ITEM 1A. RISK FACTORS.
The occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report on Form 10-K or in any other of our filings with the SEC could have a material adverse effect on our business, financial position, results of operations and cash flows. In evaluating an investment in any of our securities, you should consider carefully, among other things, the factors and the specific risks set forth below. This Annual Report on Form 10-K contains forward-looking statements that involve risks and uncertainties. See “Forward-Looking Statements” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of the factors that could cause actual results to differ
materially from those projected.
The price volatility of crude oil, other feedstocks, refined products and fuel and utility services may have a material adverse effect on our earnings, profitability and cash flows.
Our refining and marketing earnings, profitability and cash flows from operations depend primarily on the margin between refined product prices and the prices for crude oil and other feedstocks. When the margin between refined product prices and crude oil and other feedstock prices contracts or inverts, as has been the case in recent periods and may continue to be the case in the future, our results of operations and cash flows are negatively affected. Refining margins historically have been volatile, and are likely to continue to be volatile as a result of a variety of factors including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services. The direction and timing of changes in prices for crude oil and refined products do not necessarily correlate with one another and it is the relationship between such prices, rather than the nominal amounts of such prices, that has the greatest impact on our results of operations and cash flows. Prices of crude oil, other feedstocks and refined products, and the relationships between such prices and prices for refined products, depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline, diesel, asphalt and other refined products and the relative magnitude and timing of such changes. Such supply and demand are affected by, among other things:
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changes in global and local economic conditions;
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domestic and foreign demand for fuel products;
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worldwide political conditions, particularly in significant oil producing regions;
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the level of foreign and domestic production of crude oil and refined products and the level of crude oil, feedstock and refined products imported into the United States;
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utilization rates of U.S. refineries;
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development and marketing of alternative and competing fuels;
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commodities speculation;
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infrastructure limitations;
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accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our refineries;
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federal and state government regulations; and
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local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our markets.
Although we continually analyze refinery operating margins at our individual refineries and seek to adjust throughput volumes and product slates to optimize our operating results based on market conditions, there are inherent limitations on our ability to offset the effects of adverse market conditions. For example, reductions in throughput volumes in a negative operating margin environment may reduce operating losses, but it would not eliminate them because we would still be incurring fixed costs and other variable costs.
The nature of our business has historically required us to maintain substantial quantities of crude oil and refined product inventories. Because crude oil and refined products are essentially commodities, we have no control over the changing market value of these inventories. Our inventory is valued at the lower of cost or market value under the last-in, first-out (“LIFO”) inventory valuation methodology. As a result, if the market value of our inventory were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of sales. Our investment in inventory is affected by the general level of crude oil prices, and significant increases in crude oil prices could result in substantial working capital requirements to maintain inventory volumes.
In addition, the volatility in costs of natural gas, electricity and other utility services used by our refineries and other operations affect our operating costs. Utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for utility services in both local and regional markets. Future increases in utility prices may have a negative effect on our earnings, profitability and cash flows.
Our profitability depends, in part, on the differential between the cost of crude oils processed by our refineries and those processed by our competitors. Changes in this differential could negatively affect our profitability.
We select grades of crude oil to process based, in part, on each individual refinery's configuration and operating units. Our profitability is partially derived from our ability to purchase and process crude oil feedstocks that are less expensive than those
processed by competing refiners. We quantify this differential in crude prices by comparing our crude acquisition price with benchmark crude oil grades such as West Texas Intermediate. Crude oil differentials can vary significantly depending on overall economic conditions, trends and conditions within the markets for crude oil and refined products, and infrastructure constraints. A decline in these differentials affecting one or more of our refineries could have a negative impact on our earnings.
Our indebtedness could adversely affect our financial condition or make us more vulnerable to adverse economic conditions.
Our level of indebtedness could have significant effects on our business, financial condition and results of operations and cash flows and, consequently, important consequences to your investment in our securities, such as:
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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;
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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;
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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
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we may not have sufficient flexibility to react to adverse changes in the economy, our business or the industries in which we operate.
In addition, 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, capital expenditure, debt service and other liquidity needs, which could result in our inability to comply with financial and other covenants contained in our debt agreements, our being unable to repay or pay interest on our indebtedness, and our inability to fund our other liquidity needs. If we are unable to service our debt obligations, fund our other liquidity needs and maintain compliance with our financial and other covenants, we could be forced to curtail our operations, our creditors could accelerate our indebtedness and exercise other remedies and we could be required to pursue one or more alternative strategies, such as selling assets or refinancing or restructuring our indebtedness. However, we cannot assure you that any such alternatives would be feasible or prove adequate.
The 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. Recent declines in global economic activity and consumer and business confidence and spending have significantly reduced the level of demand for our products. In addition, severe reductions in the availability and increases in the cost of credit have adversely affected our ability to fund our operations and operate our refineries at full capacity, and have adversely affected our operating margins. Together, these factors have had and may continue to have an adverse impact on our business, financial condition, results of operations and cash flows.
Our business is indirectly exposed to risks faced by our suppliers, customers and other business partners. The impact on these constituencies of the risks posed by 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.
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. The occurrence of such events at any of our refineries could significantly disrupt our production and distribution of refined products, and any sustained disruption could have a material adverse effect on our business, financial condition and results of operations.
We are subject to interruptions of supply as a result of our reliance on pipelines for transportation of crude oil and refined products.
Our refineries receive a substantial percentage of their crude oil and deliver a substantial percentage of their refined products through pipelines. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, earthquakes, hurricanes, governmental regulation, terrorism, other third party action or any of the types of events described in the preceding risk factor. Our prolonged inability to use any of the pipelines that we use to transport crude oil or refined products could have a material adverse effect on our business, results of operations and cash flows.
If the price of crude oil increases significantly, it could reduce our margin on our fixed-price asphalt supply contracts.
We enter into fixed-price asphalt supply contracts pursuant to which we agree to deliver asphalt to customers at future dates. We set the pricing terms in these agreements based, in part, upon the price of crude oil at the time we enter into each contract. If the price of crude oil increases from the time we enter into the contract to the time we produce the asphalt, our margins from these sales could be adversely affected.
Our operating results are seasonal and generally lower in the first and fourth quarters of the year.
Demand for gasoline and asphalt products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. Seasonal fluctuations in highway traffic also affect motor fuels and merchandise sales in our retail stores. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. This seasonality is most pronounced in our asphalt business.
If the price of crude oil increases significantly, it could limit our ability to purchase enough crude oil to operate our refineries at full capacity.
We rely in part on borrowings and letters of credit under our revolving credit facilities to purchase crude oil for our refineries. If the price of crude oil increases significantly, we may not have sufficient capacity under our revolving credit facilities to purchase enough crude oil to operate our refineries at full capacity. A failure to operate our refineries at full capacity could adversely affect our profitability and cash flows.
Changes in our credit profile could affect our relationships with our suppliers, which could have a material adverse effect on our liquidity and our ability to operate our refineries at full capacity.
Changes in our credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms for our purchases or require us to post security prior to payment. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our suppliers of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could cause us to be unable to operate our refineries at full capacity. A failure to operate our refineries at full capacity could adversely affect our profitability and cash flows.
Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.
We compete with a broad range of companies in our refining and marketing operations. Many of these competitors are integrated, multinational oil companies that are substantially larger than we are. Because of their diversity, integration of operations, larger capitalization, larger and more complex refineries and greater resources, these companies may be better able to withstand disruptions in operations and volatile market conditions, to offer more competitive pricing and to obtain crude oil in times of shortage.
We are not engaged in the exploration and production business and therefore do not produce any of our crude oil feedstocks. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production. Competitors that have their own crude production are at times able to offset losses from refining operations with profits from producing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries, such as wind, solar and hydropower, that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual customers. If we are unable to compete effectively with these competitors, both within and outside our industry, there could be a material adverse effect on our business, financial condition, results of operations and cash flows.
Competition in the asphalt industry is intense, and an increase in competition in the markets in which we sell our asphalt products could adversely affect our earnings and profitability.
Our asphalt business competes with other refiners and with regional and national asphalt marketing companies. Many of these competitors are larger, more diverse companies with greater resources, providing them advantages in obtaining crude oil and other blendstocks and in competing through bidding processes for asphalt supply contracts.
We compete in large part on our ability to deliver specialized asphalt products which we produce under proprietary technology licenses. Recently, demand for these specialized products has increased due to new specification requirements by state and federal governments. If we were to lose our rights under our technology licenses, or if competing technologies for specialized products are developed by our competitors, our profitability could be adversely affected.
Competition in the retail industry is intense, and an increase in competition in the markets in which our retail businesses operate could adversely affect our earnings and profitability.
Our retail operations compete with numerous convenience stores, gasoline service stations, supermarket chains, drug stores, fast food operations and other retail outlets. Increasingly, national high-volume grocery and dry-goods retailers, such as Albertson's and Wal-Mart are entering the gasoline retailing business. Many of these competitors are substantially larger than we are. Because of their diversity, integration of operations and greater resources, these companies may be better able to withstand volatile market conditions or levels of low or no profitability. In addition, these retailers may use promotional pricing or discounts, both at the pump and in the store, to encourage in-store merchandise sales. These activities by our competitors could adversely affect our profit margins. Additionally, our convenience stores could lose market share, relating to both gasoline and merchandise, to these and other retailers, which could adversely affect our business, results of operations and cash flows. Our convenience stores compete in large part based on their ability to offer convenience to customers. Consequently, changes in traffic patterns and the type, number and location of competing stores could result in the loss of customers and reduced sales and profitability at affected stores.
We may incur significant costs to comply with new or changing environmental laws and regulations.
Our operations are subject to extensive regulatory controls on air emissions, water discharges, waste management and the clean-up of contamination that can require costly compliance measures. If we fail to meet environmental requirements, we may be subject to administrative, civil and criminal proceedings by state and federal authorities, as well as civil proceedings by environmental groups and other individuals, which could result in substantial fines and penalties against us as well as governmental or court orders that could alter, limit or stop our operations.
On February 2, 2007, we committed in writing to enter into discussions with the United States Environmental Protection Agency, or EPA, under the National Petroleum Refinery Initiative. To date, the EPA has not made any specific findings against us or any of our refineries, and we have not determined whether we will ultimately enter into a settlement agreement with the EPA. Based on prior settlements that the EPA has reached with other petroleum refiners under the Petroleum Refinery Initiative, we anticipate that the EPA will seek relief in the form of the payment of civil penalties, the installation of air pollution controls and the implementation of environmentally beneficial projects. At this time, we cannot estimate the amount of any such civil penalties or the costs of any required controls or environmentally beneficial projects.
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 rule.” According to the EPA, the Texas “flexible permit 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. At this time, we have agreed to make a federally enforceable commitment by March 31, 2011 to apply for a non-flexible permit. It is unclear whether we will have any obligation to install new controls.
The U.S. House of Representatives and the U.S. Senate are in various stages of considering legislation intended to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States. GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes.
Although it is not possible at this time to predict when the House and Senate may enact climate change legislation, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased costs. If we are unable to sell our refined products at a price that reflects such increased costs, there could be a material adverse effect on our business, financial condition and results of operations. In addition, any increase in prices of refined products resulting from such increased costs could have an adverse effect on our financial condition, results of operations and cash flows.
In addition to the climate change legislation under consideration by Congress, on December 7, 2009, the EPA issued an endangerment finding that GHGs endanger both public health and welfare, and that GHG emissions from motor vehicles
contribute to the threat of climate change. Although the finding itself does not impose requirements on regulated entities, it allowed the EPA and the Department of Transportation to finalize a jointly proposed rule regulating greenhouse gas emissions from vehicles and establishing Corporate Average Fuel Economy standards for light-duty vehicles. National GHG tailpipe standards for passenger cars and light trucks were finalized on April 1, 2010.
Once GHGs became regulated by the EPA for vehicles, they also became regulated pollutants under the Clean Air Act potentially triggering other Clean Air Act requirements. On May 13, 2010, EPA announced a final rule to raise the threshold amount of GHG emissions that a source would have to emit to trigger certain Clean Air Act permitting requirements and the need to install controls to reduce emissions of greenhouse gases. Beginning in January 2011, facilities already subject to the Prevention of Significant Deterioration and Title V operating permit programs that increase their emissions of GHGs by 75,000 tons per year will be required to install control technology, known as “Best Available Control Technology,” to address the GHG emissions. Both the endangerment finding and stationary source rule are being challenged, however. If the EPA’s actions withstand legal challenge, the new obligations finalized in the stationary source rule could require us to incur increased costs. If we are unable to sell our refined products at a price that captures such increased costs, there could be a material adverse effect on our business, financial condition and results of operations. In addition, any increase in prices of refined products resulting from such increased costs could have an adverse effect on our financial condition, results of operations and cash flows.
In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. 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. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. 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.
We may incur significant costs and liabilities with respect to environmental lawsuits and proceedings and any investigation and remediation of existing and future environmental conditions.
We are currently investigating and remediating, in some cases pursuant to government orders, soil and groundwater contamination at our refineries, terminals and convenience stores. We anticipate spending approximately $6.4 million in investigation and remediation expenses in connection with our Big Spring refinery and terminals over the next 15 years. We anticipate spending an additional $38.8 million in investigation and remediation expenses in connection with our California refineries and terminals over the next 15 years. There can be no assurances, however, that we will not have to spend more than these anticipated amounts. Our handling and storage of petroleum and hazardous substances may lead to additional contamination at our facilities and facilities to which we send or sent wastes or by-products for treatment or disposal, in which case we may be subject to additional cleanup costs, governmental penalties, and third-party suits alleging personal injury and property damage. Although we have sold three of our pipelines and three of our terminals to HEP and two of our pipelines pursuant to a transaction with 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 them as a result of environmental conditions existing at the time of the sale. See Items 1 and 2 “Business and Properties-Government Regulation and Legislation-Environmental Indemnity to HEP” and “Business and Properties-Government Regulation and Legislation-Environmental Indemnity to Sunoco.” If we are forced to incur costs or pay liabilities in connection with such proceedings and investigations, such costs and payments could be significant and could adversely affect our business, results of operations and cash flows.
In connection with our acquisition of the Krotz Springs refinery from Valero, we became party to an agreement that allocated the parties' respective obligations under the Valero global settlement Consent Decree. The parties are in discussions regarding the appropriate levels of NOx emissions for the refinery's catalytic cracking unit, which is part of a Valero system-wide NOx emissions limit in the Consent Decree. Depending on the outcome of these discussions, it may be necessary for us to install additional controls or take other steps to reduce emissions of NOx from the catalytic cracking unit.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
From time to time, we have been sued or investigated for alleged violations of health, safety, environmental and other laws. If a lawsuit or enforcement proceeding were commenced or resolved against us, we could incur significant costs and liabilities. In addition, our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or
upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations, cash flows or prospects.
We could encounter significant opposition to operations at our California refineries.
Our Paramount refinery is located in a residential area. The refinery is located near schools, apartment complexes, private homes and shopping establishments. In addition, our Long Beach refinery is located in close proximity to other commercial facilities, and our Bakersfield refinery is adjacent to newly developed commercial and retail property. Any loss of community support for our California refining operations could result in higher than expected expenses in connection with opposing any community action to restrict or terminate the operation of the refinery. Any community action in opposition to our current and planned use of the California refineries could have a material adverse effect on our business, results of operations and cash flows.
The occurrence of a release of hazardous materials or a catastrophic event affecting our California refineries could endanger persons living nearby.
Because our California refineries are located in residential areas, any release of hazardous material or catastrophic event could cause injuries to persons outside the confines of these refineries. In the event that persons were injured as a result of such an event, we would likely incur substantial legal costs as well as any costs resulting from settlements or adjudication of claims from such injured persons. The extent of these expenses and costs could be in excess of the limits provided by our insurance policies. As a result, any such event could have a material adverse effect on our business, results of operations and cash flows.
Certain of our facilities are located in areas that have a history of earthquakes or hurricanes, the occurrence of which could materially impact our operations.
Our refineries located in California and the related pipeline and asphalt terminals, and to a lesser extent our refinery and operations in Oregon, are located in areas with a history of earthquakes, some of which have been quite severe. Our Krotz Springs refinery is located less than 100 miles from the Gulf Coast. In the event of an earthquake or hurricane or other weather-related event that causes damage to our refining, pipeline or asphalt terminal assets, or the infrastructure necessary for the operation of these assets, such as the availability of usable roads, electricity, water, or natural gas, we may experience a significant interruption in our refining and/or marketing operations. Such an interruption could have a material adverse effect on our business, results of operations and cash flows.
Terrorist attacks, threats of war or actual war may negatively affect our operations, financial condition, results of operations and prospects.
Terrorist attacks, threats of war or actual war, as well as events occurring in response to or in connection with them, may adversely affect our operations, financial condition, results of operations and prospects. Energy-related assets (which could include refineries, terminals and pipelines such as ours) may be at greater risk of terrorist attacks than other possible targets in the United States. A direct attack on our assets or assets used by us could have a material adverse effect on our operations, financial condition, results of operations and prospects. In addition, any terrorist attack, threats of war or actual war could have an adverse impact on energy prices, including prices for our crude oil and refined products, and an adverse impact on the margins from our refining and marketing operations. In addition, disruption or significant increases in energy prices could result in government-imposed price controls.
Covenants in our credit agreements could limit our ability to undertake certain types of transactions and adversely affect our liquidity.
Our credit agreements contain negative and financial covenants and events of default that may limit our financial flexibility and ability to undertake certain types of transactions. For example, we are subject to negative covenants that restrict our activities, including changes in control of Alon or certain of our subsidiaries, restrictions on creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, entering into certain lease obligations, making certain capital expenditures, and making certain dividend, debt and other restricted payments. Should we desire to undertake a transaction that is prohibited or limited by our credit agreements, we will need to obtain the consent of our lenders or refinance our credit facilities. Such consents or refinancings may not be possible or may not be available on commercially acceptable terms, or at all.
Our insurance policies do not cover all losses, costs or liabilities that we may experience.
We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage does not apply unless a business interruption exceeds a period of 45 to 75 days, depending upon the specific policy. 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 experienced significant downgrades of its credit ratings in recent years and is currently in run-off. These two policies are 20-year policies that were purchased to protect us against expenditures not covered by our indemnification agreement with FINA. 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 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 Big Spring refinery’s workforce is unionized, and we may face labor disruptions that would interfere with our operations.
As of December 31, 2011, we employed approximately 170 people at our Big Spring refinery, approximately 120 of whom were covered by a collective bargaining agreement. The collective bargaining agreement expires April 1, 2012. Our current labor agreement may not prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse effect on our results of operation and financial condition.
We conduct our convenience store business under a license agreement with 7-Eleven, and the loss of this license could adversely affect the results of operations of our retail and branded marketing segment.
Our convenience store operations are primarily conducted under the 7-Eleven name pursuant to a license agreement between 7-Eleven, Inc. and Alon. 7-Eleven may terminate the agreement if we default on our obligations under the agreement. This termination would result in our convenience stores losing the use of the 7-Eleven brand name, the accompanying 7-Eleven advertising and certain other brand names and products used exclusively by 7-Eleven. Termination of the license agreement could have a material adverse effect on our retail operations.
We may not be able to successfully execute our strategy of growth through acquisitions.
A component of our growth strategy is to selectively acquire refining and marketing assets and retail assets in order to increase cash flow and earnings. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth and many other factors beyond our control. Risks associated with acquisitions include those relating to:
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diversion of management time and attention from our existing business;
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challenges in managing the increased scope, geographic diversity and complexity of operations;
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difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;
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liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;
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greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for
investments to improve operating results;
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difficulties in achieving anticipated operational improvements;
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incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and
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issuance of additional equity, which could result in further dilution of the ownership interest of existing stockholders.
We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.
We depend upon our subsidiaries for cash to meet our obligations and pay any dividends, and we do not own 100% of the stock of our operating subsidiaries.
We are a holding company. Our subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or pay dividends to our stockholders depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends, tax sharing payments or otherwise. Our subsidiaries’ ability to make any payments will depend on their earnings, cash flows, the terms of their indebtedness, tax considerations and legal restrictions. Three of our current and former executive officers, Messrs. Morris, Hart and Concienne, own shares of nonvoting stock of two of our subsidiaries, Alon Assets, Inc., or Alon Assets, and Alon USA Operating, Inc., or Alon Operating. As of December 31, 2011, the shares owned by these executive officers represent 5.66% of the aggregate equity interest in these subsidiaries. To the extent these two subsidiaries pay dividends to us, Messrs. Morris, Hart and Concienne will be entitled to receive pro rata dividends based on their equity ownership. For additional information, see “Security Ownership of Certain Beneficial Owners and Management.” Messrs. Morris, Hart and Concienne are parties to stockholders’ agreements with Alon Assets and Alon Operating, pursuant to which we may elect or be required to purchase their shares in connection with put/call rights or rights of first refusal contained in those agreements. The purchase price for the shares is generally determined pursuant to certain formulas set forth in the stockholders’ agreements, but after July 31, 2010, the purchase price, under certain circumstances involving a termination of, or resignation from, employment would be the fair market value of the shares. For additional information, see Item 12 “Security Ownership of Certain Beneficial Holders and Management.”
