crosby served as Vice President of Refining–California Refineries of Alon Energy 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 Energy, 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.
Alan Moret—Senior Vice President of Supply. Mr. Moret was appointed Senior Vice President of Supply of our general partner in August 2012. Mr. Moret has served as Senior Vice President of Supply of Alon Energy since August 2008. Mr. Moret served as Alon Energy’s Senior Vice President of Asphalt Operations from August 2006 to August 2008, with responsibility for asphalt operations and marketing at Alon Energy’s refineries and asphalt terminals. Mr. Moret has also served as an officer of Alon Refining Krotz Springs, Inc. since July 2008. Prior to joining Alon Energy, 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.
Claire Hart—Senior Vice President. Mr. Hart was appointed Senior Vice President of our general partner in August 2012. Mr. Hart has served as Senior Vice President of Alon Energy since January 2004 and also served as Alon Energy’s Chief Financial Officer and Vice President from August 2000 to January 2004. In addition, Mr. Hart has been an officer of Alon Refining Krotz Springs, Inc. since July 2008. Prior to joining Alon Energy, Mr. Hart held various positions in the Finance, Accounting and Operations departments of FINA for 13 years, serving as Treasurer from 1998 to August 2000 and as General Manager of Credit Operations from 1997 to 1998.
Michael Oster—Senior Vice President of Mergers and Acquisitions. Mr. Oster was appointed Senior Vice President of Mergers and Acquisitions of our general partner in August 2012. Mr. Oster has served as Senior Vice President of Mergers and Acquisitions of Alon Energy since August 2008 and has served as an officer of Alon Refining Krotz Springs, Inc. since August 2009. Prior to joining Alon Energy, Mr. Oster was a partner in the Israeli law firm of Yehuda Raveh and Co.
Kyle McKeen—Vice President of Wholesale Marketing. Mr. McKeen was appointed Vice President of Wholesale Marketing of our general partner in August 2012. Mr. McKeen has served as President and Chief Executive Officer of Alon Brands, Inc., Alon Energy’s subsidiary that manages retail and branded 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


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to joining Carter Energy in 2005, Mr. McKeen was a member of the Board of Managers of Alon USA Interests, LLC from September 2002 to 2005 and held numerous positions of increasing responsibilities with Alon Energy, including Vice President of Marketing.
ITEM 1A. RISK FACTORS.
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this annual report.
If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.
We may not have sufficient available cash to pay any quarterly distribution on our common units.
We may not have sufficient available cash each quarter to enable us to pay any distributions to our unitholders. The amount we will be able to distribute on our common units principally depends on the amount of cash we generate from our operations, which is primarily dependent upon operating margins. Our operating margins, and thus, the cash we generate from operations have been volatile, and we expect that they will fluctuate from quarter to quarter based on, among other things:
the cost of refining feedstocks, such as crude oil, that are processed and blended into refined products;
the prices at which we are able to sell refined products;
the level of our direct operating expenses, including expenses such as maintenance and energy costs;
seasonality and weather conditions;
overall economic and local market conditions; and
non-payment or other non-performance by our customers and suppliers.
The actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
our operating margins;
the level of capital expenditures we make;
our debt service requirements;
the amount of any accrued but unpaid expenses;
the amount of any reimbursement of expenses incurred by our general partner and its affiliates;
fluctuations in our working capital needs;
our ability to borrow funds and access capital markets;
planned and unplanned maintenance at our facility that, based on determinations by the board of directors of our general partner to maintain reserves, may negatively impact our cash flows in the quarter in which such maintenance occurs;
restrictions on distributions and on our ability to make working capital borrowings;
the amount of cash reserves established by our general partner, including for turnarounds, catalyst replacement and related expenses; and
Our partnership agreement does not require us to pay a minimum quarterly distribution. The amount of distributions that we pay, if any, and the decision to pay any distribution at all, is determined by the board of directors of our general partner. Our quarterly distributions, if any, are subject to significant fluctuations based on the above factors.


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The price volatility of crude oil and other feedstocks and refined products may have a material adverse effect on our earnings, profitability and cash flows, and our ability to make distributions to unitholders.
Our earnings, profitability, cash flows from operations and our ability to make distributions to unitholders depend primarily on the margin between refined product prices and the prices for crude oil and other feedstocks. When the margin between refined product prices and crude oil and other feedstock prices contracts or inverts, as has been the case in recent periods and may 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. For example, from January 2007 to December 2012, the price for NYMEX Cushing WTI crude oil fluctuated between $31.27 and $145.31 per barrel and the price for Midland WTS crude oil fluctuated between $31.27 and $145.31 per barrel, while the price for U.S. Gulf Coast conventional gasoline fluctuated between $32.27 per barrel and $199.34 per barrel. While an increase or decrease in the price of crude oil may result in a similar increase or decrease in prices for refined products, there may be a time lag in the realization, if any, of the similar increase or decrease in prices for refined products over the long term. The effect of changes in crude oil prices on our refining margins therefore depends in part on how quickly and how significantly refined product prices adjust to reflect these changes.
Prices of crude oil and other feedstocks, 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;
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 of and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;
operating hazards, natural disasters, casualty losses and other matters beyond our control;
the impact of global economic conditions, including the current European financial crisis, on our business; and
the development and marketing of alternative and competing fuels.
Although we continually analyze our operating margins 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.


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The price volatility of crude oil and refined products will affect the market value of our inventories, which could have a material adverse effect on our ability to make distributions to unitholders.
The nature of our business has historically required us to maintain substantial quantities of crude oil and refined product inventories. Because crude oil and refined products are essentially commodities, we have no control over the changing market value of these inventories. Our inventory is valued at the lower of cost or market value under the last-in, first-out (“LIFO”) inventory valuation methodology. As a result, if the market value of our inventory were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of sales. Our investment in inventory is 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 ability to pay distributions to our unitholders.
The price volatility of fuel and utility services may have a material adverse effect on our earnings, profitability and cash flows, and our ability to make distributions to unitholders.
The volatility in costs of natural gas, electricity and other utility services used by our refinery 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 that result in increased operating costs may have a negative effect on our earnings, profitability and cash flows, and our ability to make distributions to unitholders.
Changes in the WTI–Brent or Cushing WTI–Midland WTS differentials could adversely affect the crude oil cost advantage that has been in our favor, which could negatively affect our profitability.
Our profit margins depend primarily on the spread between the price of crude oil and the price of our refined products. Our ability to purchase and process less expensive crudes, such as WTS and WTI, which currently trade at a considerable discount to imported waterborne crude oils, such as Brent, has provided us with a significant cost advantage relative to many of our competitors. However, between October and November 2011, the WTI spot price increased $22.75 per barrel while the price of Brent crude oil increased only $8.81 per barrel. As a result, the WTI–Brent crude oil price differential narrowed to under $10.13 per barrel. The increase in the WTI spot price was due in part to a perception that constraints on transportation of crude oil out of the U.S. Midwest were easing. For example, the Seaway Crude Pipeline System, which historically has transported crude oil to Cushing, Oklahoma from the U.S. Gulf Coast, has recently been reversed such that it currently transports crude from Cushing to the U.S. Gulf Coast. The ability to ship crude oil out of Cushing via pipeline, while not eliminating delays in moving WTI crude oil to other markets, is expected to allow WTI and similar inland U.S. crudes to compete directly with the higher-priced waterborne crude oils available on the Gulf Coast. As a result, the price of WTI may be brought more in line with prices for other crude oils trading on the global markets.
Because our refinery is able to process substantial volumes of WTS, our overall feedstock costs are generally lower than those of refineries that lack this capability and therefore must utilize a greater percentage of sweeter crudes such as WTI. Any narrowing of the Cushing WTI–Midland WTS differential in the future would also result in a reduction of our crude oil source cost advantage.
Future declines in the WTI–Brent or Cushing WTI–Midland WTS differentials could adversely impact our earnings and profitability.
The easing of logistical and infrastructure constraints at Cushing, Oklahoma could adversely affect our crude oil cost advantage.
Due to logistical and infrastructure constraints at the Cushing, Oklahoma transport hub, which have resulted in an oversupply of crude oil at Midland, Texas, we have historically been able to purchase WTS and WTI at discounted prices to Cushing. Moreover, by sourcing West Texas crude oils at Midland, we are able to eliminate the cost of transporting crude supply to and from Cushing. If the constraints at Cushing begin to ease due to the building of additional pipeline capacity and logistics assets, the discount at which we source our West Texas crude supply at Midland relative to Cushing may decrease.
The easing of infrastructure constraints in Cushing and other changes in market dynamics could adversely impact our earnings and profitability.


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The amount of our quarterly cash distributions, if any, will vary significantly both quarterly and annually and will be directly dependent on the performance of our business. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.
Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. We expect our business performance will be more volatile, and our cash flows will be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly cash distributions will be volatile and are expected to vary quarterly and annually. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The amount of our quarterly cash distributions will be directly dependent on the performance of our business, which has been historically volatile and seasonal, and which we expect will continue to be volatile and seasonal. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero. See “Cash Distribution Policy and Restrictions on Distributions.”
The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to make any distributions at all.
The board of directors of our general partner has adopted a cash distribution policy pursuant to which we distribute all of the available cash we generate each quarter to unitholders of record on a pro rata basis. However, the board may change such policy at any time at its discretion and could elect not to make distributions for one or more quarters. Our partnership agreement does not require us to make any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders.
We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.
If we cannot generate sufficient cash flows or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations, comply with certain deadlines related to environmental regulations and standards or pursue our business strategies, any of which could have a material adverse effect on our results of operations or liquidity. We have substantial short-term capital needs and may have substantial long-term capital needs. Our short-term working capital needs are primarily related to financing our inventory and accounts receivable. Our long-term needs for cash include those to support ongoing capital expenditures for equipment maintenance and upgrades during turnarounds at our refinery and for costs of catalyst replacement and to complete our routine and normally scheduled maintenance, regulatory and security expenditures. For example, we expect to perform our next major turnaround during the first quarter of 2014. We estimate total major turnaround expense at the Big Spring refinery of approximately $23.0 million in the aggregate over a five year turnaround cycle. The refinery is expected to be shut down for a portion of the first quarter of 2014 to complete the turnaround. In addition, from time to time, we are required to spend significant amounts for repairs when one or more processing units experiences temporary shutdowns. We continue to utilize significant capital to upgrade equipment, improve facilities, and reduce operational, safety and environmental risks. We may incur substantial compliance costs in connection with any new environmental, health and safety regulations. In addition, the board of directors of our general partner will adopt a distribution policy pursuant to which we will distribute an amount equal to the available cash we generate each quarter to unitholders. As a result, we will need to rely on external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our growth. Our liquidity will affect our ability to satisfy any of these needs. The board of directors of our general partner may change our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis. See “Cash Distribution Policy and Restrictions on Distributions.”
The recent recession and credit crisis and related turmoil in the global financial system has had and may continue to have an adverse impact on our business, results of operations and cash flows.
Our business and profitability are affected by the overall level of demand for our products, which in turn is affected by factors such as overall levels of economic activity and business and consumer confidence and spending. Declines in global economic activity and consumer and business confidence and spending have in the past, and may in the future, significantly reduced the level of demand for our products, including by consumers and our wholesale customers. In the past, severe reductions in the availability and increases in the cost of credit have adversely affected our ability to fund our operations and operate our refinery at full capacity, and have adversely affected our operating margins. Together, these factors have had and may in the future have an adverse impact on our business, financial condition, results of operations and cash flows.


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Our business is indirectly exposed to risks faced by our suppliers, customers and other business partners. The impact on these constituencies of the risks posed by the recent recession and credit crisis and related turmoil in the global financial system have included or could include interruptions or delays in the performance by counterparties to our contracts, reductions and delays in customer purchases, delays in or the inability of customers to obtain financing to purchase our products and the inability of customers to pay for our products. Any of these events may have an adverse impact on our business, financial condition, results of operations and cash flows.
The dangers inherent in our operations could cause disruptions and could expose us to potentially significant losses, costs or liabilities. We are particularly vulnerable to disruptions in our operations because all of our refining operations are conducted at a single facility.
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, 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. For example, on February 18, 2008, a fire at the Big Spring refinery destroyed the propylene recovery unit and damaged equipment in the alkylation and gas concentration units, forcing a temporary shutdown. Although the crude unit was restarted in April 2008, repairs and reconstruction continued through the first quarter of 2010. In addition, in 2010, we implemented new operating procedures at the refinery that also resulted in downtime. As a result of the fire in 2008 and subsequent activities, we had significantly lower throughput and net sales in 2009 and 2010 than in 2011. Because all of our refining operations are conducted at a single refinery, any such event at our refinery 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, and as a result, our ability to make distributions.
We are subject to interruptions of supply as a result of our reliance on pipelines for transportation of crude oil and refined products.
Our refinery receives a substantial percentage of its crude oil and delivers a substantial percentage of its refined products through pipelines. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, earthquakes, hurricanes, governmental regulation, terrorism or other third party action. Our prolonged inability to use any of the pipelines that we use to transport crude oil or refined products could have a material adverse effect on our business, results of operations and cash flows.
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.