It may be difficult to serve process on or enforce a United States judgment against certain of our directors.
All of our directors, other than Messrs. Ron Haddock and Jeff Morris, reside in Israel. In addition, a substantial portion of the assets of these directors are located outside of the United States. As a result, you may have difficulty serving legal process within the United States upon any of these persons. You may also have difficulty enforcing, both in and outside the United States, judgments you may obtain in United States courts against these persons in any action, including actions based upon the civil liability provisions of United States federal or state securities laws. Furthermore, there is substantial doubt that the courts of the State of Israel would enter judgments in original actions brought in those courts predicated on United States federal or state securities laws.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 3.
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.
ITEM 4. MINE SAFTETY DISCLOSURES
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Market Information
Our common stock is traded on the New York Stock Exchange under the symbol “ALJ.”
The following table sets forth the quarterly high and low sales prices of our common stock for each quarterly period within the two most recently completed fiscal years:
Holders
As of March 1, 2012, there were approximately 25 common stockholders of record.
Dividends
Common Stock Dividends. On March 31, 2010, we paid a regular quarterly cash dividend of $0.04 per share. In connection with our cash dividend payment to stockholders, the non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.144 million.
On June 15, 2010, we paid a regular quarterly cash dividend of $0.04 per share of our common stock. In connection with our cash dividend payment to stockholders, the non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.285 million.
On September 15, 2010, we paid a regular quarterly cash dividend of $0.04 per share of our common stock. In connection with our cash dividend payment to stockholders, the non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.164 million.
On December 15, 2010, we paid a regular quarterly cash dividend of $0.04 per share of our common stock.
On March 15, 2011, we paid a regular quarterly cash dividend of $0.04 per share. In connection with our cash dividend payment to stockholders, the non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.288 million.
On June 15, 2011, we paid a regular quarterly cash dividend of $0.04 per share of our common stock. In connection with our cash dividend payment to stockholders, the non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.143 million.
On September 15, 2011, we paid a regular quarterly cash dividend of $0.04 per share of our common stock. In connection with our cash dividend payment to stockholders, the non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.139 million.
On December 15, 2011, we paid a regular quarterly cash dividend of $0.04 per share of our common stock. In connection with our cash dividend payment to stockholders, the non-controlling interest stockholders of Alon Assets and Alon Operating received an aggregate cash dividend of $0.134 million.
We intend to continue to pay quarterly cash dividends on our common stock at an annual rate of $0.16 per share. However, the declaration and payment of future dividends to holders of our common stock will be at the discretion of our board of
directors and will depend upon many factors, including our financial condition, earnings, legal requirements, restrictions in our debt agreements, the terms of our preferred stock and other factors our board of directors deems relevant.
Preferred Stock Dividends. We issued 328,000 and 101,000 shares in aggregate of common stock for payment of preferred stock dividends for the years ended December 31, 2011 and 2010, respectively.
Recent Sales of Unregistered Securities
On October 10, 2011, Alon issued 83,936 shares of Alon Common Stock to Joe Concienne, a former officer of Alon. Pursuant to the terms of a shareholders agreement between Mr. Concienne, Alon and two subsidiaries of Alon (Alon Assets and Alon Operating), Mr. Concienne exchanged 673.07 shares of non-voting common stock of Alon Assets and 252.73 shares of non-voting common stock of Alon Operating for 83,936 shares of common stock in Alon and a cash payment of $300,479.75 (prior to tax withholding obligations). The issuance of the shares of Common Stock was exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.
On March 8, 2012, pursuant to the terms of Series B Convertible Preferred Stock Agreement, Alon issued 3,000,000 shares of 8.5% Series B Convertible Preferred Stock to a group of investors who held, in the aggregate, $30.0 million of notes issued by Alon Brands, Inc., the Alon Brands term loans, and 3,092,783 warrants to purchase shares of Alon common stock. Pursuant to such agreement, Alon repaid in full the obligations under the Alon Brands term loans and the warrants were surrendered to Alon. The terms of the Series B Convertible Preferred Stock are described in the Company's Certificate of Designation for the Series B Convertible Preferred Stock. The issuance of the Series B Preferred Stock was exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
None.
Stockholder Return Performance Graph
The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, each as amended, except to the extent we specifically incorporate it by reference into such filing.
The following performance graph compares the cumulative total stockholder return on Alon common stock as traded on the NYSE with the Standard & Poor’s 500 Stock Index (the “S&P 500”) and our peer group for the cumulative five year period from December 31, 2006 to December 31, 2011, assuming an initial investment of $100 dollars and the reinvestment of all dividends, if any. The “Peer Group” includes HollyFrontier Corporation, Tesoro Corporation, Valero Energy Corporation, Delek US Holdings, Inc., Western Refining, Inc. and CVR Energy, Inc..
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth selected historical consolidated financial and operating data for our company. The selected historical consolidated statement of operations and consolidated statement of cash flows data for the years ended December 31, 2008 and 2007, and the selected consolidated balance sheet data as of December 31, 2009, 2008 and 2007 are derived from our audited consolidated financial statements, which are not included in this Annual Report on Form 10-K. The selected historical consolidated statement of operations and consolidated statement of cash flows data for the years ended December 31, 2011, 2010 and 2009, and the selected consolidated balance sheet data as of December 31, 2011 and 2010, are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
Our financial statements include the results of the Krotz Springs refining business from July 1, 2008. As a result of this transaction, the financial and operating data for periods prior to the effective date of this transaction may not be comparable to the data for the years ended December 31, 2011, 2010, 2009 and 2008.
The following selected historical consolidated financial and operating data should be read in conjunction with Item 7
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The following discussion of our financial condition and results of operations is provided as a supplement to, and should be read in conjunction with, our consolidated financial statements and the notes thereto included elsewhere in this Annual Report on Form 10-K and the other sections of this Annual Report on Form 10-K, including Items 1 and 2 “Business and Properties,” and Item 6 “Selected Financial Data.”
Forward-Looking Statements
Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.
Forward-looking statements reflect our current expectations 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:
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changes in general economic conditions and capital markets;
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changes in the underlying demand for our products;
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the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;
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changes in the spread between West Texas Intermediate ("WTI") crude oil and West Texas Sour ("WTS") crude oil;
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changes in the spread between WTI crude oil and Light Louisiana Sweet and Heavy Louisiana Sweet crude oils, as well as the spread between California crudes such as Buena Vista and WTI;
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the effects of transactions involving forward contracts and derivative instruments;
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actions of customers and competitors;
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changes in fuel and utility costs incurred by our facilities;
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disruptions due to equipment interruption, pipeline disruptions or failure at our or third-party facilities;
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the execution of planned capital projects;
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adverse changes in the credit ratings assigned to our trade credit and debt instruments;
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the effects and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;
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operating hazards, natural disasters such as flooding, casualty losses and other matters beyond our control;
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the global financial crisis’ impact on our business and financial condition; and
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the other factors discussed in this Annual Report on Form 10-K under the caption “Risk Factors.”
Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.
Company Overview
We are an independent refiner and marketer of petroleum products operating primarily in the South Central, Southwestern and Western regions of the United States. Our crude oil refineries are located in Texas, California, Oregon and Louisiana and have a combined throughput capacity of approximately 250,000 barrels per day (“bpd”). Our refineries produce petroleum products including various grades of gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt, and other petroleum-based products.
Refining and Unbranded Marketing Segment. Our refining and unbranded marketing segment includes sour and heavy crude oil refineries located in Big Spring, Texas; and Paramount, Bakersfield and Long Beach, California; and a light sweet crude oil refinery located in Krotz Springs, Louisiana. We refer to the Paramount, Bakersfield and Long Beach refineries together as our “California refineries.” The refineries in our refining and unbranded marketing segment have a combined throughput capacity of approximately 240,000 bpd. At these refineries we refine crude oil into petroleum products, including gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks and asphalts, which are marketed primarily in the South Central, Southwestern, and Western United States. At Bakersfield, we convert intermediate products into finished products and do not refine crude oil.
We market transportation fuels produced by our Big Spring refinery in West and Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in these regions as our “physically integrated system” because we supply our retail and branded marketing segment's convenience stores and unbranded distributors with motor fuels produced at our Big Spring refinery and distributed through a network of pipelines and terminals which we either own or have access to through leases or long-term throughput agreements.
We market refined products produced by our California refineries to wholesale distributors, other refiners and third parties primarily on the West Coast. We started up the Bakersfield hydrocracker unit in late June 2011 and began processing vacuum gas oil produced by our other California locations.
We market refined products produced by our Krotz Springs refinery to other refiners and third parties. The refinery’s location provides access to upriver markets on the Mississippi and Ohio Rivers and its docking facilities along the Atchafalaya River allow barge access. The refinery also uses its direct access to the Colonial Pipeline to transport products to markets in the Southern and Eastern United States. The Krotz Springs refinery processing units are structured to yield approximately 101.5% of total feedstock input, meaning that for each 100 barrels of crude oil and feedstocks input into the refinery, it produces 101.5 barrels of refined products. Of the 101.5%, on average 99.0% is light finished products such as gasoline and distillates, including diesel and jet fuel, petrochemical feedstocks and liquefied petroleum gas, and the remaining 2.5% is primarily heavy oils.
Asphalt Segment. Our asphalt segment markets asphalt produced at our Big Spring and California refineries included in the refining and unbranded marketing segment and at our Willbridge, Oregon refinery. Asphalt produced by the refineries in our refining and unbranded marketing segment is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. Our asphalt segment markets asphalt through 11 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington (Richmond Beach), Arizona (Phoenix and Flagstaff) and Nevada (Fernley) (50% interest) as well as through a 50% interest in Wright Asphalt Products Company, LLC (“Wright”). We produce both paving and roofing grades of asphalt, including performance-graded asphalts, emulsions and cutbacks.
Retail and Branded Marketing Segment. Our retail and branded marketing segment operates 302 convenience stores located in Central and West Texas and New Mexico. These convenience stores typically offer various grades of gasoline, diesel fuel, general merchandise and food and beverage products to the general public, primarily under the 7-Eleven, Alon and FINA brand names. Substantially all of the motor fuel sold through our retail operations and the majority of the motor fuels marketed in our branded business is supplied by our Big Spring refinery. In 2011, approximately 91% of the motor fuel requirements of our branded marketing operations, including retail operations, were supplied by our Big Spring refinery. Our convenience stores that are not part of our integrated supply system, primarily in Central Texas, are supplied with motor fuels we obtain from third-party suppliers.
We market gasoline and diesel under the Alon and FINA brand names through a network of approximately 640 locations, including our convenience stores. Approximately 55% of the gasoline and 21% of the diesel motor fuel produced at our Big Spring refinery was transferred to our retail and branded marketing segment at prices substantially determined by reference to commodity pricing information published by Platts. Additionally, our retail and branded marketing segment licenses the use of the Alon and FINA brand names and provides credit card processing services to approximately 230 licensed locations that are not under fuel supply agreements with us.
Summary of 2011 Developments
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We shut down the California refineries in December 2010, to redirect our resources towards the integration of the Bakersfield hydrocracker unit to process vacuum gas oil produced at our California refineries. The California refineries restarted operations in March and production from the Bakersfield hydrocracker began in June 2011.
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In February 2011, we entered into a Supply and Offtake Agreement (the “Alon Supply and Offtake Agreement”), with J. Aron & Company (“J. Aron”). Pursuant to the Alon Supply and Offtake Agreement (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.
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In June 2011, we completed the Bakersfield refinery integration project marking the realization of the plan to have a hydrocracker unit to increase the light products yields of our California refineries. We began selling products produced by our Bakersfield refinery at the beginning of the third quarter of 2011.
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At our Krotz Springs refinery, we completed several capital projects during the first two weeks of November 2011 that are intended to improve crude slate flexibility, FCC capacity and yields, and jet fuel yield. In addition, we completed arrangements that allowed us to to begin receiving WTI-priced crudes during December 2011 with the goal of processing on average 20,000 to 25,000 barrels per day of such crudes during 2012.
2011 Operational and Financial Highlights
Highlights for 2011 include:
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Combined refinery throughput for 2011 averaged 146,149 bpd, consisting of 63,614 bpd at the Big Spring refinery, 22,815 bpd at the California refineries and 59,720 bpd at the Krotz Springs refinery, where throughput was reduced during the second quarter of 2011 due to flooding in Louisiana and the impact on crude oil supply to the refinery, compared to 105,868 bpd for 2010, consisting of 49,028 bpd at the Big Spring refinery, 17,596 bpd at the California refineries and 39,244 bpd at the Krotz Springs refinery.
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Operating margin at the Big Spring refinery was $18.84 per barrel in 2011, compared to $6.03 per barrel in 2010. This increase is due to higher Gulf Coast 3/2/1 crack spreads and improved operating efficiencies at higher throughput rates.
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Operating margin at the California refineries was $(1.31) per barrel in 2011, compared to $1.08 per barrel in 2010. This decrease primarily reflects the impact of the California refineries' shutdown until its restart in late March 2011 offset by higher West Coast 3/1/1/1 crack spreads and light product yields.
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Operating margin at the Krotz Springs refinery was $3.05 per barrel in 2011, compared to $2.24 per barrel in 2010. This increase reflects the effects of the refinery being shut down for the first five months of 2010 and the increase in the Gulf Coast 2/1/1 high sulfur diesel crack spread.
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The average sweet/sour spread for 2011 was $2.06 per barrel compared to $2.15 per barrel for 2010. The average LLS to WTI spread for 2011 was $16.76 per barrel compared to $2.49 per barrel for 2010. The average WTI to Buena Vista spread for 2011 was $(13.36) per barrel compared to $1.33 per barrel for 2010.
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The average Gulf Coast 3/2/1 crack spread was $23.37 per barrel for 2011 compared to $8.22 per barrel for 2010. The average West Coast 3/1/1/1 crack spread for 2011 was $9.20 per barrel compared to $8.34 per barrel for 2010. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for 2011 was $7.00 per barrel compared to $5.26 per barrel for 2010.
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Asphalt margins in 2011 were $26.99 per ton compared to $51.06 per ton in 2010. This decrease was due primarily to higher crude oil costs without having the ability to increase asphalt sales prices accordingly. The average blended asphalt sales price increased 13.4% from $477.26 per ton in 2010 to $541.44 per ton in 2011 and the average non-blended asphalt sales price increased $0.53 from $326.16 per ton in 2010 to $326.69 per ton in 2011. The average price of Buena Vista crude increased 38.9% from $78.08 per barrel in 2010 to $108.43 per barrel in 2011.
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Retail fuel sales volume increased by 10.2% from 142.2 million gallons in 2010 to 156.7 million gallons in 2011. Branded fuel sales volume increased by 15.5% from 318.9 million gallons in 2010 to 368.4 million gallons in 2011.
Major Influences on Results of Operations
Refining and Unbranded Marketing. Earnings and cash flow from our refining and unbranded marketing segment are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. The cost to
acquire crude oil and other feedstocks and the price of the refined products we ultimately sell 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 the per barrel operating margin for each refinery by dividing the refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales (exclusive of substantial unrealized hedge positions and inventory adjustments related to acquisitions).
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 values of Gulf Coast conventional gasoline and ultra-low sulfur diesel and the market value of West Texas Intermediate, or WTI, a light, sweet crude oil.
We compare our California refineries’ per barrel operating margin to the West Coast 3/1/1/1 crack spread. A 3/1/1/1 crack spread is calculated assuming that three barrels of a benchmark crude oil are converted into one barrel of gasoline, one barrel of diesel and one barrel of fuel oil. We calculate the West Coast 3/1/1/1 crack spread using the market values of West Coast LA CARBOB pipeline gasoline, LA ultra-low sulfur pipeline diesel, and LA 380 pipeline CST (fuel oil) and the market value of Buena Vista crude oil.
We compare our Krotz Springs refinery’s per barrel margin to the Gulf Coast 2/1/1 crack spread. A 2/1/1 crack spread is calculated assuming that two barrels of a benchmark crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate the Gulf Coast 2/1/1 crack spread using the market values of Gulf Coast conventional gasoline and Gulf Coast high sulfur diesel and the market value of Light Louisiana Sweet, or LLS, crude oil.
Our Big Spring refinery and California refineries are 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 less the value of West Texas Sour, or 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 and California refineries. In addition, our California refineries are capable of processing significant volumes of heavy crude oils which historically have cost less than light crude oils. We measure the cost advantage of refining heavy crude oils by calculating the difference between the value of WTI crude oil less the value of Buena Vista crude oil. A widening of this spread can favorably influence the refinery operating margins for our California refineries.
The Krotz Springs refinery has the capability to process substantial volumes of low-sulfur, or sweet, crude oils to produce a high percentage of light, high-value refined products. Sweet crude oil typically comprises 100% of the Krotz Springs refinery's crude oil input. This input was primarily comprised of Heavy Louisiana Sweet, or HLS crude oil, and LLS crude oil. We measure the cost of refining these lighter sweet crude oils by calculating the difference between the average value of LLS crude oil (which also approximates the value of HLS crude oil) to the average value of WTI crude oil. A narrowing of this spread can favorably influence the refinery operating margins of our Krotz Springs refinery.
The results of operations from our refining and unbranded marketing segment are also significantly affected by our refineries’ operating costs, particularly the cost of natural gas used for fuel and the cost of electricity. Natural gas prices have historically been volatile. Typically, electricity prices fluctuate with natural gas prices.
Demand for gasoline products is generally higher during summer months than during winter months due to seasonal increases in highway traffic. As a result, the operating results for our refining and unbranded marketing segment for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters. The effects of seasonal demand for gasoline are partially offset by seasonality in demand for diesel, which in our region is generally higher in winter months as east-west trucking traffic moves south to avoid winter conditions on northern routes.
Safety, reliability and the environmental performance of our refineries are critical to our financial performance. The financial impact of planned downtime, such as a turnaround or major maintenance project, is mitigated through a diligent planning process that considers expectations for product availability, margin environment and the availability of resources to perform the required maintenance.
The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Crude oil and refined products are essentially commodities, and we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value under the LIFO inventory valuation methodology, price fluctuations generally have little effect on our financial results.
Asphalt. Earnings from our asphalt segment depend primarily upon the margin between the price at which we sell our asphalt and the transfer prices for asphalt produced at our refineries in the refining and unbranded marketing segment. Asphalt is transferred to our asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. The asphalt segment also conducts operations and markets asphalt at our refinery located in Willbridge, Oregon. In addition to producing asphalt at our refineries, at times when refining margins are unfavorable we opportunistically purchase asphalt from other producers for resale. A portion of our asphalt sales are made using fixed price contracts for delivery at future dates. Because these contracts are priced at the market prices for asphalt at the time of the contract, a change in the cost of crude oil between the time we enter into the contract and the time we produce the asphalt can positively or negatively influence the earnings of our asphalt segment. Demand for paving asphalt products is higher during warmer months than during colder months due to seasonal increases in road construction work. As a result, revenues from our asphalt segment for the first and fourth calendar quarters are expected to be lower than those for the second and third calendar quarters.
Retail and Branded Marketing. Earnings and cash flows from our retail and branded marketing segment are primarily affected by merchandise and motor fuel sales volumes and margins at our convenience stores and the motor fuel sales volumes and margins from sales to our Alon and FINA-branded distributors, together with licensing and credit card related fees generated from our Alon and FINA-branded distributors and licensees. Retail merchandise gross margin is equal to retail merchandise sales less the delivered cost of the retail merchandise, net of vendor discounts and rebates, measured as a percentage of total retail merchandise sales. Retail merchandise sales are driven by convenience, branding and competitive pricing. Motor fuel margin is equal to motor fuel sales less the delivered cost of fuel and motor fuel taxes, measured on a cents per gallon (“cpg”) basis. Our motor fuel margins are driven by local supply, demand and competitor pricing. Our convenience store sales are seasonal and peak in the second and third quarters of the year, while the first and fourth quarters usually experience lower overall sales.
Factors Affecting Comparability
Our financial condition and operating result over the three-year period ended December 31, 2011 have been influenced by the following factors which are fundamental to understanding comparisons of our period-to-period financial performance.