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Our ability to service our indebtedness will depend on our ability to generate cash in the future.
Our ability to make payments on our indebtedness will depend on our ability to generate cash in the future. Our ability to generate cash is subject to general economic and market conditions and financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will generate sufficient cash to fund our working capital requirements, capital expenditure, debt service and other liquidity needs, which could result in our inability to comply with financial and other covenants contained in our debt agreements, our being unable to repay or pay interest on our indebtedness, and our inability to fund our other liquidity needs. If we are unable to service our debt obligations, fund our other liquidity needs and maintain compliance with our financial and other covenants, we could be forced to curtail our operations, our creditors could accelerate our indebtedness and exercise other remedies and we could be required to pursue one or more alternative strategies, such as selling assets or refinancing or restructuring our indebtedness. However, we cannot assure you that any such alternatives would be feasible or prove adequate.
Covenants in the credit agreements governing our indebtedness could limit our ability to undertake certain types of transactions and adversely affect our liquidity.
The credit agreements governing our indebtedness may 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 may be subject to negative covenants that restrict our activities, including 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 distributions, debt and other restricted payments, including distributions to our unitholders. Should we desire to undertake a transaction that is prohibited or limited by the credit agreements governing our indebtedness, we may 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.
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 refinery 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 relationship with Alon Energy and its financial condition subjects us to potential risks that are beyond our control.
Due to our relationship with Alon Energy, adverse developments or announcements concerning Alon Energy could materially adversely affect our financial condition, even if we have not suffered any similar development. As a result, downgrades of the credit ratings of Alon Energy could increase our cost of capital and collateral requirements, and could impede our access to the capital markets.
The credit and business risk profiles of Alon Energy may be factors considered in credit evaluations of us. This is because we rely on Alon Energy for various services, including management services. Another factor that may be considered is the financial condition of Alon Energy, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness. The credit and risk profile of Alon Energy could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital. If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of Alon Energy, as credit rating agencies may consider the leverage and credit profile of Alon Energy and its affiliates because of their ownership interest in and joint control of us and the strong operational links between Alon Energy’s business and us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to unitholders.
On a historical basis, we sold 19.2% and 19.1% of the motor fuels we produced and all of the asphalt we produced to Alon Energy during the years ended December 31, 2012 and 2011, respectively. In addition, we entered into a 20-year fuel supply agreement with Alon Energy under which we will supply substantially all of the motor fuel requirements of Alon


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Energy’s retail convenience stores. We also entered into a 20-year asphalt supply agreement with Alon Energy. Because a significant percentage of our sales are to Alon Energy, adverse developments concerning Alon Energy’s financial condition could result in adverse effects on our net sales. This would in turn adversely affect our profitability and ability to make distributions to unitholders.
Our arrangement with J. Aron exposes us to J. Aron related credit and performance risk.
We have a supply and offtake agreement with J. Aron, who is our largest supplier of crude oil and largest customer of refined products. For the year ended December 31, 2012, we purchased 52.0% of our crude oil from J. Aron and J. Aron accounted for 12.3% of our total sales of refined products. In the future, we could purchase up to 100% of our supply needs from J. Aron pursuant to this agreement. Additionally, we are obligated to repurchase all consigned inventories and certain other inventories upon termination of this agreement, which may be terminated by J. Aron as early as May 31, 2016. Relying on J. Aron’s ability to honor its fuel requirements purchase obligations exposes us to J. Aron’s credit and business risks. An adverse change in J. Aron’s business, results of operations, liquidity or financial condition could adversely affect its ability to perform its obligations, which could consequently have a material adverse effect on our business, results of operations or liquidity and, as a result, our ability to make distributions. In addition, we may be required to use substantial capital to repurchase inventories from J. Aron upon termination of the agreement, 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 business of exploration and production of oil 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.
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 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 U.S. Environmental Protection Agency (“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. Since March 2000, at least 31 refining companies (representing over 90% of the U.S. refining capacity) have entered into “global settlements” under the Initiative. In February 2007, we committed in writing to enter into discussions with the EPA regarding our Big Spring refinery and, since that time, have held negotiations with the agency with respect to entering into a global settlement under the Initiative. Based on our on-going negotiations as well as consideration of prior settlements that the EPA has reached with other petroleum refineries under the Initiative, we believe that the EPA will seek relief under any global settlement in the form of the payment of a civil penalty, the installation of air pollution controls, enhanced operations and maintenance programs, and the implementation of environmentally beneficial projects in consideration for a broad release from liability for violations that may have occurred historically at the Big Spring refinery. At this time, while we cannot estimate the cost of any such civil penalties, pollution


16


controls or environmentally beneficial projects, these costs could be significant and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our Big Spring refinery is one of more than 100 facilities in Texas to receive a Clean Air Act request for information from the EPA relating to the EPA’s disapproval of Texas’ “flexible permit program.” According to the EPA, the Texas flexible permit program and its implementing rule was never approved by the EPA for inclusion in the Texas state clean-air implementation plan and, therefore, emission limitations in Texas flexible permits are not federally enforceable. The EPA indicated that it would consider enforcement against holders of flexible permits that failed to comply with applicable federal requirements on a case-by-case basis. We have agreed to convert the refinery’s non-flexible permit to a federally enforceable non-flexible permit and currently are in the process of such conversion. It is unclear whether we will have any obligation to install new air pollution controls or be assessed civil penalties. On August 13, 2012, the U.S. Fifth Circuit Court of Appeals vacated the EPA’s final rule disapproving Texas’ flexible permit program and remanded the program back to the EPA for further consideration. We are presently assessing our Big Spring refinery’s air emissions permitting alternatives as a result of this ruling.
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, on June 1, 2012, the EPA issued final amendments to the New Source Performance Standards (“NSPS”) for petroleum refineries, including standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. EPA has finalized this rule and published it in the Federal Register on September 12, 2012. We are currently evaluating the effect that the NSPS rule may have on our refinery operations. As another example, the EPA proposed new “Tier 3” motor vehicle emission and fuel standards in 2012 which may result in further restrictions on the permissible levels of sulfur in gasoline. We are not able to predict the impact of 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 greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act including one rule that requires a reduction in emissions of GHGs from motor vehicles and another rule that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. The stationary source final rule addresses the permitting of GHG emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit programs, pursuant to which these permit programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources subject to permitting first and smaller sources subject to permitting later. Facilities required to obtain PSD permits for their GHG emissions will be required to reduce those emissions according to “best available control technology” standards for GHGs. The EPA’s rule relating to emissions of GHGs from large stationary sources of emissions has been subject to a number of legal challenges, with the federal D.C. Circuit Court of Appeals dismissing the challenges to EPA’s tailoring rule on June 26, 2012. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis, for emissions occurring after January 1, 2010.
In addition, the federal Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or monitoring and reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas produced by our customers, which could reduce demand for our refining services. One or more of these developments could have an adverse effect on our business, financial condition and results of operations.


17


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 refinery and terminals arising from our or predecessor operators’ handling of petroleum hydrocarbons and wastes. We have reserved approximately $6.3 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. There can be no assurances, however, that costs will be limited to 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 three of our pipelines and three of our terminals to Holly Energy Partners, L.P. (“HEP”) and two of our pipelines pursuant to a transaction with an affiliate of Sunoco, Inc. (“Sunoco”), we have agreed, subject to certain limitations, to indemnify HEP and Sunoco for costs and liabilities that may be incurred by HEP or 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 HEP or Sunoco, such costs and payments could be significant and could adversely affect our business, results of operations and cash flows.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with 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, cash flows or ability to make distributions to unitholders.
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, and our ability to make distributions to our unitholders.
Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, the EPA has issued Renewable Fuels Standards (“RFS”) implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under RFS, the volume of renewable fuels that obligate refineries like the Big Spring refinery must blend into their finished petroleum fuels increases annually over time until 2022. Although we currently do not purchase renewable identification number credits (“RINS”) for fuel categories on the open market, in the future, we may be required to do so to comply with RFS. We cannot currently predict the future prices of RINS or waiver credits, but the costs to obtain the necessary number of RINS and waiver credits could be material. On October 13, 2010, the EPA raised the maximum amount of ethanol allowed under federal law from 10% to 15% for cars and light trucks manufactured since 2007, and on January 21, 2011, EPA extended the maximum allowable ethanol content of 15% to apply to cars and light trucks manufactured since 2001. The maximum amount allowed under federal law currently remains at 10% ethanol for all other vehicles. Existing laws and regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum fuels may increase. Because we do not produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products displaces an increasing volume of our refinery’s product pool, potentially resulting in lower earnings and materially adversely affecting our ability to make distributions.


18


Terrorist attacks, threats of war or actual war may negatively affect our operations, financial condition, results of operations and prospects.
Terrorist attacks, threats of war or actual war, as well as events occurring in response to or in connection with them, may adversely affect our operations, financial condition, results of operations and prospects. Energy-related assets (which could include refineries, terminals and pipelines such as ours) may be at greater risk of terrorist attacks than other possible targets in the United States. A direct attack on our assets or assets used by us could have a material adverse effect on our business, 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 an adverse impact on the margins from our refining and marketing operations. In addition, disruption or significant increases in energy prices could result in government-imposed price controls.
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 and business interruption insurance policies that cover the Big Spring refinery have a $850 million limit, with a $10 million deductible for physical damage and a 75-day waiting period before losses resulting from business interruptions are recoverable. We are fully exposed to all losses in excess of the applicable limits and sub-limits and for losses due to business interruptions of fewer than 75 days. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
We are exposed to risks associated with the credit-worthiness of the insurer of our environmental policies.
The insurer under two of our environmental policies is The Kemper Insurance Companies, which has been operating under a run-off plan administered by the Illinois Department of Insurance since 2004 and has experienced significant downgrades of its credit ratings in recent years. These two policies are 20-year policies that were purchased to protect us against expenditures in excess of $20 million. Our insurance brokers have advised us that environmental insurance policies with terms in excess of ten years are not currently available and that policies with shorter terms are available only at premiums equal to or in excess of the premiums paid for our policies with Kemper. Accordingly, we are currently subject to the risk that Kemper will be unable to fully comply with its obligations under these policies and that comparable insurance may not be available or, if available, at premiums equal to or in excess of our current premiums with Kemper. However, we have no reason at this time to believe that Kemper will not be able to comply with its obligations under these policies.
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 workforce is unionized, and we may face labor disruptions that would interfere with our operations.
As of December 31, 2012, Alon Energy employed approximately 190 people at our Big Spring refinery, approximately 120 of whom were covered by a collective bargaining agreement. The collective bargaining agreement expires on April 1, 2015. The 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 may not be able to successfully execute our strategy of growth through acquisitions.
A component of our growth strategy is to selectively pursue accretive acquisitions within our refining and wholesale marketing assets, both in our existing areas of operations as well as in new geographic regions that would diversify our


19


operating footprint. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth and many other factors beyond our control. Risks associated with acquisitions include those relating to:
diversion of management time and attention from our existing business;
challenges in managing the increased scope, geographic diversity and complexity of operations;
difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;
our ability to understand and capitalize on supply/demand balances in the markets of such acquired assets;
liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;
greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for investments to improve operating results;
difficulties in achieving anticipated operational improvements;
incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and
issuance of additional equity, which could result in further dilution of the ownership interest of existing unitholders.
We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.
The wholesale fuel distribution industry is characterized by intense competition and fragmentation and our failure to effectively compete could adversely affect our business and results of operations.
The market for distribution of wholesale motor fuel is highly competitive and fragmented. We have numerous competitors, some of which have significantly greater resources and name recognition than us. We rely on our ability to provide reliable supply and value-added services and to control our operating costs in order to maintain our margins and competitive position. If we were to fail to maintain the quality of our services, customers could choose alternative distribution sources and our competitive position could be adversely affected. Furthermore, we compete against major oil companies with integrated marketing businesses. Through their greater resources and access to crude oil, these companies may be better able to compete on the basis of price or offer lower wholesale and retail pricing which could negatively affect our fuel margins. The occurrence of any of these events could have a material adverse effect on our business and results of operations.
Commodity derivative contracts may limit our potential gains, exacerbate potential losses, result in period-to-period earnings volatility and involve other risks.
We may enter into commodity derivatives contracts to mitigate our crack spread risk with respect to a portion of our expected gasoline and diesel production. We enter into these arrangements with the intent to secure a minimum fixed cash flow stream on the volume of products hedged during the hedge term. However, our hedging arrangements may fail to fully achieve these objectives for a variety of reasons, including our failure to have adequate hedging contracts, if any, in effect at any particular time and the failure of our hedging arrangements to produce the anticipated results. We may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, while intended to reduce the adverse effects of fluctuations in crude oil and refined product prices, such transactions may limit our ability to benefit from favorable changes in margins. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:
the volumes of our actual use of crude oil or production of the applicable refined products is less than the volumes subject to the hedging arrangement;
accidents, interruptions in feedstock transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refinery, or those of our suppliers or customers;
the counterparties to our futures contracts fail to perform under the contracts; or
a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.


20


As a result, the effectiveness of our risk mitigation strategy could have a material adverse impact on our financial results and our ability to make distributions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk.”
The adoption of regulations implementing recent financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.
The U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act in 2010 (the “Dodd-Frank Act”). This comprehensive financial reform legislation establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. The CFTC has adopted regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or derivative instruments would be exempt from these position limits. The Dodd-Frank Act may also require compliance with margin requirements and with certain clearing and trade-execution requirements in connection with certain derivative activities, although the application of those provisions to us is uncertain at this time. The legislation may also require certain counterparties to our commodity derivative contracts to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty, or cause the entity to comply with the capital requirements, which could result in increased costs to counterparties such as us. The final rules will be phased in over time according to a specified schedule which is dependent on finalization of certain other rules to be promulgated by the CFTC and the SEC.
The Dodd-Frank Act and any new regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing commodity derivative contracts and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and any new regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to make distributions or plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd- Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the Dodd-Frank Act and any new regulations result in lower commodity prices, our net sales could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations and therefore could have an adverse effect on our ability to make distributions.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 3. LEGAL PROCEEDINGS.
In the ordinary conduct of our business, we are subject to periodic lawsuits, investigations and claims, including environmental claims and employee related matters. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, results of operations, cash flows or financial condition.
ITEM 4. MINE SAFETY DISCLOSURES.
None.


21


PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Market Information
Our common limited partner units are traded on the New York Stock Exchange under the symbol “ALDW.”
The following table sets forth the quarterly high and low sales prices of our units for the period most recently completed:
Quarterly Period
 
High
 
Low
 
 
 
 
 
2012
 
 
 
 
Fourth Quarter
 
$
25.83

 
$
16.84

Holders
As of March 1, 2013, there were approximately 3 unitholders of record.
Distributions
On February 13, 2013 the Board of the General Partner announced a cash distribution to the Partnership's common unitholders for the period following the closing of its initial public offering through and including December 31, 2012 of $0.57 per common unit. The cash distribution was paid on March 1, 2013 to unitholders of record at the close of business on February 22, 2013.
The following table presents the methodology for determining the distribution amount, which was based on preliminary financial results for the period following the closing of the initial public offering through December 31, 2012 ("Post IPO Period"). The preliminary financial results presented below for the Post IPO Period and the actual results for the corresponding period were materially consistent.


22


ALON USA PARTNERS, LP
PRORATA CASH AVAILABLE FOR DISTRIBUTION
(dollars in thousands, except per unit data)
 
 
Post IPO Period
 
Year Ended December 31, 2012
 
 
(unaudited)
 
 
Net sales
 
$
324,237

 
$
3,476,817

Operating costs and expenses:
 
 
 
 
Cost of sales
 
264,960

 
2,883,741

Direct operating expenses
 
10,687

 
100,908

Selling, general and administrative expenses
 
2,153

 
22,807

Depreciation and amortization
 
4,632

 
46,009

Total operating costs and expenses
 
282,432

 
3,053,465

Operating income
 
41,805

 
423,352

Interest expense
 
(4,335
)
 
(22,235
)
Interest expense - related parties
 

 
(15,691
)
Other expense, net
 
(2
)
 
8

Income before state income tax expense
 
37,468

 
385,434

State income tax expense
 
348

 
3,536

Net income
 
37,120

 
381,898

Adjustments to reconcile net income to Adjusted EBITDA:
 
 
 
 
Interest expense
 
4,335

 
22,235

Interest expense - related parties
 

 
15,691

State income tax expense
 
348

 
3,536

Depreciation and amortization
 
4,632

 
46,009

Adjusted EBITDA
 
46,435

 
469,369

Adjustments to reconcile Adjusted EBITDA to cash available for distribution before special expenses:
 
 
 
 
less: Maintenance/growth capital expenditures
 
4,633

 
 
less: Turnaround and catalyst replacement capital expenditures
 

 
 
less: Major turnaround reserve
 
438

 
 
less: Principal payments
 

 
 
less: State income tax expense
 
348

 


less: Interest paid in cash
 
4,091

 


less: Interest paid in cash - related parties
 

 
 
Cash available for distribution before special expenses
 
36,925

 


less: Special turnaround reserve
 
1,547

 
 
Cash available for distribution
 
$
35,378

 


 
 
 
 
 
Common units outstanding (in 000's)
 
62,500

 
 
 
 
 
 
 
Cash available for distribution per unit
 
$
0.57

 


Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
None.