Refinery Acquisitions
In June 2010, we purchased the Bakersfield, California refinery from Big West of California, LLC, a subsidiary of Flying J, Inc. The refinery was non-operational at the time and required turnaround work and additional capital expenditures before it could be returned to operations and integrated with our other California refineries. In connection with the Bakersfield refinery acquisition, the acquisition date fair value of the identifiable net assets acquired exceeded the fair value of the consideration transferred, resulting in a $17.5 million bargain purchase gain.
In June 2011, we completed the Bakersfield integration project marking the realization of the plan to have a hydrocracker unit to increase the light products yields of our California refineries. We began selling products produced by our Bakersfield refinery at the beginning of the third quarter of 2011.
Unscheduled Turnaround and Reduced Crude Oil Throughput
In an effort to match our safety, reliability and the environmental performance initiatives with the current operating margin environment, we accelerated a planned turnaround at our Krotz Springs refinery from the first quarter of 2010 to the fourth quarter of 2009. The refinery resumed operations in June 2010. Crude throughput was reduced at the Krotz Springs refinery during the second quarter of 2011 due to the flooding in Louisiana and its impact on crude oil supply to the refinery.
We implemented new operating procedures at the Big Spring refinery during 2010 that resulted in reduced throughput.
The California refineries' throughput was lower during 2010 due to continued efforts to optimize asphalt production with demand and as a result of the shutdown in December 2010 until its restart in the first quarter of 2011 to redeploy resources for the integration of the Bakersfield refinery.
Results of Operations
Net Sales. Net sales consist primarily of sales of refined petroleum products through our refining and unbranded marketing segment and asphalt segment and sales of merchandise, including food products, and motor fuels, through our retail and branded marketing segment.
For the refining and unbranded marketing segment, net sales consist of gross sales, net of customer rebates, discounts and excise taxes and includes inter-segment sales to our asphalt and retail and branded marketing segments, which are eliminated through consolidation of our financial statements. Asphalt sales consist of gross sales, net of any discounts and applicable taxes.
Retail net sales consist of gross merchandise sales, less rebates, commissions and discounts, and gross fuel sales, including motor fuel taxes. For our petroleum and asphalt products, net sales are mainly affected by crude oil and refined product prices and volume changes caused by operations. Our retail merchandise sales are affected primarily by competition and seasonal influences.
Cost of Sales. Refining and unbranded marketing cost of sales includes crude oil and other raw materials, inclusive of transportation costs. Asphalt cost of sales includes costs of purchased asphalt, blending materials and transportation costs. Retail cost of sales includes cost of sales for motor fuels and for merchandise. Motor fuel cost of sales represents the net cost of purchased fuel, including transportation costs and associated motor fuel taxes. Merchandise cost of sales includes the delivered cost of merchandise purchases, net of merchandise rebates and commissions. Cost of sales excludes depreciation and amortization expense.
Direct Operating Expenses. Direct operating expenses, which relate to our refining and unbranded marketing and asphalt segments, include costs associated with the actual operations of our refineries and asphalt terminals, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs. Environmental compliance costs, including monitoring and routine maintenance, are expensed as incurred. All operating costs associated with our crude oil and product pipelines are considered to be transportation costs and are reflected as cost of sales.
Selling, General and Administrative Expenses. Selling, general and administrative, or SG&A, expenses consist primarily of costs relating to the operations of our convenience stores, including labor, utilities, maintenance and retail corporate overhead costs. Refining and marketing and asphalt segment corporate overhead and marketing expenses are also included in SG&A expenses.
ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED
Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for us and our three operating segments for years ended December 31, 2011, 2010 and 2009. The summary financial data for our three operating segments does not include certain SG&A expenses and depreciation and amortization related to our corporate headquarters. The following data should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this Annual Report on Form 10-K.
(A)
Adjusted EBITDA does not exclude loss on heating oil call option crack spread contracts of $36,280 for the year ended December 31, 2011. The heating oil call option crack spread contracts are considered a financing activity. Adjusted EBITDA excluding the loss on these heating oil call option crack spread contracts would be $300,257.
(1)
Includes excise taxes on sales by the retail segment of $60,686, $54,930 and $47,137 for the years ended December 31, 2011, 2010 and 2009, respectively.
(2)
Includes corporate headquarters selling, general and administrative expenses of $752, $752 and $757 for the years ended December 31, 2011, 2010 and 2009, respectively, which are not allocated to our three operating segments.
(3)
Includes corporate depreciation and amortization of $1,925, $1,380 and $724 for the years ended December 31, 2011, 2010 and 2009, respectively, which are not allocated to our three operating segments.
(4)
Interest expense of $94,939 for the year ended December 31, 2010, includes a charge of $6,659 for the write-off of debt issuance costs associated with our prepayment of the Alon Refining Krotz Springs, Inc. revolving credit facility. Interest expense for the year ended December 31, 2009, includes $20,482 of unamortized debt issuance costs written off as a result of prepayments of $163,819 of term debt in October 2009. Interest expense for 2009 also includes $5,715 related to the liquidation of heating oil hedges in the second quarter of 2009.
(5)
In connection with the Bakersfield refinery acquisition in 2010, the acquisition date fair value of the identifiable net assets acquired exceeded the fair value of the consideration transferred, resulting in a $17,480 bargain purchase gain.
(6)
Other income (loss), net for the year ended December 31, 2011, is substantially the loss on heating oil crack spread contracts. Other income (loss), net for the year ended December 31, 2010, includes a gain from the sale of our investment in Holly Energy Partners of $7,277 and a loss on heating oil crack spread contracts of $4,119.
(7)
Accumulated dividends on preferred stock of subsidiary for the year ended December 31, 2009, represent dividends of $12,900 for the conversion of the preferred stock into Alon common stock. Also included for the year ended December 31, 2009, is $8,600 of accumulated dividends through December 31, 2009.
(8)
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) available to common stockholders to Adjusted EBITDA for the periods presented.
(9)
Includes corporate capital expenditures of $1,540, $2,335 and $3,704 for the years ended December 31, 2011, 2010 and 2009, respectively, which are not allocated to our three operating segments.
(1)
Net sales include intersegment sales to our asphalt and retail and branded marketing segments at prices which approximate wholesale market prices. These intersegment sales are eliminated through consolidation of our financial statements.
(2)
Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales (exclusive of substantial unrealized hedge positions and inventory adjustments related to acquisitions) attributable to each refinery by the refinery's throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margins to these crack spreads to assess our operating performance relative to other participants in our industry.
The refinery operating margin for the year ended December 31, 2011, excludes a benefit from inventory reductions of $22,460. The refinery operating margin for the year ended December 31, 2011 for the Krotz Springs refinery excludes unrealized hedging gains of $32,742. The refinery operating margin for the year ended December 31, 2010, excludes an unrealized loss associated with consignment inventory of $8,942. The refinery operating margin for the year ended December 31, 2010, excludes a benefit of $4,515 to cost of sales for inventory adjustments related to the Bakersfield refinery acquisition.
(3)
Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses at our Big Spring, California, and Krotz Springs refineries, exclusive of depreciation and amortization, by the applicable refinery’s total throughput volumes. Direct operating expenses related to the period prior to the startup of the Bakersfield refinery of $3,356 and $3,373 for the years ended December 31, 2011 and 2010, respectively, have been excluded from the per barrel measurement calculation.
(4)
Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process. The throughput data of the California refineries for the year ended December 31, 2011, reflects substantially eight months of operations due to the integration during the first three months of the year and work performed in December to the Bakersfield hydrocracker unit. The throughput data of the California refineries for the year ended December 31, 2010, reflects eleven months of throughput data as the California refineries were shutdown in December to redeploy resources for the integration of the Bakersfield refinery acquired in June 2010. The throughput data of the Krotz Springs refinery for the year ended December 31, 2011, reflects approximately a one month shutdown due to flooding in Louisiana and the impact on crude supply to the refinery and a two week shutdown in November for the tie-in of capital projects work. The throughput data of the Krotz Springs refinery for the year ended December 31, 2010, reflects substantially seven months of operations beginning in June 2010 due to the restart after major turnaround activity.
(5)
Total refinery production represents the barrels per day of various products produced from processing crude and other refinery feedstocks through the crude units and other conversion units at the refineries.
(6)
Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.
(1)
Cost of sales includes intersegment purchases of asphalt blends from our refining and unbranded marketing segment at prices which approximate wholesale market prices. These intersegment purchases are eliminated through consolidation of our financial statements.
(2)
Blended asphalt represents base asphalt that has been blended with other materials necessary to sell the asphalt as a finished product.
(3)
Non-blended asphalt represents base material asphalt and other components that require additional blending before being sold as a finished product.
(4)
Asphalt margin is a per ton measurement calculated by dividing the margin between net sales and cost of sales by the total sales volume. Asphalt margins are used in the asphalt industry to measure operating results related to asphalt sales.
(1)
Includes excise taxes on sales by the retail segment of $60,686, $54,930 and $47,137 for the years ended December 31, 2011, 2010 and 2009, respectively. Net sales also includes net royalty and related net credit card fees of $5,526, $4,221 and $1,382 for the years ended December 31, 2011, 2010 and 2009, respectively.
(2)
Cost of sales includes intersegment purchases of motor fuels from our refining and unbranded marketing segment at prices which approximate wholesale market prices. These intersegment purchases are eliminated through consolidation of our financial statements.
(3)
Branded fuel sales represent branded fuel sales to our wholesale marketing customers that are primarily supplied by the Big Spring refinery. The branded fuels that are not supplied by the Big Spring refinery are obtained from third-party suppliers. The branded fuel margin represents the margin between the net sales and cost of sales attributable to our branded fuel sales volume, expressed on a cents-per-gallon basis.
(4)
Retail fuel and merchandise sales per site for 2009 were calculated using 306 stores for eleven months and 308 stores for one month.
(5)
Retail fuel margin represents the difference between motor fuel sales revenue and the net cost of purchased motor fuel, including transportation costs and associated motor fuel taxes, expressed on a cents-per-gallon basis. Motor fuel margins are frequently used in the retail industry to measure operating results related to motor fuel sales.
(6)
Retail fuel sales price per gallon represents the average sales price for motor fuels sold through our retail convenience stores.
(7)
Merchandise margin represents the difference between merchandise sales revenues and the delivered cost of merchandise purchases, net of rebates and commissions, expressed as a percentage of merchandise sales revenues. Merchandise margins, also referred to as in-store margins, are commonly used in the retail convenience store industry to measure in-store, or non-fuel, operating results.
Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010
Net Sales
Consolidated. Net sales for the year ended December 31, 2011 were $7,186.3 million, compared to $4,030.7 million for the year ended December 31, 2010, an increase of $3,155.6 million. This increase was primarily due to higher refinery throughput volumes in our refining and unbranded marketing segment, increased sales volumes in our asphalt and retail and branded marketing segments and higher refined product prices.
Refining and Unbranded Marketing Segment. Net sales for our refining and unbranded marketing segment were $6,544.9 million for the year ended December 31, 2011, compared to $3,454.1 million for the year ended December 31, 2010, an increase of $3,090.8 million. This increase was due to higher refined product prices and higher refinery throughput in the year ended December 31, 2011 compared to the same period last year.
Combined refinery throughput for the year ended December 31, 2011, averaged 146,149 bpd, consisting of 63,614 bpd at the Big Spring refinery, 22,815 bpd at the California refineries and 59,720 bpd at the Krotz Springs refinery, compared to a combined average throughput of 105,868 bpd for the year ended December 31, 2010, consisting of 49,028 bpd at the Big Spring refinery, 17,596 bpd at the California refineries and 39,244 bpd at the Krotz Springs refinery.
The increase in refined product prices that our refineries experienced reflected the price increases experienced in each refinery's respective markets. The average per gallon price of Gulf Coast gasoline for the year ended December 31, 2011, increased $0.70, or 34.1%, to $2.75, compared to $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 37.5%, to $2.97, compared to $2.16 for the year ended December 31, 2010. The average per gallon price for Gulf Coast high-sulfur diesel for the year ended December 31, 2011, increased $0.81, or 38.6%, to $2.91, compared to $2.10 for the year ended December 31, 2010. The average per gallon price of West Coast LA CARBOB gasoline for the year ended December 31, 2011, increased $0.68, or 30.8%, to $2.89, compared to $2.21 for the year ended December 31, 2010. The average price per gallon of West Coast LA ultra low-sulfur diesel for the year ended December 31, 2011, increased $0.84, or 38.0%, to $3.05, compared to $2.21 for the year ended December 31, 2010.
Asphalt Segment. Net sales for our asphalt segment were $554.5 million for the year ended December 31, 2011, compared to $399.3 million for the year ended December 31, 2010, an increase of $155.2 million or 38.9%. This increase was due primarily to an increase in asphalt sales volumes and higher asphalt sales price for our blended asphalt product for the year ended December 31, 2011. The asphalt sales volume increased 27.0% from 863 thousand tons for the year ended December 31, 2010, to 1,096 thousand tons for the year ended December 31, 2011. The average blended asphalt sales price increased 13.4% from $477.26 per ton for the year ended December 31, 2010, to $541.44 per ton for the year ended December 31, 2011, and the average non-blended asphalt sales price increased 0.2% from $326.16 per ton for the year ended December 31, 2010, to $326.69 per ton for the year ended December 31, 2011.
Retail and Branded Marketing Segment. Net sales for our retail and branded marketing segment were $1,437.4 million for the year ended December 31, 2011, compared to $1,044.9 million for the year ended December 31, 2010, an increase of $392.5 million or 37.6%. This increase was primarily attributable to increases in motor fuel prices, motor fuel volumes and merchandise sales.
Cost of Sales
Consolidated. Cost of sales were $6,462.9 million for the year ended December 31, 2011, compared to $3,712.4 million for the year ended December 31, 2010, an increase of $2,750.5 million. This increase was primarily due to higher refinery throughput volumes in our refining and unbranded marketing segment, increased sales volumes in our asphalt and retail and branded marketing segments and higher crude oil prices.
Refining and Unbranded Marketing Segment. Cost of sales for our refining and unbranded marketing segment were $5,996.8 million for the year ended December 31, 2011, compared to $3,311.8 million for the year ended December 31, 2010, an increase of $2,685.0 million. This increase was primarily due to increased refinery throughput as well as an increase in the cost of crude oil used by our refineries. The average price of WTI increased 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. The average price of Buena Vista crude increased 38.9% from $78.08 per barrel for the year ended December 31, 2010, to $108.43 per barrel for the year ended December 31, 2011. The average price of LLS crude increased 37.7% from $80.61 per barrel for the year ended December 31, 2010, to $110.98 per barrel for the year ended December 31, 2011.
Asphalt Segment. Cost of sales for our asphalt segment were $525.0 million for the year ended December 31, 2011, compared to $355.3 million for the year ended December 31, 2010, an increase of $169.7 million or 47.8%. The increase was
due to higher asphalt sales volumes and higher crude oil costs for the year ended December 31, 2011 compared to the year ended December 31, 2010.
Retail and Branded Marketing Segment. Cost of sales for our retail and branded marketing segment were $1,291.9 million for the year ended December 31, 2011, compared to $912.9 million for the year ended December 31, 2010, an increase of $379.0 million or 41.5%. This increase was primarily attributable to increases in motor fuel prices, motor fuel volumes and merchandise costs.
Direct Operating Expenses
Consolidated. Direct operating expenses were $285.7 million for the year ended December 31, 2011, compared to $249.9 million for the year ended December 31, 2010, an increase of $35.8 million or 14.3%.
Refining and Unbranded Marketing Segment. Direct operating expenses for our refining and unbranded marketing segment for the year ended December 31, 2011 were $243.0 million, compared to $205.8 million for the year ended December 31, 2010, an increase of $37.2 million or 18.1%. This increase is due primarily to expenses associated with the startup of operations at our Bakersfield refinery and increased refinery throughput.
Asphalt Segment. Direct operating expenses for our asphalt segment for the year ended December 31, 2011, were $42.6 million, compared to $44.1 million for the year ended December 31, 2010, a decrease of $1.5 million or 3.4%. This decrease is primarily due to lower natural gas costs.
Selling, General and Administrative Expenses
Consolidated. SG&A expenses for the year ended December 31, 2011, were $143.1 million, compared to $128.1 million for the year ended December 31, 2010, an increase of $15.0 million or 11.7%, primarily due to higher employee-related costs and higher advertising and marketing costs for the year ended December 31, 2011.
Refining and Unbranded Marketing Segment. SG&A expenses for our refining and unbranded marketing segment for the year ended December 31, 2011, were $32.2 million, compared to $22.8 million for the year ended December 31, 2010, an increase of $9.4 million or 41.2%. This increase was primarily due to higher employee-related costs in the year ended December 31, 2011, and $3.5 million related to net bad debt recoveries and insurance premium refunds in the year ended December 31, 2010.
Asphalt Segment. SG&A expenses for our asphalt segment for the year ended December 31, 2011, were $5.1 million, compared to $5.5 million for the year ended December 31, 2010, a decrease of $0.4 million or 7.2%. This decrease is due primarily to lower employee related costs for the year ended December 31, 2011.
Retail and Branded Marketing Segment. SG&A expenses for our retail and branded marketing segment for the year ended December 31, 2011, were $105.1 million, compared to $99.0 million for the year ended December 31, 2010, an increase of $6.1 million or 6.2%. This increase was primarily attributable to higher advertising and marketing costs.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2011, was $113.7 million, compared to $102.1 million for the year ended December 31, 2010, an increase of $11.6 million or 11.4%, due primarily to capital expenditures for the acquisition and integration of the Bakersfield refining assets which began operations in June 2011. Also, depreciation and amortization for the year ended December 31, 2011, includes a full year of amortization of turnaround costs related to the 2010 Krotz Springs turnaround and restart in June 2010, and the write-off of deferred costs for our retail and marketing segment.
Operating Income (Loss)
Consolidated. Operating income (loss) for the year ended December 31, 2011, was $181.5 million, compared to $(160.8) million for the year ended December 31, 2010, an increase of $342.3 million. This increase was primarily due to overall higher refinery margins and throughput, higher retail fuel sales volumes and margins and increased merchandise sales and margins.
Refining and Unbranded Marketing Segment. Operating income (loss) for our refining and unbranded marketing segment was $184.0 million for the year ended December 31, 2011, compared to $(166.0) million for the year ended December 31, 2010, an increase of $350.0 million. This increase was primarily due to overall higher refining margins and increased refinery throughput.
Refinery operating margin at the Big Spring refinery was $18.84 per barrel for the year ended December 31, 2011, compared to $6.03 per barrel for the year ended December 31, 2010. This increase is primarily due to higher Gulf Coast 3/2/1 crack spreads. The average Gulf Coast 3/2/1 crack spread increased 184.3% to $23.37 per barrel for the year ended December 31, 2011, compared to $8.22 per barrel for the year ended December 31, 2010. Refinery operating margin at the
California refineries was $(1.31) per barrel for the year ended December 31, 2011, compared to $1.08 per barrel for the year ended December 31, 2010. This decrease reflects the impact of the California refineries' shutdown until its restart in late March 2011, offset by higher West Coast 3/1/1/1 crack spreads. The average West Coast 3/1/1/1 crack spreads increased 10.3% to $9.20 per barrel for the year ended December 31, 2011, compared to $8.34 per barrel for the year ended December 31, 2010. The Krotz Springs refinery operating margin for the year ended December 31, 2011, was $3.05 per barrel, compared to $2.24 per barrel for the year ended December 31, 2010. The Krotz Springs refinery restarted operations in June 2010 after being down for the first five months of 2010 for a major turnaround. Additionally, the average Gulf Coast 2/1/1 high sulfur diesel crack spread for the year ended December 31, 2011, was $7.00 per barrel, compared to $5.26 per barrel for the year ended December 31, 2010.
Asphalt Segment. Operating loss for our asphalt segment was $24.5 million for the year ended December 31, 2011, compared to $12.5 million for the year ended December 31, 2010, an increase of $12.0 million or 96.4%. This increase in loss was primarily due to the decrease in asphalt sales margins resulting from the greater increase in crude oil prices relative to the increase in our asphalt sales prices.
Retail and Branded Marketing Segment. Operating income for our retail and branded marketing segment was $24.8 million for the year ended December 31, 2011, compared to $19.8 million for the year ended December 31, 2010, an increase of $5.0 million. This increase was primarily due to higher retail fuel sales volumes and margins and higher merchandise sales and margins.
Interest Expense
Interest expense was $88.3 million for the year ended December 31, 2011, compared to $94.9 million for the year ended December 31, 2010, a decrease of $6.6 million, or 7.0%. This decrease is primarily due to a charge of $6.7 million for the write-off of debt issuance costs associated with our prepayment of the Alon Refining Krotz Springs, Inc. revolving credit facility for the year ended December 31, 2010.