23


Unitholder 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 unitholder return on Alon common units as traded on the NYSE with the Standard & Poor’s 500 Stock Index (the “S&P 500”), the Alerian MLP Index ("MLP Index") and our peer group. It is assumed that (i) $100 was invested in our common units at $18.40 per unit (the closing price at the end of our first trading day), the S&P 500, the MLP Index and the peer group on November 20, 2012 (our first day of trading) and (ii) dividends were reinvested on the relevant payment dates. The “Peer Group” includes Northern Tier Energy LP. The following performance graph is historical and not necessarily indicative of future price performance.
 
11/20/2012
 
11/30/2012
 
12/31/2012
Alon USA Partners
$
100.00

 
$
102.61

 
$
130.82

S&P 500
100.00

 
100.58

 
101.50

Alerian MLP Index
100.00

 
101.71

 
98.67

Peer Group
100.00

 
105.24

 
114.91


ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial and operating data as of and for each of the five years in the period ending December 31, 2012. The selected historical combined financial data for the years ended December 31, 2011, 2010 and 2009 are derived from audited combined financial statements of Alon USA Partners, LP Predecessor. The selected historical combined financial data for the year ended December 31, 2008 is derived from unaudited combined financial statements of Alon USA Partners, LP Predecessor. The selected historical financial data for the 2012 period presented through November 26, 2012 is also derived from combined financial results of Alon USA Partners, LP Predecessor, and the period beginning November 27, 2012 is derived from consolidated financial results of Alon USA Partners, LP.


24


The selected historical statement of operations and statement of cash flows data for the years ended December 31, 2012, 2011 and 2010, and the selected consolidated balance sheet data as of December 31, 2012 and 2011, are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
The following selected historical consolidated financial and operating data should be read in conjunction with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K.
 
Year Ended December 31,
 
2012
 
 
2011
 
2010
 
2009
 
2008 (2)
 
 
 
 
Predecessor
 
Predecessor
 
Predecessor
 
Predecessor
 
(in thousands, except per common unit data)
Statements of Operations Data (1):
 
 
 
 
 
 
 
 
 
 
Net sales
$
3,476,817

 
 
$
3,207,969

 
$
1,639,935

 
$
1,498,176

 
$
2,202,403

Operating costs and expenses
3,053,465

 
 
2,877,177

 
1,647,662

 
1,541,574

 
2,360,839

Gain on involuntary conversion of assets

 
 

 

 

 
279,680

Gain on disposition of assets

 
 

 

 
2,105

 
3,352

Operating income (loss)
423,352

 
 
330,792

 
(7,727
)
 
(41,293
)
 
124,596

Interest expense
(37,926
)
 
 
(33,786
)
 
(30,381
)
 
(25,238
)
 
(26,697
)
Other income (loss), net
8

 
 
18

 
(269
)
 
183

 
667

Income (loss) before state income tax expense
385,434

 
 
297,024

 
(38,377
)
 
(66,348
)
 
98,566

State income tax expense
3,536

 
 
2,597

 
136

 

 

Net income (loss)
$
381,898

 
 
$
294,427

 
$
(38,513
)
 
$
(66,348
)
 
$
98,566

 
 
 
 
 
 
 
 
 
 
 
Net income
$
381,898

 
 
 
 
 
 
 
 
 
Less: Net income attributable to predecessor operations
344,778

 
 
 
 
 
 
 
 
 
Net income attributable to Alon USA Partners, LP
$
37,120

 
 
 
 
 
 
 
 
 
Earnings per unit, basic
$
0.59

 
 
 
 
 
 
 
 
 
Weighted average common units outstanding (in thousands)
62,500

 
 
 
 
 
 
 
 
 
Cash distribution per limited partner unit
$
0.57

 
 
 
 
 
 
 
 
 
Statements of Cash Flow Data:
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
 
Operating activities
$
528,825

 
 
$
258,575

 
$
60,139

 
$
(29,108
)
 
$
(159,084
)
Investing activities
(31,769
)
 
 
(19,545
)
 
(25,562
)
 
(19,634
)
 
(64,571
)
Financing activities
(567,000
)
 
 
(123,437
)
 
(15,338
)
 
47,812

 
186,107

Capital expenditures
24,490

 
 
12,460

 
15,411

 
46,688

 
374,966

Capital expenditures for turnarounds and catalysts
7,279

 
 
7,085

 
10,151

 
9,176

 
1,615

Depreciation and amortization
46,009

 
 
40,448

 
39,570

 
36,651

 
19,115

Balance Sheet Data:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
66,001

 
 
$
135,945

 
$
20,352

 
$
1,113

 
$
2,043

Property, plant and equipment, net
483,061

 
 
493,970

 
512,169

 
531,307

 
512,744

Total assets
763,423

 
 
810,480

 
675,039

 
659,134

 
677,582

Total debt
295,311

 
 
533,592

 
438,526

 
387,459

 
400,392

Partners' equity
181,726

 
 
102,689

 
9,664

 
96,315

 
83,561

(1)
Net income (loss) per unit information is not presented for the years ending December 31, 2011, 2010, 2009 or 2008 as there was no common equity or potential common equity publicly traded during those periods and therefore is not


25


required by Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") topic 260, Earnings per share. Earnings per unit information is presented for the year ending December 31, 2012 for earnings subsequent to the completion of the Partnership's initial public offering on November 26, 2012. For more information regarding the initial public offering, please see Note 3 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
(2)
On February 18, 2008, a fire at the Big Spring refinery destroyed the propylene recovery unit and damaged equipment in the alkylation and gas concentration units. For the year ended December 31, 2008, we recorded pre-tax costs of $56.9 million associated with the fire. These costs include: $51.1 million for expenses incurred from pipeline commitment deficiencies, crude sale losses and other incremental costs; $5.0 million for our third party liability insurance deductible; and depreciation for the temporarily idled facilities of $0.8 million.
Alon received $330.0 million of insurance proceeds on work performed through December 31, 2008 and $55.0 million for business interruption recovery as a result of the fire with all proceeds received in 2008 and January 2009.
With the insurance proceeds received of $330.0 million, an involuntary pre-tax gain on conversion of assets was recorded of $279.7 million for the proceeds received in excess of the book value of the assets impaired of $25.3 million and demolition and repair expenses of $25.0 million incurred through December 31, 2008. Pre-tax income of $55.0 million was also recorded in 2008 for business interruption recovery.


26


ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
References in this report to the "Predecessor," "we," "our," "us" or like terms, when used in a historical context (periods prior to November 26, 2012) refers to Alon USA Partners, LP Predecessor, our predecessor for accounting purposes. References when used in the present tense or prospectively (after November 26, 2012), refer to Alon USA Partners, LP and its subsidiaries, also referred to as the "Partnership" or "Alon." Unless the context otherwise requires, references in this report to "Alon Energy" refer collectively to Alon USA Energy, Inc. and any of its subsidiaries, other than the Partnership, its subsidiaries and its general partner.
The following discussion of our financial condition and results of operations is provided as a supplement to, and should be read in conjunction with, our consolidated financial statements and the notes thereto included elsewhere in this Annual Report on Form 10-K and the other sections of this Annual Report on Form 10-K, including Items 1. and 2. “Business and Properties,” and Item 6. “Selected Financial Data.”
Forward-Looking Statements
Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.
Forward-looking statements reflect our current expectations regarding future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows. See Item 1A "Risk Factors."
Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:
changes in general economic conditions and capital markets;
changes in the underlying demand for our products;
the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;
changes in the spread between West Texas Intermediate ("WTI") crude oil and West Texas Sour ("WTS") 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”), under which J. Aron is our largest supplier of crude oil and our largest customer of refined products. Additionally, we are obligated to repurchase all consigned inventories and certain other inventories upon termination of these Supply and Offtake Agreements;
changes in fuel and utility costs incurred by our refinery;
disruptions due to equipment interruption, pipeline disruptions or failure at our or third-party facilities;
the execution of planned capital projects;
adverse changes in the credit ratings assigned to our trade credit and debt instruments or to Alon Energy;
the effects and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;
operating hazards, natural disasters, casualty losses and other matters beyond our control;
the effect of any national or international financial crisis on our business and financial condition; and


27


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
On November 26, 2012, the Partnership completed its initial public offering (the "Offering") of 11,500,00 common units (including 1,500,000 common units issued pursuant to the exercise of the underwriters' over-allotment option), representing limited partner interests. After completion of the Offering, Alon Energy contributed to the Partnership its equity interests in Alon USA, LP and Alon USA Refining, Inc. Prior to completion of the Offering, the assets, liabilities and results of operations of the aforementioned assets related to Alon USA Partners, LP Predecessor ("Predecessor").
We are a Delaware limited partnership formed in August 2012 by Alon USA Energy, Inc. (NYSE: ALJ) (“Alon Energy”) to own, operate and grow our strategically located refining and petroleum products marketing business. Our integrated downstream business operates primarily in the South Central and Southwestern regions of the United States. We own and operate a crude oil refinery in Big Spring, Texas with total crude oil throughput capacity of approximately 70,000 barrels per day (“bpd”), which we refer to as our Big Spring refinery. We refine crude oil into finished products, which we market primarily in West Texas, Central Texas, Oklahoma, New Mexico and Arizona through our wholesale distribution network to both Alon Energy’s retail convenience stores and other third-party distributors.
Our Big Spring refinery has a Nelson complexity rating of 10.2. Our refinery’s complexity allows us the flexibility to process a variety of crudes into higher-value refined products. For the year ended December 31, 2012, WTS crude oil represented approximately 80% and WTI crude oil represented approximately 20% of our crude oil input. For the year ended December 31, 2012, we produced approximately 50% gasoline, 33% diesel/jet fuel, 6% asphalt, 6% petrochemicals and 5% other refined products. During the year ended December 31, 2012, our Big Spring refinery had a utilization rate of 97.3%.
We sell refined products from our Big Spring refinery in both the wholesale rack and bulk markets. We focus our marketing of transportation fuels produced at our Big Spring refinery on portions of Texas, Oklahoma, New Mexico and Arizona through our physically integrated refining and distribution system. We distribute fuel products through a product pipeline and terminal network of seven pipelines totaling approximately 840 miles and six terminals that we own or access through leases or long-term throughput agreements.
2012 Operational and Financial Highlights
Operating income for 2012 was $423.4 million, compared to $330.8 million in 2011. Our operational and financial highlights for 2012 include the following:
Big Spring refinery throughput for 2012 averaged 68,946 bpd compared to 63,614 bpd for 2011, an increase of 8.4%.
Operating margin at the Big Spring refinery was $23.50 per barrel in 2012, compared to $20.89 per barrel in 2011. This increase is due to higher Gulf Coast 3/2/1 crack spreads and a widening of the WTI to WTS spread.
The average WTI to WTS spread for 2012 was $5.46 per barrel compared to $2.06 per barrel for 2011. The average Gulf Coast 3/2/1 crack spread was $27.43 per barrel for 2012 compared to $23.37 per barrel for 2011.
Major Influences on Results of Operations
Earnings and cash flow from the Big Spring refinery are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. These prices depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, and not necessarily fluctuations in those prices, that affect our earnings.
In order to measure our operating performance, we compare our per barrel refinery operating margins to certain industry benchmarks. We calculate this margin for the Big Spring refinery by dividing the refinery’s gross margin by its throughput


28


volumes. Gross margin is the difference between net sales and cost of sales. The Big Spring refinery margin is compared to an industry benchmark that is intended to approximate the refinery's crude slate and product yield.
We compare our Big Spring refinery’s per barrel operating margin to the Gulf Coast 3/2/1 crack spread. A 3/2/1 crack spread is calculated assuming that three barrels of a benchmark crude oil are converted, or cracked, into two barrels of gasoline and one barrel of diesel. We calculate the Gulf Coast 3/2/1 crack spread using the market value of WTI, a light, sweet crude oil, the market values of Gulf Coast conventional gasoline and Gulf Coast ultra-low sulfur diesel.
Our Big Spring refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. We measure the cost advantage of refining sour crude oil by calculating the difference between the value of WTI crude oil and the value of WTS, a medium, sour crude oil. We refer to this differential as the sweet/sour spread. A widening of the sweet/sour spread can favorably influence the operating margin for our Big Spring refinery.
The results of operations for the Big Spring refinery are also significantly affected by our refinery's 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 Big Spring refinery 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 substantial quantities of crude oil and refined product inventories. Crude oil and refined products are essentially commodities, and we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value under the LIFO inventory valuation methodology, price fluctuations generally have little effect on our financial results.
Factors Affecting Comparability
Our financial condition and operating results over the three-year period ended December 31, 2012 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.
Decreased Utilization of Refinery. In 2010, we implemented new operating procedures at the refinery, which reduced throughput rates. Accordingly, the Big Spring refinery did not resume operating at its full throughput capacity until the fourth quarter of 2010. As a result of these downtime periods, our results of operations presented below for 2010 do not reflect full utilization of the Big Spring refinery.
Product Inventory Valuation. In February 2011, we entered into a supply and offtake agreement with J. Aron and Company (“J. Aron”) under which (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 Big Spring refinery and (ii) we agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced by the Big Spring refinery. The agreement was amended in 2013 to extend the initial term of the agreement to May 2019. The supply and offtake agreement significantly reduces our inventories and reduces the time we are exposed to market fluctuations before the finished product output is sold.
IPO Transactions. On November 26, 2012, the Partnership completed its initial public offering (the "Offering") of 11,500,00 common units (including 1,500,000 common units issued pursuant to the exercise of the underwriters' over-allotment option), representing limited partner interests.


29


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 principally of sales of refined petroleum products, and are mainly affected by refined product prices, changes to the product mix and volume changes caused by operations. Product mix refers to the percentage of production represented by higher value motor fuels, such as gasoline, rather than lower value finished products.
Cost of sales. Cost of sales primarily includes crude oil, other raw materials and transportation cost.
Direct operating expenses. Direct operating expenses include costs associated with the actual operations of the refinery and terminals, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs. Environmental compliance costs, including monitoring and routine maintenance, are expensed as incurred. Substantially all of the operating costs associated with our crude oil and product pipelines are considered to be transportation costs and are reflected in cost of sales in the consolidated statements of operations.
Selling, general and administrative expenses. Selling, general and administrative expenses primarily include corporate overhead costs and marketing expenses.
Depreciation and amortization. Depreciation and amortization represents an allocation to expense within the consolidated statements of operations of the carrying value of capital assets. The value is allocated based on the straight-line method over the estimated useful life of the related asset. Depreciation and amortization also includes deferred turnaround and catalyst replacement costs. Turnaround and catalyst replacement costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround.
Operating income (loss). Operating income (loss) represents our net sales less our total operating costs and expenses.
Interest expense. Interest expense includes interest expense, letters of credit, financing costs associated with crude oil purchases, fees, and amortization of deferred debt issuance costs but excludes capitalized interest.


30


ALON USA PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED
 
Year Ended December 31,
 
2012
 
 
2011
 
2010
 
 
 
 
Predecessor
 
Predecessor
 
(dollars in thousands, except per unit and per barrel data)
STATEMENT OF OPERATIONS DATA: (A)
 
 
 
 
 
 
Net sales (1)
$
3,476,817

 
 
$
3,207,969

 
$
1,639,935

Operating costs and expenses:
 
 
 
 
 
 
Cost of sales
2,883,741

 
 
2,722,918

 
1,503,301

Direct operating expenses
100,908

 
 
98,178

 
90,359

Selling, general and administrative expenses
22,807

 
 
15,633

 
14,432

Depreciation and amortization
46,009

 
 
40,448

 
39,570

Total operating costs and expenses
3,053,465

 
 
2,877,177

 
1,647,662

Operating income (loss)
423,352

 
 
330,792

 
(7,727
)
Interest expense
(22,235
)
 
 
(16,719
)
 
(13,314
)
Interest expense - related parties
(15,691
)
 
 
(17,067
)
 
(17,067
)
Other income (loss), net
8

 
 
18

 
(269
)
Income (loss) before state income tax expense
385,434

 
 
297,024

 
(38,377
)
State income tax expense
3,536

 
 
2,597

 
136

Net income (loss)
$
381,898

 
 
$
294,427

 
$
(38,513
)
 
 
 
 
 
 
 
Net income
$
381,898

 
 
 
 
 
Less: Net income attributable to predecessor operations
344,778

 
 
 
 
 
Net income attributable to Alon USA Partners, LP
$
37,120

 
 
 
 
 
Earnings per unit, basic
$
0.59

 
 
 
 
 
Weighted average common units outstanding (in thousands)
62,500

 
 
 
 
 
Cash distribution per limited partner unit
$
0.57

 
 
 
 
 
CASH FLOW DATA:
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
Operating activities
$
528,825

 
 
$
258,575

 
$
60,139

Investing activities
(31,769
)
 
 
(19,545
)
 
(25,562
)
Financing activities
(567,000
)
 
 
(123,437
)
 
(15,338
)
OTHER DATA:
 
 
 
 
 
 
Adjusted EBITDA (2)
$
469,369

 
 
$
371,258

 
$
31,574

Capital expenditures
24,490

 
 
12,460

 
15,411

Capital expenditures for turnarounds and catalysts
7,279

 
 
7,085

 
10,151

KEY OPERATING STATISTICS:
 
 
 
 
 
 
Per barrel of throughput:
 
 
 
 
 
 
Refinery operating margin (3)
$
23.50

 
 
$
20.89

 
$
7.64

Refinery direct operating expense (4)
4.00

 
 
4.23

 
5.05

PRICING STATISTICS:
 
 
 
 
 
 
WTI crude oil (per barrel)
$
94.14

 
 
$
95.07

 
$
79.41

WTS crude oil (per barrel)
88.68

 
 
93.01

 
77.26

Crack spreads (per barrel):
 
 
 
 
 
 
Gulf Coast (WTI) 3-2-1
$
27.43

 
 
$
23.37

 
$
8.22

Crude oil differentials (per barrel):
 
 
 
 
 
 
Cushing WTI less Midland WTS
$
5.46

 
 
$
2.06

 
$
2.15

Product price (dollars per gallon):
 
 
 
 
 
 
Gulf Coast unleaded gasoline
$
2.82

 
 
$
2.75

 
$
2.05

Gulf Coast ultra-low sulfur diesel
3.05

 
 
2.97

 
2.16

Natural gas (per MMBtu)
2.83

 
 
4.03

 
4.38

(A)
Net income (loss) per unit information is not presented for the years ending December 31, 2011 and 2010 as there was no common equity or potential common equity publicly traded during those periods and therefore is not required by Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") topic 260, Earnings per share. Earnings per unit information is presented for the year ending December 31, 2012 for earnings subsequent to the completion of the Partnership's initial public offering on November 26, 2012.


31


 
As of December 31,
 
2012
 
 
2011
 
 
 
 
Predecessor
BALANCE SHEET DATA:
 
 
 
 
Cash and cash equivalents
$
66,001

 
 
$
135,945

Property, plant and equipment, net
483,061

 
 
493,970

Total assets
763,423

 
 
810,480

Total debt
295,311

 
 
533,592

Partners' equity
181,726

 
 
102,689

THROUGHPUT AND PRODUCTION DATA:
Year Ended December 31,
2012
 
 
2011
 
2010
 
 
 
 
 
 
Predecessor
 
Predecessor
 
bpd
 
%
 
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
 
WTS crude
52,190

 
75.7

 
 
51,202

 
80.4

 
39,349

 
80.2

WTI crude
14,396

 
20.9

 
 
10,023

 
15.8

 
7,288

 
14.9

Blendstocks
2,360

 
3.4

 
 
2,389

 
3.8

 
2,391

 
4.9

Total refinery throughput (5)
68,946

 
100.0

 
 
63,614

 
100.0

 
49,028

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
34,637

 
50.3

 
 
31,105

 
49.1

 
24,625

 
50.7

Diesel/jet
22,329

 
32.5

 
 
20,544

 
32.3

 
15,869

 
32.7

Asphalt
4,084

 
5.9

 
 
4,539

 
7.1

 
2,827

 
5.8

Petrochemicals
4,054

 
5.9

 
 
3,837

 
6.0

 
2,939

 
6.0

Other
3,706

 
5.4

 
 
3,488

 
5.5

 
2,341

 
4.8

Total refinery production (6)
68,810

 
100.0

 
 
63,513

 
100.0

 
48,601

 
100.0

Refinery utilization (7)
 
 
97.3
%
 
 
 
 
90.8
%
 
 
 
68.2
%
(1)
Includes sales to related parties of $588,828, $553,253 and $361,740 for the years ended December 31, 2012, 2011 and 2010, respectively.
(2)
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 (loss) to Adjusted EBITDA for the periods presented.
(3)
Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales by the refinery's throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margin to these crack spreads to assess our operating performance relative to other participants in our industry.
(4)
Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses by total throughput volumes.
(5)
Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.
(6)
Total refinery production represents the barrels per day of various refined products produced from processing crude and other refinery feedstocks through the crude units and other conversion units.
(7)
Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.


32


Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Net sales. Net sales for the year ended December 31, 2012, were $3,476.8 million, compared to $3,208.0 million for the year ended December 31, 2011, an increase of $268.8 million or 8.4%. This increase was primarily due to higher refinery throughput and higher refined product prices in 2012 as compared to 2011. Refinery throughput for the year ended December 31, 2012 was 68,946 bpd compared to 63,614 bpd for the year ended December 31, 2011, an increase of 8.4%. The average per gallon price of Gulf Coast gasoline for the year ended December 31, 2012 increased $0.07, or 2.5%, to $2.82 from $2.75 for the year ended December 31, 2011. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the year ended December 31, 2012, increased $0.08 or 2.7%, to $3.05 from $2.97 for the year ended December 31, 2011.
Cost of Sales. Cost of sales for the year ended December 31, 2012, were $2,883.7 million, compared to $2,722.9 million for the year ended December 31, 2011, an increase of $160.8 million or 5.9%. This increase was primarily due to higher refinery throughput in 2012 as compared to 2011, slightly offset by lower crude oil prices in 2012. The average price of WTI decreased 1.0% from $95.07 per barrel for the year ended December 31, 2011 to $94.14 per barrel for the year ended December 31, 2012. The average price of WTS decreased 4.7% from $93.01 per barrel for the year ended December 31, 2011 to $88.68 per barrel for the year ended December 31, 2012.
Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2012, were $100.9 million compared to $98.2 million for the year ended December 31, 2011, an increase of $2.7 million or 2.7%. The increase is primarily due to the increase in operating expenses resulting from higher refinery throughput in the year ended December 31, 2012 compared to the year ended December 31, 2011, partially offset by a decrease in natural gas costs. Refinery direct operating expenses per barrel decreased to $4.00 from $4.23 between the two periods reflecting higher throughput.
Selling, General and Administrative Expenses. SG&A expenses for the year ended December 31, 2012, were $22.8 million, compared to $15.6 million for the year ended December 31, 2011, an increase of $7.2 million or 46.2%. This is primarily due to higher employee related costs.
Depreciation and Amortization. Depreciation and amortization for the year ended December 31, 2012, were $46.0 million, compared to $40.4 million for the year ended December 31, 2011, an increase of $5.6 million or 13.9%.
Operating Income. Operating income for the year ended December 31, 2012, was $423.4 million, compared to $330.8 million for the year ended December 31, 2011, an increase of $92.6 million. The increase was primarily due to higher refinery margins resulting from increased Gulf Coast 3/2/1 crack spreads. Refinery operating margin was $23.50 per barrel for the year ended December 31, 2012, compared to $20.89 per barrel for the year ended December 31, 2011. The average Gulf Coast crack spread increased 17.4% to $27.43 per barrel for the year ended December 31, 2012, from $23.37 per barrel for the year ended December 31, 2011. Additionally, the WTI to WTS spread improved for the year ended December 31, 2012 to $5.46 per barrel compared to $2.06 per barrel for the year ended December 31, 2011.
Interest Expense. Interest expense for the year ended December 31, 2012, were $22.2 million, compared to $16.7 million for the year ended December 31, 2011, an increase of $5.5 million. The increase is primarily due to interest expense incurred on the $250 million term loan facility that was assigned to us by Alon Energy in connection with the closing of our initial public offering in November 2012.
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Net sales. Net sales for the year ended December 31, 2011, were $3,208.0 million, compared to $1,639.9 million for the year ended December 31, 2010, an increase of $1,568.1 million or 95.6%. This increase was primarily due to higher refinery throughput and higher refined product prices in 2011 compared to 2010. Refinery throughput for the year ended December 31, 2011 was 63,614 bpd compared to 49,028 bpd for the year ended December 31, 2010, an increase of 29.8%. The average per gallon price of Gulf Coast gasoline for year ended December 31, 2011 increased $0.70, or 34.1%, to $2.75 from $2.05 for the year ended December 31, 2010. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the year ended December 31, 2011, increased $0.81 or 37.57%, to $2.97 from $2.16 for the year ended December 31, 2010. Refinery throughput for the year ended December 31, 2010 was reduced as a result of efforts to implement new operating procedures.
Cost of Sales. Cost of sales for the year ended December 31, 2011, were $2,722.9 million, compared to $1,503.3 million for the year ended December 31, 2010, an increase of $1,219.6 million or 81.1%. This increase was primarily due to an increase in the cost of crude oil used by the refinery and higher refinery throughput. The average price of WTI increased


33


19.7% from $79.41 per barrel for the year ended December 31, 2010 to $95.07 per barrel for the year ended December 31, 2011.
Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2011, were $98.2 million compared to $90.4 million for the year ended December 31, 2010, an increase of $7.8 million or 8.6%. The increase was primarily due to higher refinery throughput in the year ended December 31, 2011 compared to the year ended December 31, 2010, partially offset by a decrease in natural gas costs. Refinery direct operating expenses per barrel decreased to $4.23 from $5.05 between the two periods reflecting higher throughput.
Selling, General and Administrative Expenses. SG&A expenses for the year ended December 31, 2011, were $15.6 million, compared to $14.4 million for the year ended December 31, 2010, an increase of $1.2 million or 8.3%.
Depreciation and Amortization. Depreciation and amortization for the year ended December 31, 2011, were $40.4 million, compared to $39.6 million for the year ended December 31, 2010, an increase of $0.8 million or 2.0%.
Operating Income (Loss). Operating income (loss) for the year ended December 31, 2011, was $330.8 million, compared to $(7.7) million for the year ended December 31, 2010, an increase of $338.5 million. The increase was primarily due to higher refinery margins and higher refinery throughput. Refinery operating margin was $20.89 per barrel for the year ended December 31, 2011, compared to $7.64 per barrel for the year ended December 31, 2010. The average Gulf Coast crack spread increased 184.3% to $23.37 per barrel for the year ended December 31, 2011, from $8.22 per barrel for the year ended December 31, 2010.
Interest Expense. Interest expense for the year ended December 31, 2011, was $16.7 million, compared to $13.3 million for the year ended December 31, 2010, an increase of $3.4 million, as a result of higher utilization of our revolving credit facility due to higher refinery throughput.
Liquidity and Capital Resources
Our primary sources of liquidity are cash on hand, cash generated from our operating activities, borrowings under our revolving credit facility, inventory supply and offtake arrangement and other credit lines.
We have an agreement with J. Aron for the supply of crude oil that will support the operations of the Big Spring refinery. This arrangement substantially reduces our need to issue letters of credit to support crude oil purchases. In addition, the structure allows us to acquire crude oil 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.
Cash Flows
The following table summarizes our net cash provided by or used in our operating activities, investing activities and financing activities for the years ended December 31, 2012, 2011 and 2010 (dollars in thousands):
 
Year Ended December 31,
 
2012
 
 
2011
 
2010
 
 
 
 
Predecessor
 
Predecessor
Net cash provided by (used in):
 
 
 
 
 
 
Operating activities
$
528,825

 
 
$
258,575

 
$
60,139

Investing activities
(31,769
)
 
 
(19,545
)
 
(25,562
)
Financing activities
(567,000
)
 
 
(123,437
)
 
(15,338
)
Net increase (decrease) in cash and cash equivalents
$
(69,944
)
 
 
$
115,593

 
$
19,239



34


Cash Flows Provided By Operating Activities
Net cash provided by operating activities was $528.8 million for the year ended December 31, 2012 compared to $258.6 million for the year ended December 31, 2011. The increase of $270.2 million in net cash provided by operating activities is due to higher net income of $87.5 million and a decrease in cash used for working capital of $167.1 million for the year ended December 31, 2012 as compared to the year ended December 31, 2011.
Net cash provided by operating activities was $258.6 million for the year ended December 31, 2011 compared to $60.1 million for the year ended December 31, 2010. The increase of $198.5 million in net cash provided by operating activities is due to higher net income (loss) of $332.9 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010, partially offset by an increase in cash used for working capital of $121.7 million.
Cash Flows Used In Investing Activities
Net cash used in investing activities was $31.8 million for the year ended December 31, 2012 compared to $19.5 million for the year ended December 31, 2011. The increase of $12.3 million in net cash used in investing activities is primarily due to the costs associated with the conversion from the FINA brand to the Alon brand for the year ended December 31, 2012 as compared to the year ended December 31, 2011.
Net cash used in investing activities was $19.5 million for the year ended December 31, 2011 compared to $25.6 million for the year ended December 31, 2010. The decrease of $6.1 million in net cash used in investing activities was due to lower capital expenditures and capital expenditures for turnarounds and catalysts for the year ended December 31, 2011 as compared to the year ended December 31, 2010.
Cash Flows Used In Financing Activities
Net cash used in financing activities was $567.0 million for the year ended December 31, 2012 compared to $123.4 million for the year ended December 31, 2011. The increase of $443.6 million in net cash used in financing activities is primarily due to cash payments of $171.1 million for subordinated debt, $208.7 million for cash advances to partners and net repayments of $229.0 million on our revolving credit facility, partially offset by initial public offering proceeds of $167.8 million for the year ended December 31, 2012 as compared to the year ended December 31, 2011.
Net cash used in financing activities was $123.4 million for the year ended December 31, 2011 compared to $15.3 million for the year ended December 31, 2010. The increase of $108.1 million in net cash used in financing activities is primarily due to higher net cash payments of $153.3 million to partners, partially offset by higher net borrowings under our revolving credit facility of $44.0 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010.
Indebtedness
Partnership Term Loan Credit Facility. In connection with the Offering, we were 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.
Borrowings under the Partnership Term Loan bear 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 approximately 8.00% per annum for a per annum rate of approximately 9.25%, based on current market rates at December 31, 2012.
The Partnership Term Loan is secured by a first priority lien on all of our fixed assets and other specified property, as well as on our general partner interest held by the General Partner, and a second lien on our 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, 2012, the Partnership Term Loan had an outstanding balance (net of unamortized discount) of $246.3 million.