Income Tax Expense (Benefit)
Income tax expense (benefit) was $18.9 million for the year ended December 31, 2011, compared to $(90.5) million for the year ended December 31, 2010. This increase resulted from our higher pre-tax income for the year ended December 31, 2011, compared to the year ended December 31, 2010, and a decrease in the effective tax rate. Our effective tax rate was 30.2% for the year ended December 31, 2011, compared to an effective tax rate of 37.6% for the year ended December 31, 2010. The lower effective tax rate for the year ended December 31, 2011, was due primarily to benefits arising from carry-back claims on prior year income taxes.
Net Income (Loss) Attributable to Non-controlling Interest
Net income (loss) attributable to non-controlling interest was $1.2 million for the year ended December 31, 2011, compared to $(9.6) million for the year ended December 31, 2010, an increase of $10.8 million primarily due to its proportional share of the higher after-tax income in 2011.
Net Income (Loss) Available to Common Stockholders
Net income (loss) available to common stockholders was $42.5 million for the year ended December 31, 2011, compared to $(122.9) million for the year ended December 31, 2010, an increase of $165.4 million. This increase was attributable to the factors discussed above.
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Net Sales
Consolidated. Net sales for the year ended December 31, 2010 were $4,030.7 million, compared to $3,915.7 million for the year ended December 31, 2009, an increase of $115.0 million or 2.9%. This increase was due to higher refined product prices and higher motor fuel volumes and merchandise sales, partially offset by lower refinery throughput and lower asphalt sales volumes.
Refining and Unbranded Marketing Segment. Net sales for our refining and unbranded marketing segment were $3,454.1 million for the year ended December 31, 2010, compared to $3,359.0 million for the year ended December 31, 2009, an increase of $95.1 million or 2.8%. This increase was primarily due to higher refined product prices partially offset by lower refinery throughput in the year ended December 31, 2010.
Combined refinery throughput for the year ended December 31, 2010 averaged 105,868 bpd, consisting of 49,028 bpd at the Big Spring refinery, 17,596 bpd at the California refineries, and 39,244 bpd at the Krotz Springs refinery compared to average total refinery throughput for the year ended December 31, 2009 of 139,365 bpd, consisting of 59,870 bpd at the Big Spring refinery, 31,158 bpd at the California refineries and 48,337 at the Krotz Springs refinery. The Big Spring refinery throughput was lower as a result of efforts to implement new operating procedures and the California refineries' throughput was lower due to our continued efforts to optimize asphalt production with demand and the redeployment of resources to integrate the Bakersfield refinery. The Krotz Springs refinery throughput was lower due to its shutdown for turnaround activities until its restart in June 2010.
The average per gallon price of Gulf Coast gasoline for the year ended December 31, 2010 increased $0.41, or 25.0%, to $2.05, compared to $1.64 for the year ended December 31, 2009. The average Gulf Coast ultra-low sulfur diesel per gallon price for the year ended December 31, 2010 increased $0.50, or 30.1%, to $2.16, compared to $1.66 for the year ended December 31, 2009. The average per gallon price for Gulf Coast high sulfur diesel for the year ended December 31, 2010, increased $0.48, or 29.6%, to $2.10, compared to $1.62 for the year ended December 31, 2009. The average per gallon price of West Coast LA CARBOB gasoline for the year ended December 31, 2010 increased $0.36, or 19.4%, to $2.21, compared to $1.85 for the year ended December 31, 2009. The average West Coast LA ultra-low sulfur diesel price for the year ended December 31, 2010 increased $0.50, or 29.2%, to $2.21, compared to $1.71 for the year ended December 31, 2009.
Asphalt Segment. Net sales for our asphalt segment were $399.3 million for the year ended December 31, 2010, compared to $440.9 million for the year ended December 31, 2009, a decrease of $41.6 million or 9.4%. This decrease was due to a decrease in asphalt sales volumes, partially offset by higher asphalt sales prices for the year ended December 31, 2010. The asphalt sales volumes decreased 27.5%, from 1,191 thousand tons for the year ended December 31, 2009 to 863 thousand tons for the year ended December 31, 2010. The average blended asphalt sales price increased 16.4% from $409.88 per ton for the year ended December 31, 2009 to $477.26 per ton for the year ended December 31, 2010 and the average non-blended asphalt sales price increased 91.8% from $170.05 per ton for the year ended December 31, 2009 to $326.16 per ton for the year ended December 31, 2010.
Retail and Branded Marketing Segment. Net sales for our retail and branded marketing segment were $1,044.9 million for the year ended December 31, 2010, compared to $808.2 million for the year ended December 31, 2009, an increase of $236.7 million or 29.3%. This increase was attributable to increases in motor fuel prices, motor fuel volumes and merchandise sales.
Cost of Sales
Consolidated. Cost of sales were $3,712.4 million for the year ended December 31, 2010, compared to $3,502.8 million for the year ended December 31, 2009, an increase of $209.6 million or 6.0%. This increase was due to increased costs in all segments due to higher crude oil prices, higher motor fuel volumes and merchandise sales and the realized gain recognized for the year ended December 31, 2009 for the unwind of the heating oil hedge, partially offset by lower refinery throughput and lower asphalt sales volumes.
Refining and Unbranded Marketing Segment. Cost of sales for our refining and unbranded marketing segment were $3,311.8 million for the year ended December 31, 2010, compared to $3,117.5 million for the year ended December 31, 2009, an increase of $194.3 million or 6.2%. This increase was due to higher crude oil costs and the realized gain recognized in the year ended December 31, 2009 for the unwind of the heating oil hedge, partially offset by lower refinery throughput volumes. The average price of WTI per barrel for the year ended December 31, 2010 increased $17.59 per barrel to $79.41 per barrel, compared to $61.82 per barrel for the year ended December 31, 2009, an increase of 28.5%. The average price of Buena Vista crude increased 31.0% from $59.62 per barrel for the year ended December 31, 2009, to $78.08 per barrel for the year ended December 31, 2010. The average price of LLS crude increased 32.4% from $60.90 per barrel for the year ended December 31, 2009, to $80.61 per barrel for the year ended December 31, 2010.
Asphalt Segment. Cost of sales for our asphalt segment were $355.3 million for the year ended December 31, 2010, compared to $386.0 million for the year ended December 31, 2009, a decrease of $30.7 million or 8.0%. This decrease was due to lower asphalt sales volumes partially offset by higher crude oil costs for the year ended December 31, 2010.
Retail and Branded Marketing Segment. Cost of sales for our retail and branded marketing segment was $912.9 million for the year ended December 31, 2010, compared to $691.7 million for the year ended December 31, 2009, an increase of $221.2 million or 32.0%. This increase was attributable to increases in motor fuel prices, motor fuel volumes and merchandise costs for the year ended December 31, 2010.
Direct Operating Expenses
Consolidated. Direct operating expenses were $249.9 million for the year ended December 31, 2010, compared to $265.5 million for the year ended December 31, 2009, a decrease of $15.6 million or 5.9%. This decrease was due to lower refinery throughput volumes for the year ended December 31, 2010.
Refining and Unbranded Marketing Segment. Direct operating expenses for our refining and unbranded marketing segment for the year ended December 31, 2010 were $205.8 million, compared to $221.4 million for the year ended December 31, 2009, a decrease of $15.6 million or 7.0%. This decrease was due to lower refinery throughput volumes for the year ended December 31, 2010 compared to the prior year, which was partially offset by the acquisition of the Bakersfield refinery in 2010.
Asphalt Segment. Direct operating expenses for our asphalt segment for the years ended December 31, 2010 and 2009 were $44.1 million.
Selling, General and Administrative Expenses
Consolidated. SG&A expenses for the year ended December 31, 2010 were $128.1 million, compared to $129.4 million for the year ended December 31, 2009, a decrease of $1.3 million or 1.0%.
Refining and Unbranded Marketing Segment. SG&A expenses for our refining and unbranded marketing segment for the year ended December 31, 2010 were $22.8 million, compared to $29.4 million for the year ended December 31, 2009, a decrease of $6.6 million or 22.4%. This decrease was due to net bad debt recoveries of $1.5 million for the year ended December 31, 2010 compared to bad debt expense of $3.3 million for the year ended December 31, 2009.
Asphalt Segment. SG&A expenses for our asphalt segment for the year ended December 31, 2010 were $5.5 million, compared to $4.6 million for the year ended December 31, 2009, an increase of $0.9 million or 19.6%. This increase is due to higher employee related costs for the year ended December 31, 2010.
Retail and Branded Marketing Segment. SG&A expenses for our retail and branded marketing segment for the year ended December 31, 2010 were $99.0 million, compared to $94.7 million for the year ended December 31, 2009, an increase of $4.3 million or 4.5%. This increase was attributable to increased payroll and related costs.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2010 was $102.1 million, compared to $97.2 million for the year ended December 31, 2009, an increase of $4.9 million or 5.0%. This increase was primarily attributable to depreciation on the capital expenditures placed into service during the fourth quarter of 2009 and in 2010.
Operating Income (Loss)
Consolidated. Operating loss for the year ended December 31, 2010 was $160.8 million, compared to $80.8 million for the year ended December 31, 2009, an increase of $80.0 million. This increase in loss was due to lower refinery throughput and margins, lower asphalt sales volumes and the realized gain recognized in the year ended December 31, 2009 for the unwind of the heating oil hedge, partially offset by higher motor fuel volumes and higher merchandise sales and margins.
Refining and Unbranded Marketing Segment. Operating loss for our refining and unbranded marketing segment was $166.0 million for the year ended December 31, 2010, compared to $86.5 million for the year ended December 31, 2009, an increase of $79.5 million. This increase in loss was due to lower refinery throughput at all our refineries, lower refining margins at our Krotz Springs and California refineries for the year ended December 31, 2010 compared to the prior year and the realized gain recognized in the year ended December 31, 2009 for the unwind of the heating oil hedge. This was partially offset by higher margins at our Big Spring refinery, lower direct operating costs and net bad debt recoveries of $1.5 million in the year ended December 31, 2010 compared to bad debt expense of $3.3 million for the year ended December 31, 2009.
Refinery operating margin at the Big Spring refinery was $6.03 per barrel for the year ended December 31, 2010 compared to $4.35 per barrel for the year ended December 31, 2009. The Big Spring refinery light product yields were approximately 89.4% for the year ended December 31, 2010 and 82.1% for the year ended December 31, 2009. Refinery operating margin at the California refineries was $1.08 per barrel for the year ended December 31, 2010 compared to $1.83 per barrel for the year ended December 31, 2009. The Krotz Springs refinery operating margin for the year ended December 31, 2010 was $2.24 per barrel compared to $5.66 per barrel for the year ended December 31, 2009.
Asphalt Segment. Operating loss for our asphalt segment was $12.5 million for the year ended December 31, 2010, compared to $0.6 million for the year ended December 31, 2009, an increase of $11.9 million. This increase was due to lower sales volumes for the year ended December 31, 2010.
Retail and Branded Marketing Segment. Operating income for our retail and branded marketing segment was $19.8 million for the year ended December 31, 2010, compared to $7.8 million for the year ended December 31, 2009, an increase of $11.8 million. This increase was attributable to higher motor fuel volumes and higher merchandise sales and margins.
Interest Expense
Interest expense was $94.9 million for the year ended December 31, 2010, compared to $111.1 million for the year ended December 31, 2009, a decrease of $16.2 million or 14.6%.This decrease is primarily due to $20.5 million of unamortized debt issuance costs written off as a result of the prepayment of $163.8 million of term debt in the year ended December 31, 2009 and $5.7 million of interest expenses related to the liquidation of our heating oil hedge in 2009. This was partially offset by $6.7 million of debt issuance costs written off associated with our prepayment of the Alon Refining Krotz Springs, Inc. revolving credit facility in 2010.
Gain from Bargain Purchase
In connection with the Bakersfield refinery acquisition in June 2010, the acquisition date fair value of the identifiable net assets acquired exceeded the fair value of the consideration transferred, resulting in a $17.5 million bargain purchase gain for the year ended December 31, 2010.
Income Tax Benefit
Income tax benefit was $90.5 million for the year ended December 31, 2010, compared to $64.9 million for the year ended December 31, 2009, an increase of $25.6 million. This increase in income tax benefit was attributable to our lower 2010 taxable income compared to 2009. The pre-tax loss for the year ended December 31, 2010 includes the $17.5 million non-taxable bargain purchase gain. Our effective tax rate was 37.6% for the year ended December 31, 2010, excluding the $17.5 million non-taxable bargain purchase gain, compared to an effective tax rate of 38.8% for the year ended December 31, 2009.
Net Loss Attributable to Non-controlling Interest
Net loss attributable to non-controlling interest was $9.6 million for the year ended December 31, 2010, compared to $8.6 million for the year ended December 31, 2009, an increase of $1.0 million.
Net Loss Available to Common Stockholders
Net loss available to common stockholders was $122.9 million for the year ended December 31, 2010, compared to $115.2 million for the year ended December 31, 2009, an increase in loss of $7.7 million. This increase was attributable to the factors discussed above.
Liquidity and Capital Resources
Our primary sources of liquidity are cash on hand, cash generated from our operating activities, borrowings under our revolving credit facilities, inventory supply and offtake arrangements, other credit lines and advances from affiliates.
We have agreements with J. Aron for the supply of crude oil that will support the operations of the Big Spring refinery, the Krotz Springs refinery and the California refineries. These agreements substantially reduce 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 business during the next 12 months. Our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control.
Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or equity securities, or other possible capital markets transactions, the proceeds of which could be used to refinance current indebtedness, extend or replace existing revolving credit facilities or for other corporate purposes.
Cash Flows
The following table sets forth our consolidated cash flows for the years ended December 31, 2011, 2010 and 2009:
Cash Flows Provided by Operating Activities
Net cash provided by operating activities for the year ended December 31, 2011, was $69.6 million, compared to $21.3 million for the year ended December 31, 2010. The change in cash provided by operating activities of $48.2 million is primarily attributable to the increase of approximately $317.7 million in net income, adjusted for non-cash adjustments such as deferred income tax expense, bargain purchase gain, gain on the disposition of assets and depreciation, during the year ended December 31, 2011 compared to 2010. These non-cash adjustments were offset primarily by a decrease of inventory of $91.3 million in 2010 compared to an increase in inventory of $7.4 million in 2011 which was mainly due to the integration of the Bakersfield hydrocracker unit and an increase in accounts receivable of $114.7 million due to higher refinery throughput during the year ended December 31, 2011 compared to 2010. Additionally, 2010 included $56.7 million of income tax refunds compared to $5.6 million, net received in 2011.
Net cash provided by operating activities for the year ended December 31, 2010 was $21.3 million, compared to $283.1 million for the year ended December 31, 2009. The change of $261.9 million in net cash provided by operating activities for the year ended December 31, 2010 is primarily attributable to the difference of $162.7 million in net income, adjusted for non-cash reconciling items during the year ended December 31, 2010 compared to 2009, and the receipt of proceeds from the liquidation of our heating oil crack spread hedge during the year ended December 31, 2009 of $133.6 million.
Cash Flows Used In Investing Activities
Net cash used in investing activities was $126.5 million for the year ended December 31, 2011, compared to $40.9 million for the year ended December 31, 2010. The change in net cash used in investing activities of $85.6 million was principally due to an increase in capital expenditures of $65.9 million in the year ended December 31, 2011, which primarily related to the integration of the Bakersfield hydrocracker unit, and a decrease in proceeds from the disposition of assets of $19.6 million, as compared to the year ended December 31, 2010.
Net cash used in investing activities was $40.9 million for the year ended December 31, 2010, compared to $138.7 million for the year ended December 31, 2009. The change in net cash used in investing activities of $97.8 was primarily due to lower capital expenditures of $93.3 million, proceeds received from the disposition of assets and sale of securities of $22.0 million and $36.9 million, respectively, and a decrease in the earnout payments made to Valero of $10.9 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009. This was partially offset by the acquisition of the Bakersfield refinery of $32.4 million during the year ended December 31, 2010 and insurance proceeds of $34.1 million received in the year ended December 31, 2009 to rebuild the Big Spring refinery.
Cash Flows Provided by Financing Activities
Net cash provided by financing activities was $142.4 million during the year ended December 31, 2011, compared to $50.8 million during the year ended December 31, 2010. The change in net cash provided by financing activities of $91.5 million is primarily attributable to a $144.7 million increase in revolving credit balances, net, proceeds from the sale of common stock of $11.9 million and an increase in the net proceeds from long-term debt of $20.6 million during the year ended December 31, 2011, partially offset by a decrease in the proceeds from inventory supply agreements of $44.6 million during the year ended December 31, 2011 and the proceeds from the sale of preferred stock of $40.0 million during the year ended December 31, 2010.
Net cash provided by (used in) financing activities was $50.8 million for the year ended December 31, 2010 compared to ($122.5) million for the year ended December 31, 2009. The change in net cash used in financing activities of $173.4 million was primarily attributable to the proceeds received from the sale of preferred stock of $40.0 million, cash received from the inventory supply agreement of $45.8 million during the year ended December 31, 2010, compared to cash received from an
inventory supply agreement of $20.2 million during the year ended December 31, 2009, as well as an overall decrease in payments made on long-term debt and debt issuance costs during the year ended December 31, 2010.
Cash and Cash Equivalents
We consider all highly-liquid instruments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value.
As of December 31, 2011, our total cash and cash equivalents were $157.1 million and we had total debt of $1,050.2 million.
Indebtedness
Alon USA Energy, Inc. Credit Facilities
Term Loan Credit Facility. We have a term loan (the “Alon Energy Term Loan”) that will mature on August 2, 2013. Principal payments of $4.5 million per annum are paid in quarterly installments, subject to reduction from mandatory repayments associated with certain events.
Borrowings under the Alon Energy Term Loan bear interest at a rate based on a margin over the Eurodollar rate from between 1.75% to 2.50% per annum based upon the ratings of the loans by Standard & Poor's Rating Service and Moody's Investors Service, Inc. Currently, the margin is 2.25% over the Eurodollar rate.
The Alon Energy Term Loan is jointly and severally guaranteed by all of our subsidiaries except for our retail subsidiaries and those subsidiaries established in conjunction with the Krotz Springs refinery acquisition and certain subsidiaries established in conjunction with the Bakersfield acquisition. The Alon Energy Term Loan is secured by a second lien on cash, accounts receivable and inventory and a first lien on most of our remaining assets. Both liens exclude the assets of our retail subsidiaries, those subsidiaries established in conjunction with the Krotz Springs refinery acquisition and certain subsidiaries established in conjunction with the Bakersfield acquisition.
The Alon Energy 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 Alon Energy Term Loan does not contain any maintenance financial covenants.
At December 31, 2011 and 2010, the Alon Energy Term Loan had an outstanding balance of $425.3 million and $429.8 million, respectively.
Letter of Credit Facility. In March 2010, we entered into an unsecured credit facility with Israel Discount Bank of New York (the “Alon Energy Letter of Credit Facility”) for the issuance of letters of credit in an amount not to exceed $60.0 million and with a sub-limit for borrowings not to exceed $30.0 million. This facility will terminate on January 31, 2013. The Alon Energy Letter of Credit Facility contains certain restrictive covenants including maintenance financial covenants. At December 31, 2011 and 2010, we had $47.6 million and $60.0 million, respectively, of outstanding letters of credit under this facility. Borrowings under this facility bear interest at the Eurodollar rate plus 3.00% per annum subject to an overall minimum interest rate of 4.00%.
Alon USA, LP Credit Facility
Revolving Credit Facility. We have a $240.0 million revolving credit facility (the “Alon USA LP Credit Facility”) that will mature on January 1, 2013. The Alon USA LP Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility.
Borrowings under the Alon USA LP Credit Facility bear interest at the Eurodollar rate plus 3.00% per annum subject to an overall minimum interest rate of 4.00%.
The Alon USA LP 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 and other specified property, in each case, excluding those of Alon Paramount Holdings, Inc. (“Alon Holdings”), other than asphalt inventories at all locations except those located at the California refineries, and its subsidiaries other than Alon Pipeline Logistics, LLC (“Alon Logistics”), the subsidiaries established in conjunction with the Krotz Springs refinery acquisition, the subsidiaries established in conjunction with the Bakersfield refinery acquisition and our retail subsidiaries.
The Alon USA LP Credit Facility contains certain restrictive covenants including maintenance financial covenants.
Borrowings of $200.0 million and $122.0 million were outstanding under the Alon USA LP Credit Facility at December 31, 2011 and 2010, respectively. At December 31, 2010 and 2009, outstanding letters of credit under the Alon USA
LP Credit Facility were $35.5 million and $117.0 million, respectively.
In March 2012, the Alon USA LP Credit Facility maturity date was extended through March 1, 2016.
Paramount Petroleum Corporation Credit Facility
Revolving Credit Facility. Paramount Petroleum Corporation has a $300.0 million revolving credit facility (the “Paramount Credit Facility”) that will mature on February 28, 2012. The Paramount 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 or the amount of the borrowing base under the facility.
Borrowings under the Paramount Credit Facility bear interest at the Eurodollar rate plus a margin based on excess availability. Based on the excess availability at December 31, 2011, the margin was 1.75%.
The Paramount Credit Facility is primarily secured by (i) a first lien on cash, accounts receivables, inventories and related assets and (ii) a second lien on Alon Holdings' (excluding Alon Logistics) fixed assets and other specified property.
The Paramount Credit Facility contains certain restrictive covenants related to working capital, operations and other matters.
Borrowings of $108.3 million at December 31, 2011, included in current portion of long-term debt and $63.1 million at December 31, 2010, included in long-term debt were outstanding under the Paramount Credit Facility. At December 31, 2011 and 2010, outstanding letters of credit under the Paramount Credit Facility were $18.0 million and $1.3 million, respectively.
In February 2012, we repaid our obligations under the Paramount Credit Facility.
Alon Refining Krotz Springs, Inc. Credit Facilities
Senior Secured Notes. In October 2009, Alon Refining Krotz Springs, Inc. (“ARKS”) issued 13.50% senior secured notes (the “Senior Secured Notes”) in aggregate principal amount of $216.5 million in a private offering. In February 2010, ARKS exchanged $216.5 million of Senior Secured Notes for an equivalent amount of Senior Secured Notes (“Exchange Notes”) registered under the Securities Act of 1933. The Exchange Notes will mature on October 15, 2014 and the entire principal amount is due at maturity. Interest is payable semi-annually in arrears on April 15 and October 15. The Exchange Notes are substantially identical to the Senior Secured Notes, except that the Exchange Notes have been registered with the Securities and Exchange Commission and are not subject to transfer restrictions. The Senior Secured Notes were issued at an offering price of 94.857% and ARKS received gross proceeds of $205.4 million (before fees and expenses related to the offering). ARKS used the proceeds to repay in full all outstanding obligations under its term loan at that time. The remaining proceeds from the offering were used for general corporate purposes.
The terms of the Senior Secured Notes are governed by an indenture (the “Indenture”) and the obligations under the Indenture are secured by a first priority lien on ARKS' property, plant and equipment and a second priority lien on ARKS' cash, accounts receivable and inventory.
The Indenture contains restrictive covenants such as restrictions on loans, mergers, sales of assets, additional indebtedness and restricted payments. The Indenture does not contain any maintenance financial covenants.
At December 31, 2011 and 2010, the Senior Secured Notes had an outstanding balance (net of unamortized discount) of $209.3 million and $207.4 million, respectively. ARKS is utilizing the effective interest method to amortize the original issue discount over the life of the Senior Secured Notes.
Retail Credit Facilities
Alon Brands Term Loans. In March 2011, Alon Brands issued $30.0 million five-year unsecured notes (the "Alon Brands Term Loans") to a group of investors including certain shareholders of Alon Israel and their affiliates. The notes will mature in March 2016. The group of investors have the right to request that principal payments of the loan will be paid in four equal, consecutive annual payments, starting in March 2013. Otherwise, the principal amount will be paid at the maturity date in March 2016. During the third quarter of 2011, certain shareholders of Alon Israel assigned $6.0 million of the Alon Brands Term Loans to Alon Israel.
Borrowings under the Alon Brands Term Loans bear interest at a rate of 7% per annum, payable on a semi-annual basis, provided that the interest rate will increase to 9% per annum solely with respect to the portion of the loan equal to the unexercised portion of the warrants described below.
The Alon Brands Term Loans contain certain restrictive covenants, including maintenance financial covenants.
In conjunction with the issuance of the Alon Brands Term Loans, we issued 3,092,783 warrants to purchase shares of our common stock at an initial exercise price per share of $9.70. The warrants are exercisable in whole or in part until March 2016,
five years from the date of issuance. The allocated fair value of the warrants was $11.0 million and was recorded as additional paid-in capital at the time of issuance.
At December 31, 2011, the Alon Brands Term Loans had an outstanding balance of $20.1 million (net of unamortized discount of $9.9 million). We are utilizing the effective interest method to amortize the discount over the five-year life of the Alon Brands Term Loans and have amortized $1.1 million to interest expense for the year ended December 31, 2011.
In March 2012, we issued $30.0 million of preferred stock and repaid in full our obligations under the Alon Brands Term Loans. Also as part of the transaction, the warrants issued in conjunction with the Alon Brands Term Loans were surrendered back to us.
Term Credit Agreement. Southwest Convenience Stores, LLC (“SCS”) is party to a credit agreement (the “SCS Credit Agreement”) that, as amended, matures on December 30, 2015. On December 30, 2010, SCS entered into an amendment to the SCS Credit Agreement, which increased the amount outstanding from $73.4 million (“SCS Refinancing Term Loan”) by $10.0 million (“SCS Additional Term Loan”) and also included a revolving credit loan (“SCS Revolving Credit Loan”) with a maximum loan amount of the lesser of the borrowing base or $10.0 million.
Borrowings under the SCS Refinancing Term Loan bear interest at a Eurodollar rate plus 2.00% per annum with principal payments made in quarterly installments based on a 15-year amortization schedule. Borrowings under the SCS Additional Term Loan bear interest at a Eurodollar rate plus 2.75% per annum with principal payments made in quarterly installments based on a 5-year amortization schedule. Borrowings under the SCS Revolving Credit Loan bear interest at a Eurodollar rate plus 2.75% per annum.
The obligations under the SCS Credit Agreement are secured by a pledge of substantially all of the assets of SCS and Skinny's, LLC and each of their subsidiaries, including cash, accounts receivable and inventory. The SCS Credit Agreement contains certain restrictive covenants including maintenance financial covenants.
At December 31, 2011 and 2010, the SCS Credit Agreement had an outstanding balance under the term loans of $76.5 million and $83.4 million, respectively. At December 31, 2011 and 2010, the SCS Revolving Credit Loan had an outstanding balance of $10.0 million and $10.0 million, respectively.
Other Retail Related Credit Facilities
In 2003, we obtained $1.5 million in mortgage loans to finance the acquisition of new retail locations. The interest rates on these loans ranged between 5.5% and 9.7%, with 5 to 15 year payment terms. At December 31, 2011 and 2010, the outstanding balances were $0.7 million and $0.7 million, respectively.
Financial Covenants. We have certain credit facilities that contain restrictive covenants, including maintenance financial covenants. At December 31, 2011, we were in compliance with these covenants.
Capital Spending
Each year our Board of Directors approves capital projects, including regulatory and planned turnaround projects that our management is authorized to undertake in our annual capital budget. Additionally, at times when conditions warrant or as new opportunities arise, other projects or the expansion of existing projects may be approved. Our total capital expenditure budgets, including expenditures for chemical catalyst and turnarounds, for 2012 and 2013 are $102.3 million and $170.5 million, respectively.
The following table summarizes our expected capital expenditures for 2012 and 2013 by operating segment and major category:
Turnaround and Chemical Catalyst Costs. Our 2011 turnaround and chemical catalyst costs were $9.7 million.
Between our major turnarounds we perform periodic scheduled turnaround projects on various units at our refineries. A summary of our expected turnaround and chemical catalyst costs for the following five years are as follows:
Contractual Obligations and Commercial Commitments
Information regarding our known contractual obligations of the types described below as of December 31, 2011 is set forth in the following table:
____________
(1)
Balances represent the minimum committed volume multiplied by the tariff and terminal rates pursuant to the terms of the Pipelines and Terminals Agreement with HEP, as well as our minimum requirements with Sunoco.
(2)
Other commitments include refinery maintenance services costs.
As of December 31, 2011, we did not have any material capital lease obligations or any agreements to purchase goods or services, other than those included in the table above, that were binding on us.
Off-Balance Sheet Arrangements
We have no material off-balance sheet arrangements.
Critical Accounting Policies
Our accounting policies are described in the notes to our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. We prepare our consolidated financial statements in conformity with GAAP. In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events, some of which we may have little or no control over. Our critical accounting policies, which are discussed below, could materially affect the amounts recorded in our consolidated financial statements.
Inventory. Crude oil, refined products and blendstocks for the refining and unbranded marketing segment and asphalt for the asphalt segment are priced at the lower of cost or market value. Cost is determined using the LIFO valuation method. Under the LIFO valuation method, we charge the most recent acquisition costs to cost of sales, and we value inventories at the earliest acquisition costs. We selected this method because we believe it more accurately reflects the cost of our current sales. If the market value of inventory is less than the inventory cost on a LIFO basis, then the inventory is written down to market value. An inventory write-down to market value results in a non-cash accounting adjustment, decreasing the value of our crude oil and refined products inventory and increasing our cost of sales. A reduction of inventory volumes during 2011, 2010 and 2009 resulted in a liquidation of LIFO inventory layers carried at lower costs which prevailed in previous years. The liquidation decreased cost of sales by approximately $41.4 million in 2011, $18.6 million in 2010 and $10.2 million in 2009. Market values of crude oil, refined products, asphalt and blendstock inventories exceeded LIFO costs by $93.4 million and $115.1 million at December 31, 2011 and 2010, 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, 2011, 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.
Deferred Income Taxes. Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
Asset Retirement Obligations. 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 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.
Goodwill and Intangible Assets. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over 1 to 40 years. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. Alon uses December 31 of each year as the valuation date for annual impairment testing purposes.
At December 31, 2011, we had three reporting units with goodwill; California refining, California asphalt, and Retail operations. The fair values of our reporting units in 2011 that contain goodwill were determined using two methods, one based on discounted cash flow models with estimated cash flows based on internal forecasts of revenues and expenses and the other based on market earnings multiples. Each reporting unit was evaluated separately. Cash flows were discounted at rates that approximate a market participants' weighted average cost of capital; 10.6% for both California refining and California asphalt and 7.8% for Retail operations. We believe these two approaches are appropriate valuation techniques for the purposes of our impairment testing. Therefore, we concluded from our valuations, based on business conditions and market values that existed at December 31, 2011, that none of our goodwill was impaired. The fair value of the California refining reporting unit was not considered substantially in excess of carrying value. The California refining reporting unit has $39 million of goodwill. Our valuation of this reporting unit assumes we will be able to achieve mid-cycle margins over the long-term. If we are unable to achieve these margins for a sustained period in the future, it could result in impairment of goodwill. In addition if, (1) our equity value declines, (2) the fair value of our reporting units decline, or (3) the impact of economic or competitive factors adversely affect beyond what was anticipated, we could conclude in future periods that impairment losses are required in order to reduce the carrying value of our goodwill, and, to a lesser extent, long-lived assets. Depending on the severity of the changes in the key factors underlying the valuation of our reporting units, such losses could be significant.
Reconciliation of Amounts Reported Under Generally Accepted Accounting Principles
Reconciliation of Adjusted EBITDA to amounts reported under generally accepted accounting principles in financial statements.
Adjusted EBITDA represents earnings before net income attributable to non-controlling interest, income tax expense, interest expense, depreciation and amortization, gain on bargain purchase and gain on disposition of assets. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of net income attributable to non-controlling interest, income tax expense, interest expense, gain on bargain purchase, gain on disposition of assets and the accounting effects of capital expenditures and acquisitions, items that may vary for different companies for reasons unrelated to overall operating performance.
Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:
•
Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
•
Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;
•
Adjusted EBITDA does not reflect the prior claim that non-controlling interest have on the income generated by non-wholly-owned subsidiaries;
•
Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and
•
Our calculation of Adjusted EBITDA may differ from EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.
Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.
The following table reconciles net income (loss) available to common stockholders to Adjusted EBITDA for the years ended December 31, 2011, 2010 and 2009:
Adjusted EBITDA does not exclude loss on heating oil call option crack spread contracts of $36,280 for the year ended December 31, 2011. The heating oil call option crack spread contracts are considered a financing activity. Adjusted EBITDA excluding the loss on these heating oil call option crack spread contracts would be $300,257.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Changes in commodity prices, purchased fuel prices and interest rates are our primary sources of market risk. Our risk management committee oversees all activities associated with the identification, assessment and management of our market risk exposure.
Commodity Price Risk
We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels and governmental regulatory initiatives. Our risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations.
In order to manage the uncertainty relating to inventory price volatility, we have consistently applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as timing of crude oil cargo deliveries, turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. Upon the review and approval of our risk management committee, we may utilize the commodity futures market to manage these anticipated inventory variances.
We maintain inventories of crude oil, refined products, asphalt and blendstocks, the values of which are subject to wide fluctuations in market prices driven by world economic conditions, regional and global inventory levels and seasonal conditions. As of December 31, 2011, we held approximately 1.8 million barrels of crude oil, refined product and asphalt inventories valued under the LIFO valuation method. Market value exceeded carrying value of LIFO costs by $93.4 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced by $1.8 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, 2011:
Interest Rate Risk
As of December 31, 2011, $720.1 million of our outstanding debt was at floating interest rates out of which approximately $200.0 million was at the Eurodollar rate plus 3.00%, subject to a minimum interest rate of 4.00%. As of December 31, 2011, we had an interest rate swap agreement with a notional amount of $100.0 million with a remaining period of 12 months and a fixed interest rate of 4.25%. An increase of 1% in the Eurodollar rate on indebtedness, net of the interest rate swap agreement outstanding and the instrument subject to the minimum interest rate, would result in an increase in our interest expense of approximately $5.8 million per year.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Consolidated Financial Statements and Schedule are included as an annex of this Annual Report on Form 10-K. See the Index to Consolidated Financial Statements and Schedule on page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES.
Disclosure Controls and Procedures
Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended (the “Exchange Act”)) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or furnish under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or furnish under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures.
Management's Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate “internal control over financial reporting” (as defined in Rule 13a-15(f) under the Exchange Act) for Alon. Our management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2011. In management's evaluation, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Management believes that as of December 31, 2011, our internal control over financial reporting was effective based on those criteria.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the quarter ended December 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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.
ITEM 9B. OTHER INFORMATION.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
The information concerning our directors set forth under “Corporate Governance Matters - The Board of Directors” in the proxy statement for our 2012 annual meeting of stockholders (the “Proxy Statement”) is incorporated herein by reference. Certain information concerning our executive officers is set forth under the heading “Business and Properties - Executive Officers of the Registrant” in Items 1 and 2 of this Annual Report on Form 10-K, which is incorporated herein by reference. The information concerning compliance with Section 16(a) of the Exchange Act set forth under “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement is incorporated herein by reference.
The information concerning our audit committee set forth under “Corporate Governance Matters - Committees of the Board and - Audit Committee” in the Proxy Statement is incorporated herein by reference.
The information regarding our Code of Ethics set forth under “Corporate Governance Matters - Corporate Governance Guidelines, Code of Business Conduct and Ethics and Committee Charters” in the Proxy Statement is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
The information set forth under “Executive Compensation” in the Proxy Statement is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The information set forth under “Security Ownership of Certain Beneficial Holders and Management” in the Proxy Statement is incorporated herein by reference. The information regarding our equity plans under which shares of our common stock are authorized for issuance as set forth under “Equity Compensation Plan Information” in the Proxy Statement is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
The information set forth under “Certain Relationships and Related Transactions” and under “Corporate Governance Matters - Independent Directors” in the Proxy Statement is incorporated herein by reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
The information set forth under “Independent Public Accountants” in the Proxy Statement is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)
The following documents are filed as part of this report:
1.
Financial Statements. See “Index to Consolidated Financial Statements and Schedule” on page.
2.
Financial Statement Schedules and Other Financial Information. All financial statement schedules are omitted because either they are not applicable or the required information is included in the consolidated financial statements or notes included herein.
3.
Exhibits. Exhibits filed as part of this Form 10-K are as follows:
____________
*
Identifies management contracts and compensatory plans or arrangements.
†
Filed under confidential treatment request.
ALON USA ENERGY, INC. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Alon USA Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Alon USA Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the years in the three-year period ended December 31, 2011. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Alon USA Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Alon USA Energy, Inc.'s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 12, 2012 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
/s/ KPMG LLP
Dallas, Texas
March 12, 2012
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Alon USA Energy, Inc.:
We have audited Alon USA Energy, Inc.'s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Alon USA Energy, Inc.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Alon USA Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Alon USA Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the years in the three-year period ended December 31, 2011, and our report dated March 12, 2012 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Dallas, Texas
March 12, 2012
ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(dollars in thousands, except per share data)
___________________________________
(1)
Includes excise taxes on sales by the retail segment of $60,686, 54,930 and $47,137 for the years ended December 31, 2011, 2010 and 2009, respectively.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except as noted)
(1)
Description and Nature of Business
In this document, Alon may refer to Alon USA Energy, Inc. and its consolidated subsidiaries or to Alon USA Energy, Inc. or an individual subsidiary.
Alon USA Energy, Inc. and its subsidiaries engage in the business of refining and marketing of petroleum products, primarily in the South Central, Southwestern and Western regions of the United States. Alon's business consists of three operating segments: (i) refining and unbranded marketing, (ii) asphalt and (iii) retail and branded marketing.
Refining and Unbranded Marketing Segment. Alon’s refining and unbranded marketing segment includes sour and heavy crude oil refineries located in Big Spring, Texas; and Paramount, Bakersfield and Long Beach, California (the “California refineries”); and a light sweet crude oil refinery located in Krotz Springs, Louisiana. Alon's refineries have a combined throughput capacity of approximately 240,000 barrels per day (“bpd”). At these refineries, Alon refines crude oil into products including gasoline, diesel, jet fuel, petrochemicals, feedstocks, asphalts and other petroleum products, which are marketed primarily in the South Central, Southwestern and Western regions of the United States. In Bakersfield, Alon is converting intermediate products into finished products and is not refining crude oil. Finished products and blendstocks are also marketed through sales and exchanges with other major oil companies, state and federal governmental entities, unbranded wholesale distributors and various other third parties. Alon also acquires finished products through exchange agreements and third-party suppliers.
Alon markets transportation fuels produced at our Big Spring refinery in West and Central Texas, Oklahoma, New Mexico and Arizona. Alon refers to its operations in these regions as its “physically integrated system” because it supplies the retail and branded marketing segment convenience stores and unbranded distributors in this region with motor fuels produced at its Big Spring refinery and distributed through a network of pipelines and terminals which it either owns or has access to through leases or long-term throughput agreements.
Alon markets refined products produced from its California refineries to wholesale distributors, other refiners and third parties primarily on the West Coast. Alon started-up the Bakersfield hydrocracker in late June 2011 and began processing vacuum gas oil produced at Alon's other California locations.
The Krotz Springs refinery supplies multiple demand centers in the Southern and Eastern United States markets through the Colonial products pipeline system. The Krotz Springs refinery processing units are structured to yield approximately 101.5% of total feedstock input, meaning that for each 100 barrels of crude oil and feedstocks input into the refinery, it produces 101.5 barrels of refined products. Of the 101.5%, on average 99.0% is light finished products such as gasoline and distillates, including diesel and jet fuel, petrochemical feedstocks and liquefied petroleum gas, and the remaining 2.5% is primarily heavy oils.
Asphalt Segment. Alon’s asphalt segment includes the Willbridge, Oregon refinery and 11 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington (Richmond Beach), Arizona (Phoenix and Flagstaff), and Nevada (Fernley) (50% interest) as well as a 50% interest in Wright Asphalt Products Company, LLC (“Wright”) which specializes in marketing patented tire rubber modified asphalt products. Alon produces both paving and roofing grades of asphalt and, depending on the terminal, can manufacture performance-graded asphalts, emulsions and cutbacks. The operations in which Alon has a 50% interest (Fernley and Wright), are recorded under the equity method of accounting and the investments are included as part of total assets in the asphalt segment data.
Alon's asphalt segment markets asphalt produced at its Big Spring and California refineries included in the refining and unbranded marketing segment. Asphalt produced by the refineries in Alon's refining and unbranded marketing segment is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices.
Retail and Branded Marketing Segment. Alon’s retail and branded marketing segment operates 302 convenience stores located in Central and West Texas and New Mexico. These convenience stores typically offer various grades of gasoline, diesel fuel, general merchandise and food and beverage products to the general public, primarily under the 7-Eleven, Alon and FINA brand names. Substantially all of the motor fuel sold through Alon’s convenience stores and the majority of the motor fuels marketed in Alon’s branded business is supplied by Alon’s Big Spring refinery.