35


Revolving Credit Facility. We have a $240.0 million revolving credit facility (the “Revolving Credit Facility”) that will mature in March 2016. The Revolving 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 Revolving Credit Facility bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%.
The Revolving Credit Facility is secured by (i) a first lien on our cash, accounts receivables, inventories and related assets and (ii) a second lien on our fixed assets.
The Revolving Credit Facility contains certain restrictive covenants including maintenance financial covenants. At December 31, 2012, we were in compliance with these covenants.
Borrowings of $49.0 million and $200.0 million were outstanding under the Revolving Credit Facility at December 31, 2012 and 2011, respectively. At December 31, 2012 and 2011, outstanding letters of credit under the Revolving Credit Facility were $58.8 million and $35.5 million, respectively.
Capital Spending
We divide our capital spending needs into the categories: sustaining maintenance, growth/profit improvement and chemical catalyst and turnaround. Maintenance capital spending includes only non-discretionary maintenance projects and projects required to comply with environmental, health and safety regulations. We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses.
The following table summarizes our expected capital expenditures for 2013 by major category:
 
2013
 
(dollars in thousands)
Sustaining maintenance
$
23,582

Growth/profit improvement/other
9,581

Chemical catalyst and turnaround
12,126

Total capital expenditures
$
45,289

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 Big Spring refinery.
Contractual Obligations
Information regarding our known contractual obligations of the types described below as of December 31, 2012 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
 
$
2,500

 
$
5,000

 
$
54,000

 
$
233,811

 
$
295,311

Operating lease obligations
 
11,315

 
19,831

 
19,061

 
7,640

 
57,847

Pipelines and Terminals Agreement (1)
 
34,015

 
70,072

 
69,793

 
87,132

 
261,012

Other commitments (2)
 
3,741

 
7,482

 
7,482

 
15,898

 
34,603

Total obligations
 
$
51,571

 
$
102,385

 
$
150,336

 
$
344,481

 
$
648,773

(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, as well as our minimum requirements with Sunoco Pipeline, LP.
(2)
Other commitments include refinery maintenance services costs.


36


As of December 31, 2012, we did not have any material capital lease obligations or any agreements to purchase goods or services, other than those included in the table above, that were binding on us.
Off-Balance Sheet Arrangements
We have no material off-balance sheet arrangements.
Critical Accounting Policies
Our accounting policies are described in the notes to our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. We prepare our consolidated financial statements in conformity with GAAP. In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events, some of which we may have little or no control over. Our critical accounting policies, which are discussed below, could materially affect the amounts recorded in our consolidated financial statements.
Inventory. Crude oil, refined products and blendstocks are priced at the lower of cost or market value. Cost is determined using the LIFO valuation method. Under the LIFO valuation method, we charge the most recent acquisition costs to cost of sales, and we value inventories at the earliest acquisition costs. We selected this method because we believe it more accurately reflects the cost of our current sales. If the market value of inventory is less than the inventory cost on a LIFO basis, then the inventory is written down to market value. An inventory write-down to market value results in a non-cash accounting adjustment, decreasing the value of our crude oil and refined products inventory and increasing our cost of sales. A reduction of inventory volumes during 2011 and 2010 resulted in a liquidation of LIFO inventory layers carried at lower costs which prevailed in previous years. The liquidation decreased costs of sales by approximately $42.7 million during 2011 and $24.2 million in 2010. Market values of crude oil, refined products and blendstock inventories exceeded LIFO costs by $12.5 million and $21.9 million at December 31, 2012 and 2011, respectively.
Environmental and Other Loss Contingencies. We record liabilities for loss contingencies, including environmental remediation costs, when such losses are probable and can be reasonably estimated. Our environmental liabilities represent the estimated cost to investigate and remediate contamination at our properties. Our estimates are based upon internal and third-party assessments of contamination, available remediation technology and environmental regulations. Accruals for estimated liabilities from projected environmental remediation obligations are recognized no later than the completion of the remedial feasibility study. These accruals are adjusted as further information develops or circumstances change. We do not discount environmental liabilities to their present value unless payments are fixed and determinable. At December 31, 2012, for those payments we considered fixed and determinable, payments were discounted at a 4% rate. We record them 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.
Turnarounds and Chemical Catalyst Costs. We record the cost of planned major refinery maintenance, referred to as turnarounds, and chemical catalyst used in the refinery process units, which are typically replaced in conjunction with planned turnarounds, in “Other assets” in our consolidated financial statements. Turnaround and catalyst costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround. The amortization of deferred turnaround and chemical catalysts costs are presented in “Depreciation and amortization” in our consolidated financial statements.
Impairment of Long-Lived Assets. We account for impairment of long-lived assets in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Subtopic 360-10, Property, Plant, and Equipment. In evaluating our assets, long-lived assets and certain identifiable intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of an asset to future net cash flows expected to be generated by the asset. If the carrying value of an asset exceeds its expected future cash flows, an impairment loss is recognized based on the excess of the carrying value of the impaired asset over its fair value. These future cash flows and fair values are estimates based on our judgment and assumptions. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs of disposition.
Asset Retirement Obligations. We use ASC Subtopic 410-20, Asset Retirement Obligations, which established accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset


37


retirement costs. The provisions of ASC Subtopic 410-20 apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of a long-lived asset. ASC Subtopic 410-20 also requires companies to recognize a liability for the fair value of a legal obligation to perform asset retirement activities that are conditional on a future event, if the amount can be reasonably estimated.
In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are subjective.


38


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 state income tax expense, interest expense, depreciation and amortization and gain on disposition of assets. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of state income tax expense, interest expense, gain on disposition of assets and the accounting effects of capital expenditures and acquisitions, items that may vary for different companies for reasons unrelated to overall operating performance.
Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:
Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;
Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and
Our calculation of Adjusted EBITDA may differ from EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.
Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.
The following table reconciles net income (loss) to Adjusted EBITDA for the years ended December 31, 2012, 2011 and 2010:
 
Year Ended December 31,
 
2012
 
 
2011
 
2010
 
 
 
 
Predecessor
 
Predecessor
 
(dollars in thousands)
Net income (loss)
$
381,898

 
 
$
294,427

 
$
(38,513
)
State income tax expense
3,536

 
 
2,597

 
136

Interest expense
22,235

 
 
16,719

 
13,314

Interest expense - related parties
15,691

 
 
17,067

 
17,067

Depreciation and amortization
46,009

 
 
40,448

 
39,570

Adjusted EBITDA
$
469,369

 
 
$
371,258

 
$
31,574



39


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. Alon Energy's 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 Alon Energy's risk management committee, we may utilize the commodity futures market to manage these anticipated inventory variances.
We maintain inventories of crude oil, refined products 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, 2012, we held approximately 0.7 million barrels of crude oil and refined product inventories valued under the LIFO valuation method. Market value exceeded carrying value of LIFO costs by $12.5 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 $0.7 million.
In accordance with fair value provisions of ASC 825-10, all commodity futures contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section of our consolidated financial statements. “Forwards” represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. “Futures” represent trades which have been executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. A “long” represents an obligation to purchase product and a “short” represents an obligation to sell product.
The following table provides information about our derivative commodity instruments as of December 31, 2012:
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)
 
217,926

 
$
62.46

 
$

 
$
13,613

 
$
17,184

 
$
3,571

Forwards-long (Gasoline)
 
19,130

 
112.02

 

 
2,143

 
2,235

 
92

Forwards-long (Distillate)
 
62,185

 
127.19

 

 
7,989

 
8,083

 
94

Forwards-short (Jet)
 
(12,934
)
 

 
126.03

 
(1,630
)
 
(1,665
)
 
(35
)
Forwards-short (Slurry)
 
(3,902
)
 

 
92.65

 
(362
)
 
(367
)
 
(5
)
Forwards-long (Catfeed)
 
143,887

 
111.57

 

 
16,054

 
16,604

 
550

Forwards-short (Slop)
 
(17,995
)
 

 
78.25

 
(1,408
)
 
(1,472
)
 
(64
)
Forwards-short (Propane)
 
(17,364
)
 

 
32.03

 
(556
)
 
(624
)
 
(68
)
Futures-short (Crude)
 
(355,000
)
 

 
88.11

 
(31,280
)
 
(32,596
)
 
(1,316
)
Futures-short (Gasoline)
 
(104,000
)
 

 
112.42

 
(11,692
)
 
(12,063
)
 
(371
)
Futures-short (Distillate)
 
(83,000
)
 

 
126.34

 
(10,486
)
 
(10,569
)
 
(83
)


40


Interest Rate Risk
As of December 31, 2012, our outstanding debt balance of approximately $299.0 million was subject to floating interest rates. Approximately $250.0 million was at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00% and approximately $49.0 million was at the Eurodollar rate plus 3.5%, subject to a minimum interest rate of 4.0%.
An increase of 1% in the Eurodollar rate on indebtedness, would result in an increase in our interest expense of approximately $0.3 million per year.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Consolidated Financial Statements are included as an annex of this Annual Report on Form 10-K. See the Index to Consolidated Financial Statements on page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
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 Report on Internal Control over Financial Reporting
The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring companies to file reports with the SEC to include a management report on such company's internal control over financial reporting in its annual report. In addition, our independent registered public accounting firm must attest to our internal control over financial reporting. This, our first Annual Report on Form 10-K, will not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to new public companies. Management will be required to provide an assessment of the effectiveness of our internal control over financial reporting and our independent registered public accounting firm will report on such assertion as of December 31, 2013.
Certifications
Included in this Annual Report on Form 10-K are certifications of our Chief Executive Officer and Chief Financial Officer which are required in accordance with Rule 13a-14 of the Exchange Act. This section includes the information concerning the controls and controls evaluation referred to in the certifications.
ITEM 9B. OTHER INFORMATION.
None.


41


PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
We are managed and operated by the board of directors and executive officers of our general partner, Alon USA Partners GP, LLC, an indirect subsidiary of Alon Energy. Our general partner manages our operations and activities subject to the terms and conditions specified in our partnership agreement. Alon Energy owns, directly or indirectly, approximately 81.6% of our outstanding common units. The operations of our general partner in its capacity as general partner are managed by its board of directors. Our unitholders are not entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. As a result of owning our general partner, Alon Energy has the right to appoint all of the members of the board of directors of our general partner, including all of our general partner's independent directors. Eitan Raff and Sheldon Stein were appointed as independent directors effective November 19, 2012 and February 25, 2013, respectively. Alon Energy will appoint our general partner's third independent director on or prior to November 19, 2013. Our directors serve until the earlier of their resignation or removal.
Actions by our general partner that are made in its individual capacity are made by Alon Energy as the owner of the sole member of our general partner and not by the board of directors of our general partner. Our general partner is not elected by our unitholders and is not subject to re-election on a regular basis in the future. The officers of our general partner manage the day-to-day affairs of our business.
Whenever our general partner makes a determination or takes or declines to take an action in its individual, rather than representative, capacity, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us, any limited partner or assignee, and it is not required to act in good faith or pursuant to any other standard imposed by our partnership agreement or under Delaware law or any other law. Examples include the exercise of its call right or its registration rights, its voting rights with respect to the units it owns and its determination whether or not to consent to any merger or consolidation of the partnership. In addition, our general partner may decline to undertake any transaction that it believes would materially adversely affect Alon Energy's ability to continue to comply with the covenants contained in its debt agreements. Decisions by our general partner that are made in its individual capacity will be made by Alon Energy, as the owner of the sole member of our general partner, not by the board of directors of our general partner.
Limited partners are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our partnership agreement contains various provisions which replace default fiduciary duties with contractual corporate governance standards. Our general partner is liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it.
As a publicly traded partnership, we qualify for, and are relying on, certain exemptions from the NYSE's corporate governance requirements, including:
the requirement that a majority of the board of directors of our general partner consist of independent directors;
the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and
the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors.
As a result of these exemptions, our general partner's board of directors does not consist of a majority of independent directors and our general partner's board of directors does not currently intend to establish a compensation committee or a nominating/corporate governance committee. Accordingly, unitholders do not have the same protections afforded to equity holders of companies that are subject to all of the corporate governance requirements of the NYSE.
The board of directors of our general partner currently consists of nine directors.
Audit Committee
The board of directors of our general partner established an audit committee consisting of members who meet the independence and experience standards established by the NYSE and the Exchange Act. The audit committee's responsibilities are to review our accounting and auditing principles and procedures, accounting functions, financial reporting and internal controls; to oversee the qualifications, independence, appointment, retention, compensation and performance of


42


our independent registered public accounting firm; to recommend to the board of directors the engagement of our independent registered public accounting firm; to review with the independent registered public accounting firm the plans and results of the auditing engagement; and to oversee “whistle-blowing” procedures and certain other compliance matters. The audit committee currently consists of Messrs. Eitan Raff and Sheldon Stein, with Mr. Raff currently serving as the Chairman. The NYSE's regulations and applicable laws require that our general partner have an audit committee consisting of at least three independent directors no later than one year following the effective date of our prospectus, which was November 19, 2012. Alon Energy will appoint our general partner's third independent director on or prior to November 19, 2013 and such independent director will serve as a member of the audit committee.
Conflicts Committee
The board of directors of our general partner established a conflicts committee consisting entirely of independent directors. Pursuant to our partnership agreement, the board may, but is not required to, seek the approval of the conflicts committee whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any public unitholder, on the other, including any related party transactions. The board of directors determines whether to seek approval of the conflicts committee on a case by case basis. The conflicts committee will then determine whether the resolution of the conflict of interest is in the best interests of the partnership. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. The conflicts committee currently consists of Messrs. Eitan Raff and Sheldon Stein, with Mr. Raff currently serving as the Chairman. Any matters approved by the conflicts committee will be conclusively deemed to be in our best interests, approved by all of our partners and not a breach by the general partner of any duties it may owe us or our unitholders.
In determining whether to seek approval from the conflicts committee, the board of directors of our general partner will consider a variety of factors, including the size and dollar amount involved in the potential transaction, the type of assets involved in the potential transaction, the various parties to the transaction, the interests of the various board members (if any) in the potential transaction, the interests of Alon Energy and its affiliates (if any) in the potential transaction, and any other factors the board of directors deems relevant in determining whether it should seek approval from the conflicts committee.
Executive Officers and Directors
The executive officers of our general partner are also executive officers of Alon Energy, and are providing their services to our general partner and us pursuant to the services agreement entered into among us, Alon Energy and our general partner. The executive officers listed below divide their working time between the management of Alon Energy and us. The approximate weighted average percentages of the amount of time the executive officers spent on management of our business in 2012 are as follows: David Wiessman (25%), Jeff D. Morris (25%), Paul Eisman (25%), Shai Even (25%), Jimmy C. Crosby (100%), Alan Moret (25%), Claire Hart (25%), Michael Oster (25%) and Kyle McKeen (25%).
The table below sets forth the names, positions and ages of the executive officers and directors of our general partner.
Name
 