Alon markets gasoline and diesel under the Alon and FINA brand names through a network of approximately 640 locations, including Alon's convenience stores. Approximately 55% of the gasoline and 21% of the diesel motor fuel produced at Alon's Big Spring refinery was transferred to Alon's retail and branded marketing segment at prices substantially determined by reference to commodity pricing information published by Platts. Additionally, Alon's retail and branded marketing segment
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
licenses the use of the Alon and FINA brand names and provides credit card processing services to approximately 230 licensed locations that are not under fuel supply agreements.
Alon has operated under an exclusive license to use the FINA trademark in the wholesale distribution of motor fuel within Texas, Oklahoma, New Mexico, Arizona, Arkansas, Louisiana, Colorado and Utah since 2000. Alon's license to use the FINA brand will expire in August 2012 in accordance with its terms. Alon developed its own brand and logo in anticipation of this expiration of this license and has begun the process of converting all of its locations and all locations served by its branded marketing business to the new Alon brand. Under the brand, Alon will no longer be subject to the geographic limitations contained in the FINA license agreement.
(2)
Basis of Presentation and Certain Significant Accounting Policies
(a)
Basis of Presentation
The consolidated financial statements include the accounts of Alon USA Energy, Inc. and its subsidiaries (collectively, “Alon”). All significant intercompany balances and transactions have been eliminated.
(b)
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(c)
Revenue Recognition
Revenues from sales of refined products are earned and realized upon transfer of title to the customer based on the contractual terms of delivery (including payment terms and prices). Title primarily transfers at the refinery or terminal when the refined product is loaded into the common carrier pipelines, trucks or railcars (free on board origin). In some situations, title transfers at the customer's destination (free on board destination).
Alon occasionally enters into refined product buy/sell arrangements, which involve linked purchases and sales related to refined product sales contracts entered into to address location, quality or grade requirements. These buy/sell transactions are included on a net basis in sales in the consolidated statements of operations and profits are recognized when the exchanged product is sold.
In the ordinary course of business, logistical and refinery production schedules necessitate the occasional sale of crude oil to third parties. All purchases and sales of crude oil are recorded net, in cost of sales in the consolidated statements of operations.
Sulfur credits purchased to meet federal gasoline sulfur regulations are recorded in inventory at the lower of cost or market. Cost is computed on an average cost basis. Purchased sulfur credits are removed from inventory and charged to cost of sales in the consolidated statements of operations as they are utilized. Sales of excess sulfur credits are recognized in earnings and included in net sales in the consolidated statements of operations.
Excise taxes on sales by Alon's retail and branded marketing segment is presented on a gross basis. Supplemental information regarding the amount of such taxes included in revenues are provided in a footnote on the face of the consolidated statements of operations. All other excise taxes are presented on a net basis in the consolidated statements of operations.
(d)
Cost Classifications
Refining and unbranded marketing cost of sales includes crude oil and other raw materials, inclusive of transportation costs. Asphalt cost of sales includes costs of purchased asphalt, blending materials and transportation costs. Retail and branded marketing cost of sales includes cost of sales for motor fuels and for merchandise. Motor fuel cost of sales represents the net cost of purchased fuel, including transportation costs and associated motor fuel taxes. Merchandise cost of sales includes the delivered cost of merchandise purchases, net of merchandise rebates and commissions. Cost of sales excludes depreciation and amortization, which is presented separately in the consolidated statements of operations.
Direct operating expenses, which relate to Alon's refining and unbranded marketing and asphalt segments, include costs associated with the actual operations of the refineries and terminals, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs. Operating costs associated with Alon's crude oil and product pipelines are considered to be transportation costs and are reflected in cost of sales in the consolidated statements of operations.
Selling, general and administrative expenses consist primarily of costs relating to the operations of the convenience stores,
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
including labor, utilities, maintenance and retail corporate overhead costs. Refining and unbranded marketing and asphalt segments corporate overhead and marketing expenses are also included in selling, general and administrative expenses.
Interest expense consists of interest expense, letters of credit, financing costs associated with crude oil purchases, fees, and both the amortization and write-off of deferred debt issuance costs but excludes capitalized interest.
(e)
Cash and Cash Equivalents
All highly-liquid instruments with a maturity of three months or less at the time of purchase are considered to be cash equivalents. Cash equivalents are stated at cost, which approximates market value.
(f)
Accounts Receivable
The majority of accounts receivable is due from companies in the petroleum industry. Credit is extended based on evaluation of the customer's financial condition and in certain circumstances, collateral, such as letters of credit or guarantees, are required. Credit losses are charged to reserve for bad debts when accounts are deemed uncollectible. Reserve for bad debts is based on a combination of current sales and specific identification methods.
(g)
Inventories
Crude oil, refined products and blendstocks for the refining and unbranded marketing segment and asphalt for the asphalt segment (including inventory consigned to others) are stated at the lower of cost or market. Cost is determined under the last-in, first-out (“LIFO”) valuation method. Cost of crude oil, refined products, asphalt and blendstock inventories in excess of market value are charged to cost of sales. Such charges are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. Materials and supplies are stated at average cost. Cost for the retail and branded marketing segment merchandise inventories is determined under the retail inventory method and cost for retail and branded marketing segment fuel inventories is determined under the first-in, first-out (“FIFO”) method.
(h)
Hedging Activity
All derivative instruments are recorded in the consolidated balance sheet as either assets or liabilities measured at their fair value. Alon generally considers all commodity forwards, futures, swaps, and option contracts to be part of its risk management strategy. Alon has elected not to designate these commodity contracts as cash flow hedges for financial accounting purposes. Accordingly, net unrealized gains and losses for changes in the fair value on open commodity derivative contracts are recognized in cost of sales or in other income (loss), net on the consolidated statement of operations.
Alon selectively designates certain commodity derivative contracts and interest rate derivatives as cash flow hedges. The effective portion of the gains or losses associated with these derivative contracts designated and qualifying as cash flow hedges are initially recorded in accumulated other comprehensive income in the consolidated balance sheet and reclassified into the statement of operations in the period in which the underlying hedged forecasted transaction affects income. The amounts recorded into the consolidated statement of operations for commodity derivative contracts is recorded as a part of cost of sales and the amounts recorded for interest rate derivatives are recognized as interest expense. The ineffective portion of the gains or losses on the derivative contracts, if any, is recognized in the consolidated statement of operations as it is incurred.
(i)
Property, Plant and Equipment
The carrying value of property, plant and equipment includes the fair value of the asset retirement obligation and has been reflected in the consolidated balance sheets at cost, net of accumulated depreciation.
Property, plant and equipment, net of salvage value, are depreciated using the straight-line method at rates based on the estimated useful lives for the assets or groups of assets, beginning in the first month of operation following acquisition or completion. Alon capitalizes interest costs associated with major construction projects based on the effective interest rate on aggregate borrowings.
Leasehold improvements are depreciated on the straight-line method over the shorter of the contractual lease terms or the estimated useful lives.
Expenditures for major replacements and additions are capitalized. Refining and unbranded marketing segment and asphalt segment expenditures for routine repairs and maintenance costs are charged to direct operating expense as incurred. Retail and branded marketing segment routine repairs and maintenance costs are charged to selling, general and administrative expense as incurred. The applicable costs and accumulated depreciation of assets that are sold, retired, or otherwise disposed of are removed from the accounts and the resulting gain or loss is recognized.
(j)
Impairment of Long-Lived Assets and Assets to be Disposed Of
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
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 management's judgment and assumptions. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs of disposition.
(k)
Asset Retirement Obligations
The accounting standards established for asset retirement obligations 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 and 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 (Note 11).
(l)
Turnarounds and Chemical Catalysts Costs
Alon records the cost of planned major refinery maintenance, referred to as turnarounds, and chemical catalyst used in the refinery process units, which are typically replaced in conjunction with planned turnarounds, in “Other assets” in the consolidated balance sheets. Turnaround and catalyst costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround. The amortization of deferred turnaround and chemical catalyst costs are presented in “Depreciation and amortization” in the consolidated statements of operations.
(m)
Income Taxes
Alon accounts for income taxes under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
(n)
Stock-Based Compensation
Alon uses the grant date fair value based method for calculating and accounting for stock-based compensation.
Stock compensation expense is presented as selling, general and administrative expenses in the consolidated statements of operations (Note 15).
(o)
Environmental Expenditures
Alon accrues for costs associated with environmental remediation obligations when such costs are probable and can be reasonably estimated. Environmental liabilities represent the estimated costs to investigate and remediate contamination at Alon's properties. This estimate is based on internal and third-party assessments of the extent of the contaminations, the selected remediation technology and review of applicable environmental regulations.
Accruals for estimated costs from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value unless payments are fixed and determinable. Recoveries of environmental remediation costs from other parties are recorded as assets when the receipt is deemed probable (Note 19). Estimates are updated to reflect changes in factual information, available technology or applicable laws and regulations.
(p)
Earnings Per Share
Earnings per share are computed by dividing net income (loss) available to common stockholders by the weighted average number of participating common shares outstanding during the reporting period. Diluted earnings per share are calculated to give effect to all potentially dilutive common shares that were outstanding during the period (Note 17).
(q)
Other Comprehensive Income (Loss)
Comprehensive income (loss) consists of net income (loss) and other gains and losses affecting stockholders' equity that, under United States generally accepted accounting principles, are excluded from net income (loss), such as defined benefit pension plan adjustments and gains and losses related to certain derivative instruments. The balance in other comprehensive
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
income (loss), net of tax reported in the consolidated statements of stockholders' equity consists of defined benefit pension plans, fair value of interest rate swap adjustments, and the fair value of commodity derivative contract adjustments.
(r)
Postretirement Benefits
Alon recognizes the overfunded or underfunded status of its defined benefit pension and postretirement plans as an asset or a liability in the statement of financial position and recognizes changes in that funded status through comprehensive income in the year the changes occur.
(s)
Commitments and Contingencies
Liabilities for loss contingencies, arising from claims, assessments, litigation, fines, and penalties and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recorded as assets, and are not offset against the related environmental liability.
(t)
Goodwill and Intangibles
Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over 1 to 40 years. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. Alon uses December 31 of each year as the valuation date for annual impairment testing purposes.
(u)
Reclassifications
Certain reclassifications have been made to the prior period balances to conform to the current presentation.
(v)
New Accounting Standards
In September 2011, the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 350, Intangibles - Goodwill and Other, were amended to permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If the existence of events or circumstances leads an entity to believe that the fair value of the entity is not below its carrying amount, then performing the two-step impairment test is unnecessary. The adoption of this guidance will not affect Alon's financial position or results of operations.
In June 2011, the provisions of FASB ASC 220, Comprehensive Income, were amended to allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. Under either option, the entity is required to present reclassification adjustments on the face of the financial statements for items that are reclassified from other comprehensive income to net income in the statement where those components are presented. These provisions are effective for the first interim or annual period beginning after December 15, 2011, and are to be applied retrospectively, with early adoption permitted. The adoption of this guidance will not affect Alon's financial position or results of operations because these requirements only affect disclosures.
(3)
Acquisitions
Bakersfield Refinery Acquisition
On June 1, 2010, Alon completed the acquisition of the Bakersfield, California refinery (“Bakersfield refinery”) from Big West of California, LLC, a subsidiary of Flying J, Inc. The aggregate purchase price was $58,409 in cash, which included the purchase price of hydrocarbon inventories. In connection with the acquisition, an affiliate of Alon purchased certain refinery assets not installed at the Bakersfield refinery location for $26,000. The remaining assets were purchased by Alon. Alon incurred $550 of acquisition-related costs that were recognized in selling, general and administrative expenses in the consolidated statement of operations for the year ended December 31, 2010.
Alon integrated the Bakersfield hydrocracker unit into its California operations to process vacuum gas oil produced at the other California locations. Alon had capital expenditures of approximately $52,000 for the year ended December 31, 2011 to complete the necessary projects to integrate the Bakersfield hydrocracker unit. The newly integrated assets began operations
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
late second quarter of 2011.
An acquirer is required to recognize and measure the goodwill acquired in a business combination or a gain from a bargain purchase. FASB ASC 805 defines a bargain purchase as a business combination in which the total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any non-controlling interest in the acquiree, and it requires the acquirer to recognize that excess in earnings as a gain attributable to the acquirer.
The fair value of the assets acquired and liabilities assumed are as follows:
In connection with the acquisition of the Bakersfield refinery, Alon recorded an accrued environmental remediation obligation of $42,122. This amount was recorded as a non-current liability in Alon's consolidated balance sheet at the acquisition date.
Also in connection with the acquisition of the Bakersfield refinery, Alon entered into an indemnification agreement with a prior owner for remediation expenses of conditions that existed at the refinery on the acquisition date. Alon is required to make indemnification claims to the prior owner by March 15, 2015. The indemnification amount was $17,122 and was recorded as a non-current receivable in the consolidated balance sheet at the acquisition date.
(4)
Segment Data
Alon’s revenues are derived from three operating segments: (i) refining and unbranded marketing, (ii) asphalt and (iii) retail and branded marketing. The reportable operating segments are strategic business units that offer different products and services. The segments are managed separately as each segment requires unique technology, marketing strategies and distinct operational emphasis. Each operating segment’s performance is evaluated primarily based on operating income.
Operating income (loss) for each segment consists of net sales less cost of sales, direct operating expenses, selling, general and administrative expenses, depreciation and amortization, and gain (loss) on disposition of assets. Intersegment sales are intended to approximate wholesale market prices. Consolidated totals presented are after intersegment eliminations.
Operations that are not included in any of the three segments are included in the corporate category. These operations consist primarily of corporate headquarters operating and depreciation expenses.
Total assets of each segment consist of net property, plant and equipment, inventories, cash and cash equivalents, accounts and other receivables and other assets directly associated with the segment’s operations. Corporate assets consist primarily of corporate headquarters information technology and administrative equipment.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
Segment data as of and for the years ended December 31, 2011, 2010 and 2009 are presented below:
(5)
Fair Value
The carrying amounts of Alon’s cash and cash equivalents, receivables, payables and accrued liabilities approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of long-term debt approximate fair value. Derivative financial instruments are carried at fair value, which is based on quoted market prices.
Alon must determine fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, Alon utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy. Alon generally applies the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the consolidated balance sheets as of December 31, 2011 and 2010:
(6)
Derivative Financial Instruments
Commodity Derivatives - Mark to Market
Alon selectively utilizes commodity derivatives to manage its exposure to commodity price fluctuations and uses crude oil and refined product commodity derivative contracts to reduce risk associated with potential price changes on committed obligations. Alon does not speculate using derivative instruments. Credit risk on Alon’s derivative instruments is mitigated by transacting with counterparties meeting established collateral and credit criteria.
Cash Flow Hedges
To designate a derivative as a cash flow hedge, Alon documents at the inception of the hedge the assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. If, during the term of the derivative, the hedge is determined to be no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings when the underlying transaction occurs.
Interest Rate Derivatives. Alon selectively utilizes interest rate related derivative instruments to manage its exposure to floating-rate debt instruments. Alon periodically uses interest rate swap agreements to manage its floating to fixed rate position by converting certain floating-rate debt to fixed-rate debt. As of December 31, 2011, Alon had an interest rate swap agreement with a notional amount of $100,000, a remaining period of 12 months and a fixed interest rate of 4.25%. This swap was accounted for as a cash flow hedge.
For cash flow hedges, gains and losses reported in equity are reclassified into interest expense when the forecasted transaction affects income. During the years ended December 31, 2011 and 2010, Alon recognized in equity unrealized after-tax gains of $2,147 and $6,131, respectively, for the fair value measurement of the interest rate swap agreements. There were no amounts reclassified from equity into interest expense as a result of the discontinuance of cash flow hedge accounting.
For the years ended December 31, 2011 and 2010, there was no hedge ineffectiveness recognized in income. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.
Commodity Derivatives. In May 2008, as part of financing the acquisition of the Krotz Springs refinery, Alon entered into futures contracts for the forward purchase of crude oil and the forward sale of heating oil of 14,849,750 barrels. These futures contracts were designated as cash flow hedges for accounting purposes. In the fourth quarter of 2008, Alon determined during its retrospective assessment of hedge effectiveness that the hedge was no longer highly effective. Cash flow hedge accounting
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
was discontinued in the fourth quarter of 2008 and all changes in value subsequent to the discontinuance were recognized into earnings. An after-tax loss of $4,563 and an after-tax gain of $3,409 were reclassified from equity to earnings for the years ended December 31, 2010 and 2009, respectively. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.
The following table presents the effect of derivative instruments on the consolidated statements of financial position.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
The following tables present the effect of derivative instruments on Alon’s consolidated statements of operations and accumulated other comprehensive income (“OCI”).
Derivatives designated as hedging instruments:
Derivatives not designated as hedging instruments:
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
(7)
Accounts and Other Receivables
Financial instruments that potentially subject Alon to concentration of credit risk consist primarily of trade accounts receivables. Credit risk is minimized as a result of the ongoing credit assessment of Alon's customer base and a lack of concentration in Alon's customer base. Alon performs ongoing credit evaluations of its customers and requires letters of credit, prepayments or other collateral or guarantees as management deems appropriate. Valero Energy Corporation ("Valero") and J. Aron & Company (“J. Aron”) (Note 19) each accounted for more than 10% of Alon's net sales for the years ended December 31, 2011 and 2010. Valero (Note 19) and BP North America each accounted for more than 10% of Alon's net sales for the year ended December 31, 2009. Alon's allowance for doubtful accounts is reflected as a reduction of accounts and other receivables in the consolidated balance sheets.
Accounts and other receivables consisted of the following:
The following table sets forth the allowance for doubtful accounts for the years ended December 31, 2011, 2010 and 2009:
________
(1)
Substantially all of the additions charged to expense in 2009 relate to the SEMGroup, LP bankruptcy.
(2)
Amounts written off net of recoveries. The 2011 deduction is related to the write-off of the SEMGroup, LP bankruptcy amounts charged to expense in 2009 and 2008.
(8)
Inventories
Alon’s inventories (including inventory consigned to others) are stated at the lower of cost or market. Cost is determined under the last-in, first-out (LIFO) method for crude oil, refined products, asphalt, and blendstock inventories. Materials and supplies are stated at average cost. Cost for convenience store merchandise inventories is determined under the retail inventory method and cost for convenience store fuel inventories is determined under the first-in, first-out (FIFO) method.
Carrying value of inventories consisted of the following:
Crude oil, refined products, asphalt and blendstock inventories totaled 1,838 thousand barrels and 2,441 thousand barrels as of December 31, 2011 and 2010, respectively. A reduction of inventory volumes during 2011, 2010 and 2009 resulted in a liquidation of LIFO inventory layers carried at lower costs which prevailed in previous years. The liquidation decreased cost of sales by approximately $59,332 in 2011, $18,619 in 2010, and $10,169 in 2009. An increase in LIFO inventory associated with crude oil resulted in an increase to cost of sales of $17,959 for the year ended December 31, 2011.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
Market values of crude oil, refined products, asphalt and blendstock inventories exceeded LIFO costs by $93,401 and $115,072 at December 31, 2011 and 2010, respectively.
Crude oil inventory consigned to others represents inventory that was sold to third parties with an obligation by Alon to repurchase the inventory at the end of the respective agreements. As a result of this requirement to repurchase inventory, no revenue was recorded on these transactions and the inventory volumes remain valued under the LIFO method.
Alon had 951 thousand barrels and 674 thousand barrels of crude oil consigned to others at December 31, 2011 and 2010, respectively. Alon recorded liabilities associated with this consigned inventory of $26,389 in accounts payable and $58,328 in other non-current liabilities and $27,034 in accounts payable and $32,433 in other non-current liabilities at December 31, 2011 and 2010, respectively.
Additionally, Alon recorded accrued liabilities of $117 and accounts receivable of $1,073 at December 31, 2011 and 2010, respectively, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.
Normal Purchase Normal Sale
Effective January 1, 2011, Alon elected to account for all inventory financing agreements it has under the "Normal Purchase Normal Sales" exemption of FASB ASC 815, Derivatives and Hedging. This exemption applies to situations where commodities are physically delivered. In previous periods Alon recorded changes in the fair value of the estimated settlement liability of these contracts through the consolidated statement of operations. Beginning January 1, 2011 and forward, changes in fair value of the estimated settlement liability will no longer be recorded due to the Normal Purchase Normal Sale exemption. If the contracts were settled December 31, 2011, the payment would be in excess of the liabilities recorded by $19,702.
(9)
Property, Plant and Equipment, Net
Property, plant and equipment, net consisted of the following:
The increase in refining facilities at December 31, 2011 is mainly due to capital expenditures related to the integration of the hydrocracker unit in Bakersfield, California into Alon's California operations.