Age
 
Position With Our General Partner
David Wiessman
 
58
 
Executive Chairman of the Board of Directors
Jeff D. Morris
 
61
 
Vice Chairman of the Board of Directors
Paul Eisman
 
57
 
President, Chief Executive Officer and Director
Itzhak Bader
 
66
 
Director
Boaz Biran
 
49
 
Director
Snir Wiessman
 
31
 
Director
Eitan Raff
 
70
 
Director
Mordehay Ventura
 
57
 
Director
Sheldon Stein
 
59
 
Director
Shai Even
 
44
 
Senior Vice President, Chief Financial Officer
Jimmy C. Crosby
 
53
 
Vice President of Refining and Chief Operating Officer
Alan Moret
 
58
 
Senior Vice President of Supply
Claire Hart
 
57
 
Senior Vice President
Michael Oster
 
41
 
Senior Vice President of Mergers and Acquisitions
Kyle McKeen
 
49
 
Vice President of Wholesale Marketing


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David Wiessman-Executive Chairman. Mr. D. Wiessman was appointed Chairman of the board of directors of our general partner in August 2012. Mr. D. Wiessman has served as Executive Chairman of the Board of Directors of Alon Energy since July 2000 and served as President and Chief Executive Officer of Alon Energy from its formation in 2000 until May 2005. Mr. D. Wiessman has over 25 years of oil industry and marketing experience. Since 1994, Mr. D. Wiessman has been Chief Executive Officer, President and a director of Alon Israel, Alon Energy's parent company. In 1987, Mr. D. Wiessman became Chief Executive Officer of, and a stockholder in, Bielsol Investments (1987) Ltd. (“Bielsol”), which acquired a 50% interest in Alon Israel in 1992. In 1976, after serving in the Israeli Air Force, Mr. D. Wiessman became Chief Executive Officer of Bielsol Ltd., a privately owned Israeli company that owns and operates gasoline stations and owns real estate in Israel. Mr. D. 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 (the “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, all of which are subsidiaries of Alon Israel. Mr. D. Wiessman has also served as Executive Chairman of the Board of Directors of Alon Refining Krotz Springs, Inc. (“Krotz Springs”) since May 2008. Krotz Springs is a subsidiary of Alon Energy through which Alon Energy conducts its Louisiana refining business and which has publicly traded debt in the United States. We believe Mr. D. Wiessman's vision, business expertise, industry experience, leadership skills and devotion to community service qualify him to serve as Executive Chairman of the board of directors of our general partner. David Wiessman is the father of Snir Wiessman, who joined the board of directors of our general partner in November 2012.
Jeff D. Morris-Vice Chairman. Mr. Morris was appointed Vice Chairman of the board of directors of our general partner in November 2012. Mr. Morris has served as Vice Chairman of the Board of Directors of Alon Energy since May 2011 and a director since May 2005. Prior to this Mr. Morris served as Alon Energy's Chief Executive Officer from May 2005 to May 2011, as Chief Executive Officer of Alon Energy's operating subsidiaries from July 2000 to May 2011, Alon Energy's President from May 2005 until March 2010 and President of its operating subsidiaries from July 2000 until March 2010. Prior to joining Alon Energy, he held various positions at Fina, Inc., where he began his career in 1974. Mr. Morris served as Vice President of Fina's SouthEastern Business Unit from 1998 to 2000 and as Vice President of its SouthWestern Business Unit from 1995 to 1998. In these capacities, he was responsible for both the Big Spring refinery and Fina's Port Arthur refinery and the crude oil gathering assets and marketing activities for both business units. Mr. Morris has also been a director of Krotz Springs since 2008. We believe that Mr. Morris' position as Chief Executive Officer of Alon Energy, detailed knowledge of Alon Energy'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 of directors of our general partner.
Paul Eisman-President, Chief Executive Officer and Director. Mr. Eisman was appointed President, Chief Executive Officer and Director of our general partner in August 2012. Mr. Eisman became president of Alon Energy in March 2010. Prior to joining Alon Energy, Mr. Eisman was Executive Vice President, Refining & Marketing Operations at Frontier Oil Corporation from March 2006 to October 2009 and held various positions at KBC Advanced Technologies from June 2003 to March 2006, including Vice President of North American Operations. In 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 Refinery Manager at the McKee refinery. Mr. Eisman has also been a director of Alon Refining Krotz Springs, Inc. since May 2010. Mr. Eisman was selected to serve as a director of our general partner because of his position as president of Alon Energy, extensive management experience, leadership skills and knowledge of our operations.
Itzhak Bader-Director. Mr. Bader joined the board of directors of our general partner in November 2012. Mr. Bader has served as a director of Alon Energy since August 2000. Mr. Bader has also served as Chairman of the Board of Directors of Alon Israel since 1993. He is Chairman of Granot Cooperative Regional Organization Corporation, a purchasing organization of the Kibbutz movement, a position he has held since 1995. In addition, he is also Chairman of Gat Givat Haim Agricultural Cooperative for Conservation of Agricultural Production Ltd., an Israeli beverage producer, a position he has held since 1999. Mr. Bader has also been the Co-Chairman of Dor-Alon Energy in Israel (1988) Ltd. since 2005, a director of Alon Holdings Blue Square-Israel, Ltd. since 2003 and a director of Blue Square Real Estate Ltd. since 2005, each a subsidiary of Alon Israel. We believe that Mr. Bader's experience gained while serving as a director on a number of companies' boards, including several chairman positions, qualifies him to serve as a member of the board of directors of our general partner.
Boaz Biran-Director. Mr. Biran joined the board of directors of our general partner in November 2012. Mr. Biran has served as director of Alon Energy since May 2002. Mr. Biran has been a director of Bielsol since 1998 and served as Chairman of the Board of Directors of Rosebud Real Estate Ltd., an investment company in Israel listed on the TASE, since November 2003. Mr. Biran was also a partner in Shraga F. Biran & Co., a law firm in Israel, from 1999 to 2008. We believe


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that Mr. Biran's broad business background and experience, legal expertise and directorship experience qualify him to serve as a member of the board of directors of our general partner.
Snir Wiessman-Director. Mr. S. Wiessman joined the board of directors of our general partner in November 2012. Mr. S. Wiessman has served as a director of Alon Brands, Inc., a subsidiary of Alon Energy, since November 2008. Mr. S. Wiessman has served as a Business Development and M&A Manager of Alon Israel since August 2007. Mr. Wiessman has also served as a Director of Dor-Alon Fuel Stations Operation Ltd., an Israeli gas station and convenience store operator, from August 2003 to October 2010 and AM:PM, an Israeli convenience store operator, from January 2008 to October 2010. AM:PM and Dor-Alon Fuel Station Operation Ltd. merged in October 2010 and Mr. S. Wiessman has served as a director in the merged entity, Dor-Alon Retail Sites Management, since this time. Dor-Alon Retail Sites Management is a subsidiary of Dor-Alon Energy in Israel (1988) Ltd., which is listed on the TASE. Mr. S. Wiessman holds a Bachelors in Science in Electrical Engineering from Ben Gurion University and a Masters of Business Administration from Tel Aviv University. Snir Wiessman is the son of David Wiessman, who is also a member of the board of directors of our general partner. We believe Mr. S. Wiessman's broad business background and experience qualify him to serve as a member of the board of directors of our general partner.
Eitan Raff-Director. Mr. Raff joined the board of directors of our general partner in November 2012. Mr. Raff has served as a director of Verifone Systems, Inc. since October 2007. Mr. Raff currently serves as a financial consultant to Wolfson Clore Mayer Ltd. and as a senior advisor to Morgan Stanley. Mr. Raff is also chairman of the public board of Youth Leading Change, a non-profit association, and previously served as the Accountant General (Treasurer) in the Israeli Ministry of Finance. Mr. Raff holds a B.A. and M.B.A. from the Hebrew University of Jerusalem. Mr. Raff currently serves on the boards of directors of Israel Corp. Ltd. and a number of privately-held corporations. Mr. Raff previously served as chairman of the board of directors of Bank Leumi le Israel B.M., Bank Leumi USA and Bank Leumi UK plc from 1995 until 2010. He currently serves on the investment and capital structure committee of Israel Corp. While serving on the Bank Leumi le Israel B.M. board, Mr. Raff served on a number of committees of the board of directors, including the committees on credit, finance, administration, conflicts of interest and risk management. We have concluded that Mr. Raff's experience gained while serving as a director on a number of companies' boards, including several chairman positions, qualifies him to serve as a member of the board of directors of our general partner.
Mordehay Ventura-Director. Mr. Ventura joined the board of directors of our general partner in November 2012. Mr. Ventura has been the Chief Executive Officer of Mishkey Hadarom Aguda Haklait Shitufit Ltd. since 2004. Mr. Ventura has been a Director at Alon Holdings Blue Square-Israel Ltd since March 22, 2012. He serves as a Director in Oil Holdings (Founded by the Kibbutzim Organizations) Ltd., Alon Israel Oil Company Ltd., Dor Alon Energy in Israel (1988) Ltd., Dor Alon Retail Sites Management Ltd. Gan Smuel Mazon Ltd., Ganir (1992) Ltd., Hadarey Nitzanim Aguda Haklait Shitufit Ltd., Sivey Hadarom (S.D.) Ltd., Hanegev Aguda Haklait Shitufit Transport Company Ltd., Megadley Drom Yehuda Aguda Haklait Shitufit Ltd., Shkedey Drom Yehuda Aguda Haklait Shitufit Ltd., Zeitey Drom Yehuda Aguda Haklait Shitufit Ltd., Hazera (1939) Ltd., Megadley Zraim Ltd., the Egg and Poultry Board, Yoav Regional Council, Amal Darom Aguda Haklait Shitufit Ltd., Marbek Services and assets (2002) Ltd., Shovre Bar Import Feeding Stuff Ltd., Mishkey Dan Partnership, Dana Finance Services Ltd., Amber Machon Letaarovet Aguda Haklait Shitufit Merkazit Ltd., and Tnuva Holdings. Mr. Ventura serves as a Director in several companies, including companies within Alon Israel Oil Company Ltd. group, companies related to Miskey Hadarom and others. Mr. Ventura holds a BA degree in Economics and Business Administration from the Rupin College. We have concluded that Mr. Ventura's experience gained while serving as a director on a number of companies' boards and extensive experience in the financial industry qualifies him to serve as a member of the board of directors of our general partner.
Sheldon Stein-Director. Mr. Stein joined the board of directors of our general partner in February 2013. Mr. Stein also serves as the President and Chief Executive Officer of Glazer's Distributors, one of the nation's largest distributors of wine, spirits and malt products, a position he has held since July 2010. From February 2008 until July 2010, Mr. Stein was a Vice Chairman and Head of Southwest Investment Banking for Bank of America, Merrill Lynch. Prior to joining Merrill Lynch, Mr. Stein was a Senior Managing Director and ran Bear Stearns' Southwest Investment Banking Group for over 20 years. Mr. Stein received a Bachelors degree Magna Cum Laude with honors from Brandeis University where he was a member of Phi BetaKappa and a J.D. from Harvard Law School. He is a director of The Men's Wearhouse, Inc. and Ace Cash Express and is also on the advisory board of Amegy Bank. We have concluded that Mr. Stein's broad business background and experience gained while serving as a director on a number of companies' boards qualifies him to serve as a member of the board of directors of our general partner.
Shai Even-Senior Vice President, Chief Financial Officer. Mr. Even was appointed Senior Vice President, Chief Financial Officer and Director of our general partner in August 2012. Mr. Even has served as Senior Vice President of Alon Energy since August 2008, Vice President of Alon Energy from May 2005 to August 2008 and as Alon Energy's Chief


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Financial Officer since December 2004. Mr. Even also served as Alon Energy's Treasurer from August 2003 until March 2007. Prior to joining Alon Energy, 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 our general partner 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 our general partner in November 2012.
Jimmy C. Crosby-Vice President of Refining and Chief Operating Officer. Mr. Crosby was appointed Vice President of Refining of our general partner in August 2012 and the Chief Operating Officer of our general partner in November 2012. Mr. Crosby has served as Vice President of Refining-Big Spring of Alon Energy since January 2010, with responsibility for operations at the Big Spring refinery. Prior to this, Mr. Crosby served as Vice President of Refining-California Refineries of Alon Energy 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 Energy, 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.
Alan Moret-Senior Vice President of Supply. Mr. Moret was appointed Senior Vice President of Supply of our general partner in August 2012. Mr. Moret has served as Senior Vice President of Supply of Alon Energy since August 2008. Mr. Moret served as Alon Energy's Senior Vice President of Asphalt Operations from August 2006 to August 2008, with responsibility for asphalt operations and marketing at Alon Energy's refineries and asphalt terminals. Mr. Moret has also served as an officer of Alon Refining Krotz Springs, Inc. since July 2008. Prior to joining Alon Energy, 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.
Claire Hart-Senior Vice President. Mr. Hart was appointed Senior Vice President of our general partner in August 2012. Mr. Hart has served as Senior Vice President of Alon Energy since January 2004 and also served as Alon Energy's Chief Financial Officer and Vice President from August 2000 to January 2004. In addition, Mr. Hart has been an officer of Alon Refining Krotz Springs, Inc. since July 2008. Prior to joining Alon Energy, Mr. Hart held various positions in the Finance, Accounting and Operations departments of FINA for 13 years, serving as Treasurer from 1998 to August 2000 and as General Manager of Credit Operations from 1997 to 1998.
Michael Oster-Senior Vice President of Mergers and Acquisitions. Mr. Oster was appointed Senior Vice President of Mergers and Acquisitions of our general partner in August 2012. Mr. Oster has served as Senior Vice President of Mergers and Acquisitions of Alon Energy since August 2008 and has served as an officer of Alon Refining Krotz Springs, Inc. since August 2009. Prior to joining Alon Energy, Mr. Oster was a partner in the Israeli law firm of Yehuda Raveh and Co.
Kyle McKeen-Vice President of Wholesale Marketing. Mr. McKeen was appointed Vice President of Wholesale Marketing of our general partner in August 2012. Mr. McKeen has served as President and Chief Executive Officer of Alon Brands, Inc., Alon Energy's subsidiary that manages retail and branded marketing operations, since May 2008. From 2005 to 2008, Mr. McKeen served as President and Chief Operating Officer of Carter Energy, an independent energy marketer supporting over 600 retailers by providing fuel supply, merchandising and marketing support, and consulting services. Prior to joining Carter Energy in 2005, Mr. McKeen was a member of the Board of Managers of Alon USA Interests, LLC from September 2002 to 2005 and held numerous positions of increasing responsibilities with Alon Energy, including Vice President of Marketing.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires directors, executive officers and persons who beneficially own more than 10% of our common units to file certain reports with the SEC and New York Stock Exchange concerning their beneficial ownership of our equity securities. Based on a review of these reports, other information available to us and written representations from reporting persons indicating that no other reports were required, all such reports concerning beneficial ownership were filed in a timely manner by reporting persons during the year ended December 31, 2012.
Code of Ethics
We have adopted a code of business ethics and conduct that applies to our principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions, as well as other employees. Additionally, the board of directors of our general partner has adopted corporate governance guidelines for the directors and