The useful lives on depreciable assets used to determine depreciation expense were as follows:
Alon capitalized interest of $2,273, $1,004 and $1,692 for the years ended December 31, 2011, 2010 and 2009, respectively.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
(10)
Other Assets
Other assets consisted of the following:
Debt issuance costs are amortized over the term of the related debt using the effective interest method. Amortization of debt issuance costs was $6,493, $5,825, and $7,112 for the years ended December 31, 2011, 2010 and 2009, respectively, and is recorded as interest expense in the consolidated statements of operations. Additionally, $6,659 and $20,482 of unamortized debt issuance costs were written off in 2010 and 2009, respectively (Note 13). Unamortized debt issuance costs written off in 2010 were related to the prepayment of the Alon Refining Krotz Springs, Inc. revolving credit facility in the first quarter of 2010. Unamortized debt issuance costs written off in 2009 were related to the prepayment of the Alon Refining Krotz Springs, Inc. term loan.
(11)
Accrued Liabilities and Other Non-Current Liabilities
Accrued liabilities and other non-current liabilities consisted of the following:
Alon has asset retirement obligations with respect to its refineries due to various legal obligations to clean and/or dispose of these assets at the time they are retired. However, the majority of these assets can be used for extended and indeterminate periods of time provided that they are properly maintained and/or upgraded. It is Alon's practice and intent to continue to maintain these assets and make improvements based on technological advances. When a date or range of dates can reasonably be estimated for the retirement of these assets or any component part of these assets, Alon will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using established present value techniques.
Alon has recorded asset retirement obligations for the removal of underground storage tanks and the removal of brand signage at Alon's owned and leased retail sites. The asset retirement obligation for storage tank removal on leased retail sites is
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
accreted over the expected life of the underground storage tank which approximates the average retail site lease term.
The following table summarizes the activity relating to the asset retirement obligations for the years ended December 31, 2011 and 2010:
(12)
Postretirement Benefits
(a)
Retirement Plans
Alon has four defined benefit pension plans covering substantially all of its employees, excluding employees of SCS. The benefits are based on years of service and the employee's final average monthly compensation. Alon's funding policy is to contribute annually not less than the minimum required nor more than the maximum amount that can be deducted for federal income tax purposes. Contributions are intended to provide not only for benefits attributed to service to date but also for those benefits expected to be earned in the future.
The measurement dates used to determine pension benefit measures for the pension plan is December 31, 2011 and 2010. Financial information related to Alon's pension plans is presented below.
The pre-tax amounts related to our defined benefit plans recognized in our consolidated balance sheets as of December 31, 2011 and 2010 were as follows:
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
The pre-tax amounts in accumulated other comprehensive income (loss) as of December 31, 2011 and 2010 that have not yet been recognized as components of net periodic benefit cost were as follows:
The following amounts included in accumulated other comprehensive income (loss) as of December 31, 2011 are expected to be recognized as components of net periodic benefit cost during the year ending December 31, 2012:
As of December 31, 2011 and 2010, the accumulated benefit obligation for each of Alon's pension plans was in excess of the fair value of plan assets. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans were as follows:
The weighted-average assumptions used to determine benefit obligations at December 31, 2011, 2010 and 2009 were as follows:
The discount rate used reflects the expected future cash flow based on Alon's funding valuation assumptions and participant data as of the beginning of the plan year. The expected future cash flow is discounted by the Principal Pension Discount Yield Curve for the fiscal year end because it has been specifically designed to help pension funds comply with statutory funding guidelines.
The weighted-average assumptions used to determine net periodic benefit costs for the years ended December 31, 2011, 2010 and 2009 were as follows:
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
Alon's overall expected long-term rate of return on assets is 9.0%. The expected long-term rate of return is based on the portfolio as a whole and not on the sum of the returns on individual asset categories. The components of net periodic benefit cost for the years and periods are as follows:
Plan Assets
The weighted-average asset allocation of Alon's pension benefits at December 31, 2011 and 2010 was as follows:
The fair value of Alon's pension assets by category as of December 31, 2011 and 2010 were as follows:
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
The investment policies and strategies for the assets of Alon's pension benefits is to, over a five year period, provide returns in excess of the benchmark. The portfolio is expected to earn long-term returns from capital appreciation and a stable stream of current income. This approach recognizes that assets are exposed to price risk and the market value of the plans' assets may fluctuate from year to year. Risk tolerance is determined based on Alon's specific risk management policies. In line with the investment return objective and risk parameters, the plans' mix of assets includes a diversified portfolio of equity, fixed-income and real estate investments. Equity investments include domestic and international stocks of various sizes of capitalization. The asset allocation of the plan is reviewed on at least an annual basis.
Cash Flows
Alon contributed $5,825 and $5,880 to the pension plan for the years ended December 31, 2011 and 2010, respectively, and expects to contribute $2,723 to the pension plan in 2012. There were no employee contributions to the plans.
The benefits expected to be paid in each year 2012 - 2016 are $2,723; $3,480; $3,266; $3,571 and $4,005, respectively. The aggregate benefits expected to be paid in the five years from 2017 - 2021 are $25,139. The expected benefits are based on the same assumptions used to measure Alon's benefit obligation at December 31, 2011 and include estimated future employee service.
In 2011, Alon revised its contributory benefit plans to provide for a 401(k) savings plan that is available to all employees, excluding employees of the retail marketing business. Alon matches 100% of individual participant contributions up to 3% of compensation.
In 2010, Alon did not match 401(k) contributions for Krotz Springs employees. In 2009, Alon matched 75% of individual participant contributions up to 8% of compensation. This match was limited to 6% of employee pay.
Alon sponsored a 401(k) savings plan for its West Coast employees (including those in its asphalt partnerships) which was available to all employees who were at least 21 years of age. Employees of its asphalt partnerships will continue under this plan in 2012. Participants could contribute a minimum of 1% up to a maximum of 50% of base pay subject to limits established by the Internal Revenue Service. Alon matched a 100% of individual participant contributions based on the first 6% of compensation with full vesting of matching and contributions occurring after two years of service. Alon's contribution for the years ended December 31, 2011 and 2010 was $1,472 and $1,742, respectively.
Alon sponsors a 401(k) plan in which employees of Alon's retail marketing segment may participate by contributing up to 50% of their pay after completing three months of service. Alon matches from 1% to 4.5% of employee compensation. This match is limited to 4.5% of employee pay with full vesting of matching and contributions occurring after two years of service. Alon's contribution for the years ended December 31, 2011 and 2010 was $648 and $500, respectively.
(b)
Postretirement Medical Plan
In addition to providing pension benefits, Alon adopted an unfunded postretirement medical plan covering certain health care and life insurance benefits (other benefits) for active and certain retired employees who meet eligibility requirements in the plan documents. The health care benefits in excess of certain limits are insured. The accrued benefit liability reflected in the consolidated balance sheets was $4,827 and $3,966 at December 31, 2011 and 2010, respectively, related to this plan.
As of December 31, 2011, the total accumulated postretirement benefit obligation under the postretirement medical plan was $4,827.
(13)
Indebtedness
Debt consisted of the following:
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
(a)
Alon USA Energy, Inc. Credit Facilities
Term Loan Credit Facility. Alon has a term loan (the “Alon Energy Term Loan”) that will mature on August 2, 2013. Principal payments of $4,500 per annum are paid in quarterly installments, subject to reduction from mandatory repayments associated with certain events.
Borrowings under the Alon Energy Term Loan bear interest at a rate based on a margin over the Eurodollar rate from between 1.75% to 2.50% per annum based upon the ratings of the loans by Standard & Poor's Rating Service and Moody's Investors Service, Inc. Currently, the margin is 2.25% over the Eurodollar rate.
The Alon Energy Term Loan is jointly and severally guaranteed by all of Alon's subsidiaries except for its retail subsidiaries and those subsidiaries established in conjunction with the Krotz Springs refinery acquisition and certain subsidiaries established in conjunction with the Bakersfield acquisition. The Alon Energy Term Loan is secured by a second lien on cash, accounts receivable and inventory and a first lien on most of its remaining assets. Both liens exclude the assets of its retail subsidiaries and those subsidiaries established in conjunction with the Krotz Springs refinery acquisition and certain subsidiaries established in conjunction with the Bakersfield acquisition.
The Alon Energy 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 Alon Energy Term Loan does not contain any maintenance financial covenants.
At December 31, 2011 and 2010, the Alon Energy Term Loan had an outstanding balance of $425,250 and $429,750, respectively.
Letter of Credit Facility. In March 2010, Alon entered into an unsecured credit facility with Israel Discount Bank of New York (the “Alon Energy Letter of Credit Facility”) for the issuance of letters of credit in an amount not to exceed $60,000 and with a sub-limit for borrowings not to exceed $30,000. This facility will terminate on January 31, 2013. The Alon Energy Letter of Credit Facility contains certain restrictive covenants including maintenance financial covenants. At December 31, 2011 and 2010, Alon had $47,561 and $60,000, respectively, of outstanding letters of credit under this facility. Borrowings under this facility bear interest at the Eurodollar rate plus 3.00% per annum subject to an overall minimum interest rate of 4.00%.
(b)
Alon USA, LP Credit Facility
Revolving Credit Facility. Alon has a $240,000 revolving credit facility (the “Alon USA LP Credit Facility”) that will mature on January 1, 2013. The Alon USA LP Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility.
Borrowings under the Alon USA LP Credit Facility bear interest at the Eurodollar rate plus 3.00% per annum subject to an overall minimum interest rate of 4.00%.
The Alon USA LP Credit Facility is secured by (i) a first lien on cash, accounts receivables, inventories and related assets and (ii) a second lien on fixed assets and other specified property, in each case, excluding those of Alon Paramount Holdings, Inc. (“Alon Holdings”), other than asphalt inventories at all locations except those located at the California Refineries, and its subsidiaries other than Alon Pipeline Logistics, LLC (“Alon Logistics”), the subsidiaries established in conjunction with the Krotz Springs refinery acquisition, the subsidiaries established in conjunction with the Bakersfield refinery acquisition and our retail subsidiaries.
The Alon USA LP Credit Facility contains certain restrictive covenants including maintenance financial covenants.
Borrowings of $200,000 and $122,000 were outstanding under the Alon USA LP Credit Facility at December 31, 2011 and 2010, respectively. At December 31, 2011 and 2010, outstanding letters of credit under the Alon USA LP Credit Facility were $35,509 and $116,956, respectively.
In March 2012, the Alon USA LP Credit Facility maturity date was extended through March 1, 2016.
(c)
Paramount Petroleum Corporation Credit Facility
Revolving Credit Facility. Paramount Petroleum Corporation has a $300,000 million revolving credit facility (the “Paramount Credit Facility”) that will mature on February 28, 2012. The Paramount Credit Facility is used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility.
Borrowings under the Paramount Credit Facility bear interest at the Eurodollar rate plus a margin based on excess availability. Based on the excess availability at December 31, 2011, the margin was 1.75%.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
The Paramount Credit Facility is primarily secured by (i) a first lien on cash, accounts receivables, inventories and related assets and (ii) a second lien on Alon Holdings' (excluding Alon Logistics) fixed assets and other specified property.
The Paramount Credit Facility contains certain restrictive covenants related to working capital, operations and other matters.
Borrowings of $108,341 at December 31, 2011,included in current portion of long-term debt and $63,120 at December 31, 2010, included in long-term debt were outstanding under the Paramount Credit Facility. At December 31, 2011 and 2010, outstanding letters of credit under the Paramount Credit Facility were $17,996 and $1,250, respectively.
In February 2012, Alon repaid its obligations under the Paramount Credit Facility.
(d)
Alon Refining Krotz Springs, Inc. Credit Facilities
Senior Secured Notes. In October 2009, Alon Refining Krotz Springs, Inc. (“ARKS”) issued 13.50% senior secured notes (the “Senior Secured Notes”) in aggregate principal amount of $216,500 in a private offering. In February 2010, ARKS exchanged $216,500 of Senior Secured Notes for an equivalent amount of Senior Secured Notes (“Exchange Notes”) registered under the Securities Act of 1933. The Exchange Notes will mature on October 15, 2014 and the entire principal amount is due at maturity. Interest is payable semi-annually in arrears on April 15 and October 15. The Exchange Notes are substantially identical to the Senior Secured Notes, except that the Exchange Notes have been registered with the Securities and Exchange Commission and are not subject to transfer restrictions. The Senior Secured Notes were issued at an offering price of 94.857% and ARKS received gross proceeds of $205,365 (before fees and expenses related to the offering). ARKS used the proceeds to repay in full all outstanding obligations under its term loan at that time. The remaining proceeds from the offering were used for general corporate purposes.
The terms of the Senior Secured Notes are governed by an indenture (the “Indenture”) and the obligations under the Indenture are secured by a first priority lien on ARKS' property, plant and equipment and a second priority lien on ARKS' cash, accounts receivable and inventory.
The Indenture contains restrictive covenants such as restrictions on loans, mergers, sales of assets, additional indebtedness and restricted payments. The Indenture does not contain any maintenance financial covenants.
At December 31, 2011 and 2010, the Senior Secured Notes had an outstanding balance (net of unamortized discount) of $209,324 and $207,378, respectively. ARKS is utilizing the effective interest method to amortize the original issue discount over the life of the Senior Secured Notes.
(e)
Retail Credit Facilities
Alon Brands Term Loans. In March 2011, Alon Brands issued $30,000 five-year unsecured notes (the "Alon Brands Term Loans") to a group of investors including certain shareholders of Alon Israel and their affiliates. The notes will mature in March 2016. The group of investors have the right to request that principal payments of the loan will be paid in four equal, consecutive annual payments, starting in March 2013. Otherwise, the principal amount will be paid at the maturity date in March 2016. During the third quarter of 2011, certain shareholders of Alon Israel assigned $6,000 of the Alon Brands Term Loans to Alon Israel.
Borrowings under the Alon Brands Term Loans bear interest at a rate of 7% per annum, payable on a semi-annual basis, provided that the interest rate will increase to 9% per annum solely with respect to the portion of the loan equal to the unexercised portion of the warrants described below.
The Alon Brands Term Loans contain certain restrictive covenants, including maintenance financial covenants.
In conjunction with the issuance of the Alon Brands Term Loans, we issued 3,092,783 warrants to purchase shares of our common stock at an initial exercise price per share of $9.70. The warrants are exercisable in whole or in part until March 2016, five years from the date of issuance. The allocated fair value of the warrants was $10,988 and was recorded as additional paid-in capital at the time of issuance.
At December 31, 2011, the Alon Brands Term Loans had an outstanding balance of $20,116 (net of unamortized discount of $9,884). We are utilizing the effective interest method to amortize the discount over the five-year life of the Alon Brands Term Loans and have amortized $1,104 to interest expense for the year ended December 31, 2011.
Term Credit Agreement. Southwest Convenience Stores, LLC (“SCS”) is party to a credit agreement (the “SCS Credit Agreement”) that, as amended, matures on December 30, 2015. On December 30, 2010, SCS entered into an amendment to the SCS Credit Agreement, which increased the amount outstanding from $73,361 (“SCS Refinancing Term Loan”) by $10,000 (“SCS Additional Term Loan”) and also included a revolving credit loan (“SCS Revolving Credit Loan”) with a maximum loan
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
amount of the lesser of the borrowing base or $10,000.
Borrowings under the SCS Refinancing Term Loan bear interest at a Eurodollar rate plus 2.00% per annum with principal payments made in quarterly installments based on a 15-year amortization schedule. Borrowings under the SCS Additional Term Loan bear interest at a Eurodollar rate plus 2.75% per annum with principal payments made in quarterly installments based on a 5-year amortization schedule. Borrowings under the SCS Revolving Credit Loan bear interest at a Eurodollar rate plus 2.75% per annum.
The obligations under the SCS Credit Agreement are secured by a pledge of substantially all of the assets of SCS and Skinny's, LLC and each of their subsidiaries, including cash, accounts receivable and inventory. The SCS Credit Agreement contains certain restrictive covenants including maintenance financial covenants.
At December 31, 2011 and 2010, the SCS Credit Agreement had an outstanding balance under the term loans of $76,470 and $83,361, respectively. At December 31, 2011 and 2010, the SCS Revolving Credit Loan had an outstanding balance of $10,000 and $10,000, respectively.
In March 2012, Alon issued $30,000 of preferred stock and repaid in full its obligations under the Alon Brands Term Loans. Also as part of the transaction, the warrants issued in conjunction with the Alon Brands Term Loans were surrendered back to Alon.
(f)
Other Retail Related Credit Facilities
In 2003, Alon obtained $1,545 in mortgage loans to finance the acquisition of new retail locations. The interest rates on these loans ranged between 5.5% and 9.7%, with 5 to 15 year payment terms. At December 31, 2011 and 2010, the outstanding balances were $695 and $696, respectively.
(g)
Financial Covenants
Alon has certain credit facilities that contain restrictive covenants, including maintenance financial covenants. At December 31, 2011, Alon was in compliance with these covenants.
(h)
Maturity of Long-Term Debt
The aggregate scheduled maturities of long-term debt for each of the five years subsequent to December 31, 2011 are as follows: 2012 - $119,874 ; 2013 - $632,597; 2014 - $221,134; 2015 - $70,722; 2016 - $5,660 and thereafter - $209.
(i)
Interest and Financing Expense
Interest and financing expense included the following:
(14)
Stockholders' Equity
(a)
Common stock (share value in dollars)
The authorized capital stock of Alon consists of 100,000,000 shares of common stock, $0.01 par value, and 10,000,000 shares of convertible preferred stock, $0.01 par value. Issued and outstanding shares of common stock were 56,107,986 and 54,281,636 as of December 31, 2011 and 2010, respectively.
Standby Equity Distribution Agreement. In January 2011, Alon entered into a Standby Equity Distribution Agreement (the "SEDA”) with YA Global Master SPV Ltd. ("YA Global”) to purchase up to $25,000 of Alon USA Energy, Inc. common stock ("Common Stock"). At any time during the effective period of the agreement, Alon may require YA Global to purchase shares of Common Stock by delivering an advance notice (as provided for in the SEDA) to YA Global. The purchase price of the Common Stock is 98.5% of the market price during the five consecutive trading days after the receipt of the advance notice is
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
provided to YA Global. In no event shall the number of shares of Common Stock owned by YA Global and its affiliates exceed 4.99% of the outstanding Common Stock at that time. The SEDA automatically terminates in January 2013. During 2011, Alon sold Common Stock with total proceeds of $11,900.
Warrants. In conjunction with the issuance of the Alon Brands Term Loans, Alon issued 3,092,783 warrants to purchase shares of Alon USA Energy, Inc. common stock at an initial exercise price per share of $9.70. The warrants are exercisable in whole or in part until March 2016, five years from the date of issuance.
Amended Shareholder Agreement. In 2011, an agreement was reached with one of the participants of the 2000 Incentive Stock Compensation Plan whereby the participant would exchange 2,019 shares of common stock of Alon Assets, Inc. (“Alon Assets”) and 758 shares of Alon USA Operating, Inc. (“Alon Operating”) for 377,710 shares of common stock of Alon USA Energy, Inc. One-third of the shares were exchanged in October 2011 and the remaining two-thirds will be exchanged equally in October 2012 and October 2013.
For the years ended December 31, 2011, 2010 and 2009, activity in the number of common stock was as follows:
(b)
Preferred stock (share value in dollars)
In October 2010, Alon completed a registered direct offering of Alon's 8.5% Series A Convertible Preferred Stock (the “Preferred Stock”) for an aggregate offering price of $40,000 less offering expenses, of which Alon Israel purchased $35,000. The holders of the Preferred Stock can convert, at the holder's option, the Preferred Stock into Alon's common stock based on an initial conversion price of $6.74 per share of Alon's common stock, in each case subject to adjustments. The Preferred Stock may be redeemed at Alon's option after October 28, 2017. If all of the Preferred Stock were to be converted into Alon's common stock based on the initial conversion price, then 5,934,800 shares of Alon's common stock would be issued. Issued and outstanding shares of convertible preferred stock were 4,000,000 shares as of December 31, 2011 and 2010.
(c)
Dividends
Common Stock Dividends. Alon paid regular quarterly cash dividends of $0.04 per share on Alon's common stock in 2011 on each of the following dates: March 15, 2011; June 15, 2011; September 15, 2011; and December 15, 2011. Additionally, the non-controlling interest stockholders of Alon Assets and Alon Operating received aggregate cash dividends of $704.
Alon paid regular quarterly cash dividends of $0.04 per share on Alon's common stock in 2010 on each of the following dates: March 31, 2010; June 15, 2010; September 15, 2010; and December 15, 2010. Additionally, the non-controlling interest stockholders of Alon Assets and Alon Operating received aggregate cash dividends of $593.