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the board. The code of business ethics and conduct and the corporate governance guidelines may be found on our website at www.alonpartners.com under the Governance tab.
ITEM 11. EXECUTIVE COMPENSATION.
Compensation Discussion and Analysis
We and our general partner were formed on August 17, 2012. Accordingly, neither we nor our general partner have accrued any obligations with respect to management compensation or retirement benefits for directors and executive officers for any periods prior to our date of formation.
Neither we nor our general partner directly employ any of the persons responsible for managing our business. All of the executive officers that are currently responsible for managing our day to day affairs are also current officers of our parent Alon Energy, and therefore have responsibilities for both us and Alon Energy. The individuals that are considered to be “named executive officers” at Alon Energy and which will also provide management services to us are as follows:
Paul Eisman-Chief Executive Officer
Shai Even-Senior Vice President and Chief Financial Officer
Alan Moret-Senior Vice President of Supply
Michael Oster-Senior Vice President of Mergers and Acquisitions
Kyle McKeen-Vice President of Wholesale Marketing
Objectives of Compensation Program
The objectives of Alon Energy's compensation policies are to attract, motivate and retain qualified management and personnel who are highly talented while ensuring that executive officers and other employees are compensated in a manner that advances both the short- and long-term interests of unitholders. In pursuing these objectives, Alon Energy's compensation committee believes that compensation should reward executive officers and other employees for both their personal performance and the performance of Alon Energy and its subsidiaries. For a detailed discussion of the compensation and benefits that Alon Energy provided to the officers noted above during the 2010, 2011 and 2012 fiscal years, as applicable for each officer, please see Alon Energy's most recent proxy statement as filed with the SEC.
The officers and all other personnel necessary for our business to function are employed and compensated by our parent Alon Energy, subject to the administrative services fee or reimbursement by us in accordance with the terms of the omnibus agreement. Under the omnibus agreement, none of Alon Energy's long-term incentive compensation expense will be allocated to us. However, we will be responsible for paying the long-term incentive compensation expense associated with our long-term incentive plan described below. The executive officers that perform services for us who are also direct employees of Alon Energy will continue to participate in employee benefit plans and arrangements sponsored by Alon Energy, including plans that may be established in the future. Neither we nor our general partner have entered into any additional employment or benefit-related agreements with any of the individuals who provide executive officer services to us, and we do not anticipate entering into any such agreements in the near future.
Compensation paid by or awarded by us in 2012 with respect to the executive officers of Alon Energy that also provide services to us will reflect only the portion of compensation paid by Alon Energy that is allocated to us pursuant to Alon Energy's allocation methodology and subject to the terms of the omnibus agreement. The compensation expenses that we incur pursuant to the omnibus agreement are based upon the amount of time spent by such officers managing our business and operations during the applicable fiscal year. Responsibility and authority for compensation-related decisions for Alon Energy's executive officers resides with the board of directors of Alon Energy and its committees (other than compensation under our long-term incentive plan should we choose to issue awards directly to those individuals). Any such compensation decisions by Alon Energy will not be subject to any approvals by the board of directors of our general partner or any committees thereof.
The board of directors of our general partner may grant awards to individuals who support our operations, whether or not they also provide services to Alon Energy, pursuant to the long-term incentive plan described below. Our general partner intends to implement the long-term incentive plan to provide us with maximum flexibility with respect to the design of compensatory arrangements for individuals providing services to us; however, neither we nor our general partner currently have plans to make any grants under the long-term incentive plan in conjunction with this offering or in the near term.


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Compensation Program Elements
Alon Energy compensates its employees and named executive officers through a combination of base salary, annual bonuses and awards granted pursuant to its 2005 Incentive Compensation Plan. The Compensation Committee of Alon Energy considers each element of Alon Energy's overall compensation program applicable to an employee or named executive officer when making any decision affecting that employee's or named executive officer's compensation. The particular elements of Alon Energy's compensation program are explained below.
Base Salaries. Base salary levels are designed to attract and retain highly qualified individuals. Each executive officer is eligible to participate with Alon Energy's other employees in an annual program for merit increases to the executive's base salary. Pursuant to this program, each officer's performance is evaluated annually utilizing a number of factors divided into three categories: (i) individual performance objectives and results, (ii) competencies in core skills and knowledge, and (iii) professional development. Each executive officer reviews his evaluation with Mr. Eisman and individualized performance objectives for the following year are established. Based on the results of these evaluations, each executive officer receives an overall score that is considered by the Compensation Committee of Alon Energy when determining any increase in base compensation. The precise amount of any increase in base compensation varies based on the executive's current level of compensation when compared to others in the Company at the same pay grade and the results of the annual evaluation. The Compensation Committee of Alon Energy may also consider available information on prevailing compensation levels for executive-level employees at comparable companies in Alon Energy's industry.
The range of various compensation elements for our named executive officers will be discussed in further detail within the “Compensation Discussion and Analysis” section of Alon Energy's 2013 proxy statement.
Annual Bonuses. Executive officers and key employees may be awarded bonuses outside the plans described herein based on individual performance and contributions.
Bonus Plans. The board of directors of Alon Energy has approved three annual bonus plans pursuant to the 2005 Incentive Compensation Plan (collectively, the “ALJ Bonus Plans”). Annual cash bonuses under the ALJ Bonus Plans are distributed to eligible employees each year based on the previous year's performance. Bonuses were paid to certain eligible employees in the third quarter of 2012 based on performance during Alon Energy's 2011 fiscal year and if bonuses are payable based on performance during Alon Energy's 2012 fiscal year, we expect such bonuses to be paid in the second or third quarter of 2013. Each of the ALJ Bonus Plans contains the same plan elements, which are described below. Participation in the ALJ Bonus Plans is based on the location of each employee as follows: (i) Alon Energy's refining and marketing employees and Big Spring refinery employees are eligible to participate in one plan based primarily on the performance of Alon Energy's Big Spring refinery, (ii) the employees of Alon Energy's Paramount Petroleum Corporation subsidiary are eligible to participate in a second plan based primarily on the performance of Alon Energy's California refineries, and (iii) the employees at the Krotz Springs refinery are eligible to participate in the third plan based primarily on the performance of Alon Energy's Krotz Springs refinery. The bonus potential for Alon Energy's named executive officers is based 33.3% on the bonus plan for employees of the Big Spring refinery, 33.3% on the bonus plan for employees of the California refineries and 33.3% on the bonus plan for employees of the Krotz Springs refinery. Under each of the ALJ Bonus Plans, bonus payments are based 37.5% on meeting or exceeding target reliability measures, 37.5% on meeting or exceeding target free cash flow measures and 25% on meeting or exceeding target safety and environmental objectives. The bonus pool available under each ALJ Bonus Plan is limited to 20% of the aggregate direct salary expenses of the employees eligible to participate in such plan for the applicable year. The bonus potential for Alon Energy's named executive officers ranges from 65% to 100% of the respective executive officer's base salary, as established in each executive officer's employment agreement.
The Compensation Committee of Alon Energy believes that the Bonus Plans provide motivation for the eligible employees to attain Alon Energy's financial objectives as well as refinery reliability and environmental and safety objectives, which have been designed to benefit Alon Energy in both the long- and short-term.
In addition to cash bonuses paid under the ALJ Bonus Plans, the Compensation Committee of Alon Energy awards cash bonuses from time to time to recognize exemplary results achieved by employees and named executive officers. The amount of any such cash bonus is determined based on the recipient's pay grade, contribution to the project or result and the benefit to Alon Energy from the recipient's efforts.
2005 Incentive Compensation Plan. In July 2005, the board of directors of Alon Energy approved the Alon USA Energy, Inc. 2005 Incentive Compensation Plan, and Alon Energy's stockholders approved such plan at Alon Energy's 2006 annual meeting of stockholders. In 2010, the board of directors of Alon Energy approved an amendment and restatement to such plan and the stockholder approved such amendment and restatement at Alon Energy's 2010 annual meeting of stockholders. Alon Energy refers to such amended and restated plan as the Alon USA Energy, Inc. Amended and Restated 2005 Incentive Compensation Plan, or the 2005 Incentive Compensation Plan. The 2005 Incentive Compensation Plan is a component of


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Alon Energy's overall executive incentive compensation program. The 2005 Incentive Compensation Plan permits the granting of awards in the form of options to purchase common stock, stock appreciation rights, restricted shares of common stock, restricted stock units, performance shares, performance units and senior executive plan bonuses to Alon Energy's directors, officers and key employees. The Compensation Committee of Alon Energy believes that the award of equity-based compensation pursuant to the 2005 Incentive Compensation Plan aligns executive and stockholder long-term interests by creating a strong and direct link between executive compensation and stockholder return. The Compensation Committee of Alon Energy also utilizes equity-based compensation with multi-year vesting periods for purposes of executive officer retention. The specific amount of equity-based grants is determined by the Compensation Committee of Alon Energy primarily by reference to an employee's level of authority within Alon Energy. Typically, all executive officers of the same level receive awards that are comparable in amount. The grant of restricted shares of common stock and similar equity-based awards also allows Alon Energy's directors, officers and key employees to develop and maintain a long-term ownership position in Alon Energy. The 2005 Incentive Compensation Plan is currently administered, in the case of awards to participants subject to Section 16 of the Exchange Act, by the board of directors of Alon Energy and, in all other cases, by the Compensation Committee of Alon Energy. Subject to the terms of the 2005 Incentive Compensation Plan, the Compensation Committee of Alon Energy and the board of directors of Alon Energy have the full authority to select participants to receive awards, determine the types of awards and terms and conditions of awards, and interpret provisions of the 2005 Incentive Compensation Plan. Awards may be made under the 2005 Incentive Compensation Plan to eligible directors, officers and employees of Alon Energy and its subsidiaries, provided that awards qualifying as incentive stock options, as defined under the Internal Revenue Code of 1986, as amended, or the Code, may be granted only to employees.
Option Plans. On August 1, 2000, the board of directors of each of Alon Operating and Alon Assets adopted a stock option plan (collectively, the “Option Plans”), each of which were approved by the stockholders of Alon Operating and Alon Assets, as applicable, in June 2001. The Option Plans authorized grants of options to purchase up to 16,154 shares of Alon Assets and 6,066 shares of Alon Operating. No further options may be granted under the Option Plans. All stock options granted under the Option Plans had ten-year terms. Each year a portion of the options were subject to accelerated vesting and became fully exercisable if Alon Energy achieves certain financial performance and debt service criteria. Upon exercise, Alon Energy reimbursed the optionholder for the exercise price of the shares and under certain circumstances the related federal taxes (gross up-liability). All shares have vested and been exercised under the Option Plans.
Perquisites. Alon Energy's use of perquisites as an element of compensation is limited in scope and amount. Alon Energy does not view perquisites as a significant element of compensation but does believe that in certain circumstances they can be used in conjunction with base salary to attract, motivate and retain qualified management and personnel in a competitive environment.
Retirement Benefits. Retirement benefits to Alon Energy's senior management, including Alon Energy's named executive officers, are currently provided through one of Alon Energy's 401(k) plans and one of Alon Energy's pension plans, each of which are available to most Alon Energy employees, and the Alon USA Energy, Inc. Benefits Restoration Plan, or Benefits Restoration Plan, which provides additional pension benefits to Alon Energy's highly compensated employees. Non-represented employees, including senior management, are eligible to receive company matching of employee contributions into the 401(k) plan in which they participate of up to 3% of the employee's base salary. Alon Energy's pension plans and the Benefits Restoration Plan are discussed more fully below in the “2012 Pension Benefits” table included in this Annual Report.
Employment Agreements
As discussed more fully below in “Employment Agreements and Change of Control Arrangements,” Alon Energy has entered into employment agreements with each of the named executive officers. Alon Energy's decision to enter into employment agreements and the terms of those agreements were based on the facts and circumstances at the time and an analysis of competitive market practices.
Methodology of Establishing Compensation Packages
The Compensation Committee of Alon Energy does not adhere to any specified formula for determining the apportionment of executive compensation between cash and non-cash awards. The Compensation Committee of Alon Energy attempts to design each compensation package to provide incentive to achieve Alon Energy's performance objectives, appropriately compensate individuals for their experience and contributions and secure the retention of qualified employees. This is accomplished through a combination of the compensation program elements and, in certain instances, through specific incentives not generally available to all Alon Energy's employees.


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Chief Executive Officer Compensation
The annual compensation of Alon Energy's Chief Executive Officer, Paul Eisman, is determined by the Compensation Committee of Alon Energy based on the compensation principles and programs described above. All cash compensation paid to and stock awards granted under the 2005 Incentive Compensation Plan to Mr. Eisman in 2012 will be reflected in the “Summary Compensation Table” set forth in Alon Energy's 2013 proxy statement.
Stock Ownership Policy
Neither Alon Energy nor our general partner require its directors or executive officers to own shares of Alon Energy stock or common units representing limited partner interest in us.
Section 162(m)
Under Section 162(m) of the Code, compensation paid to the Chief Executive Officer or any of the other four most highly compensated individuals in excess of $1,000,000 may not be deducted by Alon Energy in determining its taxable income. This deduction limitation does not apply to certain “performance based” compensation. The board of directors of Alon Energy does not currently intend to award levels of non-performance based compensation that would exceed $1,000,000; however, it may do so in the future if it determines that such compensation is in the best interest of Alon Energy and its stockholders.
Long-Term Incentive Plan
We, through our general partner, have adopted the Alon USA Partners, LP 2012 Long-Term Incentive Plan (the “LTIP”) for the employees, consultants and the directors of us, our general partner and its affiliates who perform services for us. The description of the LTIP set forth below is a summary of the material features of the plan. This summary, however, does not purport to be a complete description of all the provisions of the LTIP. This summary is qualified in its entirety by reference to the LTIP, a copy of which is included as an exhibit to this Annual Report. The purpose of the LTIP is to provide a means to attract and retain individuals who will provide services to us by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units.
The LTIP provides grants of (1) unit options (“Options”), (2) unit appreciation rights (“UARs”), (3) restricted units (“Restricted Units”), (4) phantom units (“Phantom Units”), (5) unit awards (“Unit Awards”), (6) substitute awards, (7) other unit-based awards (“Unit-Based Awards”), (8) cash awards, (9) performance awards, and (10) distribution equivalent rights (“DERs”) (collectively referred to as “Awards”).
Administration
The LTIP is administered by the board of directors of our general partner or an alternative committee appointed by the board of directors of our general partner, which we refer to together as the committee for purposes of this summary. The committee administers the LTIP pursuant to its terms and all applicable state, federal or other rules or laws. The committee has the power to determine to whom and when Awards will be granted, determine the amount of Awards (measured in cash or in shares of our common units), proscribe and interpret the terms and provisions of each Award agreement (the terms of which may vary), accelerate the vesting provisions associated with an Award, delegate duties under the LTIP, and execute all other responsibilities permitted or required under the LTIP. In the event that the committee is not comprised of “nonemployee directors” within the meaning of Rule 16b-3 under the Exchange Act, a subcommittee of two or more nonemployee directors will administer all Awards granted to individuals that are subject to Section 16 of the Exchange Act.
Securities to be Offered
The maximum aggregate number of shares of common units that may be issued pursuant to any and all Awards under the LTIP shall not exceed 3,125,000 units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or the expiration of Awards, as provided under the LTIP.
If a common unit subject to any Award is not issued or transferred, or ceases to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an Award or because an Award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer or exercise pursuant to Awards under the LTIP to the extent allowable by law.
Options. We may grant Options to eligible persons. Option Awards are options to acquire common units at a specified price. The exercise price of each option granted under the LTIP will be stated in the option agreement and may vary; provided, however, that, the exercise price for an Option must not be less than 100% of the fair market value per common


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unit as of the date of grant of the Option unless that Option is intended to otherwise comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”). Options may be exercised in the manner and at such times as the committee determines for each Option, unless that Option is determined to be subject to Section 409A of the Code, where the Option will be subject to any necessary timing restrictions imposed by the Code or federal regulations. The committee will determine the methods and form of payment for the exercise price of an Option and the methods and forms in which common units will be delivered to a participant.
UARs. A UAR is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the UAR. The committee will be able to make grants of UARs and will determine the time or times at which a UAR may be exercised in whole or in part. The exercise price of each UAR granted under the LTIP will be stated in the UAR agreement and may vary; provided, however, that, the exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the UAR unless that UAR Award is intended to otherwise comply with the requirements of Section 409A of the Code.
Restricted Units. A Restricted Unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability, and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. The committee shall provide, in the Restricted Unit agreement, whether the Restricted Unit will be forfeited upon certain terminations of employment. Unless otherwise determined by the committee, a common unit distributed in connection with a unit split or unit dividend, and other property distributed as a dividend, will generally be subject to restrictions and a risk of forfeiture to the same extent as the Restricted Unit with respect to which such common unit or other property has been distributed.
Phantom Units. Phantom Units are rights to receive common units, cash, or a combination of both at the end of a specified period. The committee may subject Phantom Units to restrictions (which may include a risk of forfeiture) to be specified in the Phantom Unit agreement that may lapse at such times determined by the committee. Phantom Units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number of common units covered by the Phantom Unit, or any combination thereof determined by the committee. Except as otherwise provided by the committee in the Phantom Unit agreement or otherwise, Phantom Units subject to forfeiture restrictions may be forfeited upon termination of a Participant's employment prior to the end of the specified period. Cash dividend equivalents may be paid during or after the vesting period with respect to a Phantom Units, as determined by the committee.
Unit Awards. The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant Unit Awards to any eligible person in such amounts as the committee, in its sole discretion, may select.
Substitute Awards. The LTIP will permit the grant of Awards in substitution for similar awards held by individuals who become employees or directors as a result of a merger, consolidation or acquisition by us, an affiliate of another entity or the assets of another entity. Such substitute Awards that are Options or UARs may have exercise prices less than 100% of the fair market value per common unit on the date of the substitution if such substitution complies with Section 409A of the Code and its regulations, and other applicable laws and exchange rules.
Unit-Based Awards. The LTIP will permit the grant of other Unit-Based Awards, which are Awards that may be based, in whole or in part, on the value or performance of a common unit or are denominated or payable in common units. Upon settlement, the Unit-Based Award may be paid in common units, cash or a combination thereof, as provided in the Award agreement.
Cash Awards. The LTIP will permit the grant of Awards denominated in and settled in cash. Cash Awards may be based, in whole or in part, on the value or performance of a common unit.
Performance Awards. The committee may condition the right to exercise or receive an Award under the LTIP, or may increase or decrease the amount payable with respect to an Award, based on the attainment of one or more performance conditions deemed appropriate by the committee.
DERs. The committee will be able to grant DERs in tandem with Awards under the LTIP (other than an award of Restricted Units or Unit Awards), or they may be granted alone. DERs entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the DER is outstanding. Payment of a DER issued in connection with another Award may be subject to the same vesting terms as the Award to which it relates or different vesting terms, in the discretion of the committee.


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Miscellaneous
Tax Withholding. At our discretion, subject to conditions that the committee may impose, a participant's minimum statutory tax withholding with respect to an Award may be satisfied by withholding from any payment related to an Award or by the withholding of common units issuable pursuant to the Award based on the fair market value of the common units.
Anti-Dilution Adjustments. If any “equity restructuring” event occurs that could result in an additional compensation expense under Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”) if adjustments to Awards with respect to such event were discretionary, the committee will equitably adjust the number and type of units covered by each outstanding Award and the terms and conditions of such Award to equitably reflect the restructuring event, and the committee will adjust the number and type of units with respect to which future Awards may be granted. With respect to a similar event that would not result in a FASB ASC Topic 718 accounting charge if adjustment to Awards were discretionary, the committee shall have complete discretion to adjust Awards in the manner it deems appropriate. In the event the committee makes any adjustment in accordance with the foregoing provisions, a corresponding and proportionate adjustment shall be made with respect to the maximum number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, in the case of (i) a subdivision or consolidation of the common units (by reclassification, split or reverse split or otherwise), (ii) a recapitalization, reclassification or other change in our capital structure or (iii) any other reorganization, merger, combination, exchange or other relevant change in capitalization of our equity, then a corresponding and proportionate adjustment shall be made in accordance with the terms of the LTIP, as appropriate, with respect to the maximum number of units available under the LTIP, the number of units that may be acquired with respect to an Award, and, if applicable, the exercise price of an Award in order to prevent dilution or enlargement of Awards as a result of such events.
Change in Control. Upon a “change of control” (as defined in the LTIP), the committee may, in its discretion, (i) remove any forfeiture restrictions applicable to an Award, (ii) accelerate the time of exercisability or vesting of an Award, (iii) require Awards to be surrendered in exchange for a cash payment, (iv) cancel unvested Awards without payment or (v) make adjustments to Awards as the committee deems appropriate to reflect the change of control.
Summary Compensation Table
As previously noted, the cash compensation and benefits for Named Executive Officers were not paid by us, but rather by Alon Energy. Information regarding the compensation paid to Names Executive Officers as consideration for the services they perform for us will be reported in Alon Energy's 2013 proxy statement.
2012 Grants of Plan-Based Awards
No grants of plan-based awards were made to any of the Named Executive Officers during the last completed fiscal year.
Outstanding Equity Awards at Fiscal Year-End 2012
There are no restricted or performance units held by any of our Named Executive Officers as of December 31, 2012.
2012 Option Exercises and Units Vested
No unit awards were held by our Named Executive Officers and therefore no vesting occurred during 2012.
Pension Benefits
As previously noted, employment benefits, including pension benefits, for our Named Executive Officers are provided by Alon Energy will be reported in Alon Energy's 2013 proxy statement.
Employee Agreements and Change of Control Agreements
Each of our Named Executive Officers has an employment agreement with Alon Energy. The details of such employment agreements, including payments triggered upon the occurrence of death, disability, termination, resignation, retirement or a change of control will be described in Alon Energy's 2013 proxy statement.
Officers or employees of Alon Energy or its subsidiaries who also serve as directors of our general partner do not receive additional compensation for such service. Directors of our general partner who are not also officers or employees of Alon Energy or its subsidiaries receive compensation for service on the board of directors and its committees.


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We pay each director who is not also an officer or employee of Alon Energy or its subsidiaries an annual retainer of $50,000. In addition, each independent director and each other non-employee director who is not affiliates with Alon Israel, Alon Energy's parent corporation, will receive $25,000 annually in restricted equity interests which vest in three equal installments on each of the first, second and third anniversaries of the grant date. In addition, each such director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board and committee meetings. We pay meeting fees to such directors in the amount of $1,500 for each in-person board or committee meeting, and $900 for each telephonic board or committee meeting. We pay the audit committee chairman an annual amount of $10,000. Each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to our partnership agreement.
The table below sets forth the compensation earned during the period from our formation to December 31, 2012 by each director who was not also an officer or employee of Alon Energy or its subsidiaries:
Name(1)
 
Fees Earned or Paid in Cash
 
Equity Awards
 
All Other Compensation
 
Total
Eitan Raff
 
$

 
$

 
$

 
$

Itzhak Bader
 
$

 
$

 
$

 
$

Boaz Biran
 
$

 
$

 
$

 
$

Snir Wiessman
 
$

 
$

 
$

 
$

Mordehay Ventura
 
$

 
$

 
$

 
$

__________
(1)
Mr. Stein is not included in this table because he did not serve as a director of our general partner in 2012.


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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table presents information regarding the number of common units representing limited partner interests of the Partnership beneficially owned as of March 5, 2013 by each director and named executive officer of our general partner, and all directors and executive officers of our general partner as a group. In addition, the table presents information about each person known by the Partnership to beneficially own 5% or more of our common units. Unless otherwise indicated by footnote, the beneficial owner exercises sole voting and investment power over the units. Additionally, unless otherwise indicated by footnote, the percentage of outstanding common units is calculated on the basis of 62,501,043 of our common units outstanding as of March 5, 2013.
 
 
Beneficial Unit Ownership
Directors, Executive Officers and 5% Unitholders
 
Number of Units
 
Percentage of Outstanding Common Units
Directors and Executive Officers:
 
 
 
 
David Wiessman
 

 
Itzhak Bader
 

 
Boaz Biran
 

 
Snir Wiessman
 

 
Eitan Raff
 
1,043

 
*
Jeff D. Morris
 

 
Mordehay Ventura
 

 
Sheldon Stein
 

 
Jimmy C. Crosby
 

 
Paul Eisman
 

 
Jeff Brorman
 

 
Shai Even
 

 
Alan Moret
 

 
Michael Oster
 

 
Claire Hart
 

 
Kyle McKeen
 

 
All directors and executive offers as a group (16 persons)
 
1,043

 
*
5% or more Unitholders:
 
 
 
 
Alon USA Energy, Inc. (1)
 
51,000,000

 
81.60%
______________________
*    Indicates less than 1%
(1)
Alon Energy holds its common units through one of its subsidiaries, Alon Assets, Inc. Alon Energy owns 100% of the Class A voting common stock in Alon Assets, Inc. and 95.40% of all outstanding common stock. The remaining 4.60% of outstanding common stock, which is Class B non-voting common stock, is owned by certain existing and former members of Alon Energy's management. Alon Energy also indirectly owns Alon USA Partners GP, LLC, which is our general partner and manages and operates our business and has a non-economic general partner interest in us. Voting and investment determinations of Alon Energy are made by its board of directors, which is comprised of the following members: David Wiessman, Jeff Morris, Zalman Segal, Itzhak Bader, Boaz Biran, Yeshayahu Pery, Ron Haddock, Avraham Shochat, Oded Rubinstein and Shlomo Even. As a result of, and by virtue of the relationships described above, each of David Wiessman, Jeff Morris, Zalman Segal, Itzhak Bader, Boaz Biran, Yeshayahu Pery, Ron Haddock, Avraham Shochat, Oded Rubinstein and Shlomo Even may be deemed to exercise voting and dispositive power with respect to securities held by Alon Assets, Inc.


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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.
Related Party Transactions
Alon Energy is an independent refiner and marketer of petroleum products operating primarily in the South Central, Southwestern and Western regions of the United States. Alon Energy owns 100% of the voting interests in our general partner and 81.6% of our common units. Our ongoing relationship with Alon Energy provides us with secure fuel distribution outlets and marketing expertise, which we believe provides us with a competitive advantage. Given its significant ownership in us, we believe Alon Energy is motivated to promote and support the successful execution of our business plan and to pursue projects and/or acquisitions that enhance the value of our business.
On November 26, 2012, in connection with the closing of the initial public offering of our common limited partner units, we entered into the following agreements with Alon Energy and its subsidiaries.
Omnibus Agreement
Under the terms of the omnibus agreement between us and Alon Energy, we have the right of first refusal if Alon Energy or any of its controlled affiliates has the opportunity to acquire a controlling interest in any refinery and related crude oil and refined product logistic assets, including non-retail transportation terminal sales, and that operate in Arizona, Arkansas, Colorado, Kansas, New Mexico, Oklahoma or Texas. In addition, pursuant to the terms of the omnibus agreement, we will have a 60-day exclusive right of negotiation if Alon Energy or any of its controlled affiliates decide to attempt to sell any refinery and related crude oil and refined product logistic assets, including non-retail transportation terminal sales, that operate in Arizona, Arkansas, Colorado, Kansas, New Mexico, Oklahoma or Texas.
Services Agreement
The Services Agreement among the Partnership, the General Partner and Alon Energy addresses certain aspects of the Partnership's relationship with the General Partner and Alon Energy, including the provision by Alon Energy or its service subsidiary to the Partnership of certain general and administrative services and its agreement to reimburse Alon Energy for such services; and the provision by Alon Energy or its service subsidiary to the Partnership of such employees as may be necessary to operate and manage the Partnership's business, and its agreement to reimburse Alon Energy for the expenses associated with such employees.
Pursuant to the Services Agreement, the Partnership has agreed to reimburse Alon Energy or its service subsidiary for (i) all reasonable direct and indirect costs and expenses incurred by it in connection with the performance of these services and (ii) all other reasonable expenses allocable to the Partnership or the General Partner or otherwise incurred by Alon Energy in connection with the operation of the Partnership's business.
Tax Sharing Agreement
Under the terms of the Tax Sharing Agreement by and among the Partnership and Alon Energy, the Partnership must reimburse Alon Energy for the Partnership's share of state and local income and other taxes borne by Alon Energy as a result of the Partnership's results being included in a combined or consolidated tax return filed by Alon Energy.
Fuel Supply Agreement
Pursuant to the terms of the 20-year Fuel Supply Agreement between the Partnership and Southwest Convenience Stores, LLC (“Southwest”), a subsidiary of Alon Energy, the Partnership supplies substantially all of the motor fuel requirements of Alon Energy's retail convenience stores. The volume of motor fuels sold under the Fuel Supply Agreement is determined monthly based upon Southwest's estimated requirements. Southwest purchases such motor fuels at a price equal to the price per unit in effect at the time of delivery less applicable terminal discounts plus all applicable freight, taxes, pipeline tariff and delivery place differentials.
The Fuel Supply Agreement additionally provides for (i) Southwest's mandatory participation in the Partnership's credit card payment network, (ii) Southwest's use of the “Alon” name and related marks in connection with the use of the credit card payment network and the resale of the motor fuels purchased pursuant to the Fuel Supply Agreement, and (iii) marketing services for the benefit of Southwest (at an additional cost).


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Asphalt Supply Agreement
The Partnership also entered into a 20-year Asphalt Supply Agreement with Paramount Petroleum Corporation (“Paramount”), a subsidiary of Alon Energy, under which Paramount purchases all of the asphalt produced by the Partnership. The volume of asphalt sold pursuant to the Asphalt Supply Agreement is based upon actual production, but the Partnership is required to provide good faith non-binding forecasts of its monthly production estimates for each contract year.
Products are sold under the Asphalt Supply Agreement at prices equal to the three day average price for such product, determined by reference to the value derived from the pricing formula set forth in the Asphalt Supply Agreement for such product on the day of delivery or lifting and for the two business days prior to the date of delivery or lifting. Products with a contract term exceeding one year require the parties to meet annually to reexamine the price for such product.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
Audit Fees. The aggregate fees billed by KPMG LLP ("KPMG") for professional services rendered for the audit of Alon's annual financial statements, the review of the financial statements included in this Annual Report on Form 10-K and quarterly reports on Form 10-Q were $0.3 million for the year ended December 31, 2012.
Audit-Related Fees. The aggregate fees billed by KPMG for assurance and related services related to the performance of audits or review of Alon's financial statements and not described above under "Audit Fees" were $0.7 million for 2012, primarily related to professional services rendered by KPMG in connection with the formation of our Partnership and the f