In 2009, Alon paid regular quarterly cash dividends of $0.04 per share on Alon's common stock on each of the following dates: April 2, 2009; June 15, 2009; September 15, 2009; and December 15, 2009. Additionally, the non-controlling interest stockholders of Alon Assets and Alon Operating received aggregate cash dividends of $576.
Preferred Stock Dividends. Alon issued 328,000 and 101,000 shares in aggregate of common stock for payment of the
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
quarterly 8.5% preferred stock dividend to preferred stockholders for the years ended December 31, 2011 and 2010, respectively.
(15)
Stock-Based Compensation
Alon has two employee incentive compensation plans, (i) the Amended and Restated 2005 Incentive Compensation Plan and (ii) the 2000 Incentive Stock Compensation Plan.
(a)
Amended and Restated 2005 Incentive Compensation Plan (share value in dollars)
Alon’s original incentive compensation plan, the Alon USA Energy, Inc. 2005 Incentive Compensation Plan, was approved by its stockholders in 2006. In May 2010, Alon’s stockholders approved an amended and restated incentive compensation plan, the Alon USA Energy, Inc. Amended and Restated 2005 Incentive Compensation Plan ("the Plan"), which is a component of Alon’s overall executive incentive compensation program. The Plan permits the granting of awards in the form of options to purchase common stock, Stock Appreciation Rights (“SARs”), restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses to Alon’s directors, officers and key employees.
Restricted Stock. Non-employee directors are awarded an annual grant of $25 in shares of restricted stock. The restricted shares granted to the non-employee directors vest over a period of three years, assuming continued service at vesting.
In May 2011, Alon granted awards of 180,000 restricted shares to certain executive officers at a grant date price of $13.53. These May 2011 restricted shares will vest as follows: 50% on May 10, 2012 and 50% on May 10, 2016, assuming continued service at vesting.
Compensation expense for the restricted stock grants amounted to $1,054, $75 and $75 for the years ended December 31, 2011, 2010 and 2009, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.
The following table summarizes the restricted share activity from January 1, 2010:
As of December 31, 2011, there was $1,519 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 2.3 years. The fair value of shares vested in 2011 was $88.
Restricted Stock Units. In May 2011, Alon granted 500,000 restricted stock units to the CEO and President of Alon at a grant date fair value of $11.47. Each restricted unit represents the right to receive one share of Alon common stock upon the vesting of the restricted stock unit. All 500,000 restricted stock units vest on March 1, 2015, assuming continued service at vesting. Compensation expense for the restricted stock units amounted to $997 for the year ended December 31, 2011 and is included in selling, general and administrative expenses in the consolidated statements of operations.
Stock Appreciation Rights. In March 2007, Alon granted awards of 361,665 SARs to certain officers and key employees at a grant price equal to $28.46. The March 2007 SARs are fully vested as of December 31, 2011 and are exercisable during the three-year period following each of the vesting dates.
In July 2008, Alon granted awards of 12,000 SARs to certain employees at the close of the Krotz Springs refinery
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
acquisition at a grant price equal to $14.23. The July 2008 SARs are 75% vested as of December 31, 2011 with the remaining 25% vesting on July 1, 2012 and are exercisable during the 365-day period following the date of vesting.
In December 2008, Alon granted an award of 10,000 SARs at a grant price equal to $14.23. The December 2008 SARs are 50% vested as of December 31, 2011 with vesting of 25% on December 1, 2012 and 25% on December 1, 2013 and are exercisable during the 365-day period following the date of vesting.
In January 2010, Alon granted awards of 177,250 SARs to certain officers and key employees at a grant price equal to $16.00. The January 2010 SARs are 50% vested as of December 31, 2011 with vesting of 25% on December 10, 2012 and 25% on December 10, 2013 and are exercisable during the 365-day period following the date of vesting.
In March 2010, Alon granted awards of 10,000 SARs at a grant price equal to $16.00 and 10,000 SARs at a grant price equal to $10.00 to an executive officer. The March 2010 SARs vest as follows: 50% on March 1, 2012, 25% on March 1, 2013 and 25% on March 1, 2014 and are exercisable during the 365-day period following the date of vesting.
In January 2011, Alon granted awards of 18,250 SARs to certain officers and key employees at a grant price equal to $16.00. The January 2011 SARs vest as follows: 50% on January 5, 2013, 25% on January 5, 2014, and 25% on January 5, 2015, and are exercisable during the 365-day period following the date of vesting.
When exercised, all SARs are convertible into shares of Alon common stock, the number of shares will be determined at the time of exercise by calculating the difference between the closing price of Alon common stock on the exercise date and the grant price of the SARs (the “Spread”), multiplying the Spread by the number of SARs being exercised and then dividing the product by the closing price of Alon common stock on the exercise date.
Compensation expense for the SARs grants amounted to $336, $500 and $479 for the years ended December 31, 2011, 2010 and 2009, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.
(b)
2000 Incentive Stock Compensation Plan
On August 1, 2000, Alon Assets and Alon Operating, majority owned, consolidated subsidiaries of Alon, adopted the 2000 Incentive Stock Compensation Plan pursuant to which Alon’s board of directors may grant stock options to certain officers and members of executive management. The 2000 Incentive Stock Compensation Plan authorized grants of options to purchase up to 16,154 shares of common stock of Alon Assets and 6,066 shares of common stock of Alon Operating. This plan was closed to new participants subsequent to August 1, 2000, the initial grant date. As of December 31, 2011, all stock options issued under the 2000 Incentive Stock Compensation Plan have been exercised. Total compensation expense (benefit) recognized under this plan was $0, $4 and $(52) for the years ended December 31, 2011, 2010 and 2009, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.
In addition, compensation expense of $542 associated with the difference in value between the participants ownership of Alon Assets and Alon Operating stock compared to Alon USA Energy, Inc. stock was recognized for the year ended December 31, 2011 and is included in selling, general and administrative expenses in the consolidated statements of operations.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
The following table summarizes the stock option activity for Alon Assets and Alon Operating for the years ended December 31, 2011 and 2010:
The intrinsic value of total options exercised in 2011 was $471.
(16)
Income Taxes
Income tax expense (benefit) included the following:
A reconciliation between the income tax expense (benefit) computed on pretax income (loss) at the statutory federal rate and the actual provision for income tax expense (benefit) is as follows:
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
The following table sets forth the tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of taxable income and projections for future taxable income, over the periods which the deferred tax assets are deductible, management believes it is more likely than not that Alon will realize the benefits of these deductible differences in future periods.
At December 31, 2011, Alon has net operating loss carryforwards for Federal income tax purposes of $212,217 which are available to offset future Federal taxable income through 2031. In addition, Alon has net operating loss carryforwards for state and local income tax purposes of $455,689 which are available to offset future state taxable income in various years through 2031.
Alon has elected to recognize interest expense related to the underpayment of income taxes in interest expense, and penalties relating to underpayment of income taxes as a reduction to other income, net, in the consolidated statements of operations. Alon is subject to U.S. federal income tax, and income tax in multiple state jurisdictions with California, Texas, and Louisiana comprising the majority of the Company's state income tax. The federal tax years 2000 to 2005 are closed to audit. The federal tax years 2006 through 2009 have been audited by the IRS, but the statute remains open for all years. In general, the state tax years open to audit range from 2006 to 2010. Alon's liability for unrecognized tax benefits and accrued interest did not increase during the year ended December 31, 2011, as there were no unrecognized tax benefits recorded in 2011.
(17)
Earnings (Loss) Per Share
Basic earnings (loss) per share is calculated as net income (loss) available to common stockholders divided by the average number of participating shares of common stock outstanding. Diluted earnings (loss) per share include the dilutive effect of SARs using the treasury stock method and the dilutive effect of convertible preferred shares, warrants and granted restricted stock units using the if-converted method.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
The calculation of earnings (loss) per share, basic and diluted, for the years ended December 31, 2011, 2010 and 2009, is as follows:
(18)
Related Party Transactions
(a)Alon Brands Term Loans
In March 2011, Alon Brands issued $12,000 five-year unsecured notes to certain shareholders of Alon Israel and their affiliates as part of the Alon Brands Term Loans. The Alon Brands Term Loans will mature in March 2016. The shareholders have the right to request that principal payments of the loan will be paid in four equal, consecutive annual payments, starting in March 2013. Otherwise, the principal amount will be paid at the maturity date in March 2016. During the third quarter of 2011, these shareholders assigned $6,000 of the Alon Brands Term Loans to Alon Israel.
Borrowings under the Alon Brands Term Loans bear interest at a rate of 7% per annum, payable on a semi-annual basis, provided that the interest rate will increase to 9% per annum solely with respect to the portion of the loan equal to the unexercised portion of the warrants described below.
In conjunction with the issuance of the Alon Brands Term Loans, Alon issued to certain shareholders of Alon Israel 1,237,113 warrants to purchase shares of Alon USA Energy, Inc. common stock at an initial exercise price per share of $9.70. The warrants are exercisable in whole or in part until March 2016, five years from the date of issuance.
(b)Sale of ARL Preferred Shares
In connection with the acquisition of the Krotz Springs refinery, pursuant to a stock purchase agreement Alon Israel Oil Company, Ltd. (“Alon Israel”) provided letters of credit in the amount of $55,000 to support the borrowing base of ARKS and purchased shares of Series A Preferred Stock of Alon Refining Louisiana, Inc. for $80,000. Alon Israel issued an additional $25,000 of letters of credit in the first quarter of 2009 for the benefit of ARKS. In December 2009, Alon Israel's shares of Series A Preferred Stock were exchanged for 7,351,051 shares of Alon common stock. In connection with the termination of the ARKS revolving credit facility, Alon returned to Alon Israel $65,000 of letters of credit, leaving $15,000 of letters of credit. In the event that any letter of credit, provided by Alon Israel, is drawn upon by beneficiaries of a letter of credit, a promissory note will be issued in favor of Alon Israel for the amount of any such drawn letter of credit. This promissory note will provide that Alon Israel may exchange the promissory note for shares of Alon common stock.
(c)Letter of Credit Fee Agreement
In November 2010, Alon entered into a Letter of Credit Fee Agreement with Alon Israel whereby Alon Israel caused a bank to issue and deliver a $23,000 letter of credit in favor of Alon USA, LP, a subsidiary of Alon (“Alon LP”), to a supplier of Alon LP to support Alon LP's crude oil purchases. Pursuant to the Letter of Credit Fee Agreement, Alon agreed to pay a fee of 8.5% per annum of the outstanding letter of credit amount. The aforementioned letter of credit was returned to Alon Israel in October 2011 and the Letter of Credit Fee Agreement was terminated.
(d)Collateral Fee Agreement
In March 2010, Alon entered into a line letter with Israel Discount Bank of New York (“IDB”), pursuant to which IDB agreed to provide a line of credit to Alon in a maximum amount of $60,000. The collateral supporting the line of credit is currently comprised of a security interest in a $30,000 deposit account maintained at IDB by Alon Israel. In 2010, in consideration for maintaining the deposit at IDB as collateral under the line letter, Alon entered into a Collateral Fee Agreement with Alon Israel whereby it agreed to pay a fee to Alon Israel based upon a formula set forth in the agreement which includes, among other items, costs to Alon Israel associated with the deposit. Currently the fee is 6.0% per annum. The initial term of the Collateral Fee Agreement ended on December 31, 2010 and is automatically extended for six month terms thereafter unless
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
terminated by either party after the initial term with 30 days prior written notice.
(e)Sale of HEP Units
In January 2010, Alon sold 150,200 Holly Energy Partners ("HEP") Units to each of Dor-Alon Energy in Israel (1988) Ltd. and Alon Holdings Blue Square-Israel, Ltd., both affiliates of Alon Israel, and Alon also exchanged 287,258 HEP Units for auction rate securities held by Alon Israel (which were sold in March 2010 and no gain or loss was recognized). The HEP Units sold and exchanged were based on a price per unit based on the average closing price of HEP's publicly traded Class A limited partnership units for the 30 trading days preceding the closing of such transaction for a total of $22,760.
(f)Richmond Beach Property Sale
In April 2010, Alon entered into a Purchase and Sale Agreement with BSRE Point Wells, LP (“BSRE”), a subsidiary of Alon Holdings Blue Square-Israel, Ltd. to sell a parcel of land at Richmond Beach, Washington for $19,500. The sale of the land was completed in June 2010 and Alon deferred recognition of the gain on the sale of land of $5,539 as the land was sold to an affiliated entity. The deferred gain will be recognized at such time as the property is sold to a third party.
In conjunction with the sale, Alon entered into a development agreement with BSRE. The agreement provides that Alon and BSRE, in order to enhance the value of the land with a view towards maximizing the proceeds from its sale, intend to cooperate in the development and construction of a mixed-use residential and planned community real estate project on the land. As part of this agreement, Alon agreed to pay a quarterly development fee of $439, commencing in the third quarter of 2010, in exchange for the right to participate in the potential profits realized by BSRE from the development of the land.
(19)
Commitments and Contingencies
(a)
Leases
Alon has long-term lease commitments for land, office facilities, retail facilities and related equipment and various equipment and facilities used in the storage and transportation of refined products. Alon also has long-term lease commitments for land at its Krotz Springs refinery. In most cases Alon expects that in the normal course of business, Alon's leases will be renewed or replaced by other leases. Alon has commitments under long-term operating leases for certain buildings, land, equipment, and pipelines expiring at various dates over the next twenty years. Certain long-term operating leases relating to buildings, land and pipelines include options to renew for additional periods. At December 31, 2011, minimum lease payments on operating leases were as follows:
Total rental expense was $39,420, $42,762, and $42,883 for the years ended December 31, 2011, 2010, and 2009, respectively. Contingent rentals and subleases were not significant.
(b)
Commitments
In the normal course of business, Alon has long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by its refineries, terminals, pipelines and retail locations. Alon is also party to various refined product and crude oil supply and exchange agreements. These agreements are typically short-term in nature or provide terms for cancellation.
Alon has a pipelines and terminals agreement with HEP through February 2020 with three additional five year renewal terms exercisable at Alon's sole option. Pursuant to the pipelines and terminals agreement, Alon has committed to transport and store minimum volumes of refined products in these pipelines and terminals. The tariff rates applicable to the transportation of refined products on the pipelines are variable, with a base fee which is reduced for volumes exceeding defined volumetric targets. The agreement provides for the reduction of the minimum volume requirement under certain circumstances. The service fees for the storage of refined products in the terminals are initially set at rates competitive in the marketplace.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
Alon has a throughput and deficiency agreement with Sunoco Pipeline, LP, through February 2016 with an option to extend the agreement by four additional thirty-month periods. The throughput and deficiency agreement gives Alon transportation rights to ship a minimum of 15,000 bpd of crude oil on the Amdel and White Oil pipelines from the Gulf Coast and from Midland, Texas to the Big Spring refinery. In October 2011, the throughput and deficiency agreement was replaced with a new throughput and deficiency agreement (the “New Agreement”). The New Agreement gives Alon the option to transport crude oil through the Amdel Pipeline (1) either westbound from the Nederland Terminal to the Big Spring refinery, or (2) eastbound from the Big Spring refinery to the Nederland Terminal for further barge transportation to the Krotz Springs refinery. The minimum throughput commitment by Alon is 15,645 bpd. The agreement is for 5 years from the operational date as defined in the New Agreement with an option to extend the New Agreement by four additional thirty-month periods.
Alon has an arrangement with Centurion through June 2021. This arrangement gives Alon transportation pipeline capacity to ship a minimum of 21,500 bpd of crude oil from Midland to the Big Spring refinery using Centurion's approximately forty-mile long pipeline system from Midland to Roberts Junction and Alon's three-mile pipeline from Roberts Junction to the Big Spring refinery which Alon leases to Centurion.
Alon and Valero have an offtake agreement that provides for Valero to purchase, at market prices, light cycle oil and high sulfur distillate blendstock through July 2013.
In April 2010, ARKS entered into a Supply and Offtake Agreement, which was amended in May 2010 and March 2011 (the “ARKS Supply and Offtake Agreement”), with J. Aron, to support the operation of the refinery at a minimum of 72,000 barrels per day. Pursuant to the Supply and Offtake Agreement, (i) J. Aron agreed to sell to ARKS, and ARKS agreed to buy from J. Aron, at market price, crude oil for processing at the Krotz Springs refinery and (ii) ARKS agreed to sell, and J. Aron agreed to buy, at market price, certain refined products produced at the Krotz Springs refinery.
In connection with the execution of the ARKS Supply and Offtake Agreement, ARKS also entered into agreements that provided for the sale, at market price, of ARKS' crude oil and certain refined product inventories to J. Aron, the lease to J. Aron of crude oil and refined product storage tanks located at the Krotz Springs refinery, and an agreement to identify prospective purchasers of refined products on J. Aron's behalf. The Supply and Offtake Agreement has an initial term that expires on May 31, 2016. J. Aron may elect to terminate the agreement on May 31, 2013, May 31, 2014 or May 31, 2015 and ARKS may elect to terminate the agreement on May 31, 2015; provided that such election is given at least six months prior to any such election. Following expiration or termination of the ARKS Supply and Offtake Agreement, ARKS is obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Krotz Springs refinery at market price at that time.
In May 2010, ARKS entered into a secured Credit Agreement (the “Standby LC Facility”) by and between ARKS, as Borrower, and Goldman Sachs Bank USA, as Issuing Bank. The Standby LC Facility provides for up to $200,000 of letters of credit to be issued to J. Aron. Obligations under the Standby LC Facility are secured by a first priority lien on the existing and future accounts receivable and inventory of ARKS. At this time there is no further availability under the Standby LC Facility.
The Standby LC Facility includes customary events of default and restrictions on the activities of ARKS and its subsidiaries. The Standby LC Facility contains no maintenance financial covenants.
In February 2011, Alon entered into a Supply and Offtake Agreement (the “Alon Supply and Offtake Agreement”), with J. Aron. Pursuant to the Alon Supply and Offtake Agreement (i) J. Aron agreed to sell to Alon, and Alon agreed to buy from J. Aron, at market prices, crude oil for processing at the Big Spring refinery and (ii) Alon agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at the Big Spring refinery.
In connection with the execution of the Alon Supply and Offtake Agreement, Alon also entered into agreements that provided for the sale, at market prices, of Alon's crude oil and certain refined product inventories to J. Aron, the lease to J. Aron of crude oil and refined product storage tanks located at the Big Spring refinery, and an agreement to identify prospective purchasers of refined products on J. Aron’s behalf. The Alon Supply and Offtake Agreement has an initial term that expires in May 2016. J. Aron may elect to terminate the agreement prior to the initial term beginning in May 2013, provided Alon receives notice of termination at least six months prior to that date. Following expiration or termination of the Alon Supply and Offtake Agreement, Alon is obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Big Spring refinery.
(c)
Contingencies
Alon is involved in various other claims and legal actions arising in the ordinary course of business. In August 2011, Alon received from the Federal Trade Commission a civil investigative demand to provide documents as part of an industry-wide investigation related to petroleum industry practices and pricing. Alon believes the ultimate disposition of this and all other matters will not have a material effect on Alon’s financial position, results of operations or liquidity.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
(d)
Environmental
Alon is subject to federal, state, and local environmental laws and regulations. These rules regulate the discharge of materials into the environment and may require Alon to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites; to compensate others for damage to property and natural resources and for remediation and restoration costs. These possible obligations relate to sites owned by Alon and associated with past or present operations. Alon is currently participating in environmental investigations, assessments and cleanups under these regulations at refineries, service stations, pipelines and terminals. Alon may in the future be involved in additional environmental investigations, assessments and cleanups. The magnitude of future costs will depend on factors such as the unknown nature and contamination at many sites, the timing, extent and method of the remedial actions which may be required, and the determination of Alon’s liability in proportion to other responsible parties.
Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Substantially all amounts accrued are expected to be paid out over the next 15 years. The level of future expenditures for environmental remediation obligations cannot be determined with any degree of reliability.
Alon has an environmental agreement with HEP pursuant to which Alon agreed to indemnify HEP against costs and liabilities incurred by HEP to the extent resulting from the existence of environmental conditions at the pipelines or terminals prior to February 28, 2005 or from violations of environmental laws with respect to the pipelines and terminals occurring prior to February 28, 2005. Alon's environmental indemnification obligations under the environmental agreement expire after February 28, 2015. In addition, Alon's indemnity obligations are subject to HEP first incurring $100 of damages as a result of pre-existing environmental conditions or violations. Alon's environmental indemnity obligations are further limited to an aggregate indemnification amount of $20,000, including any amounts paid by Alon to HEP with respect to indemnification for breaches of Alon's representations and warranties under a contribution agreement. With respect to any remediation required for environmental conditions existing prior to February 28, 2005, Alon has the option under the environmental agreement to perform such remediation itself in lieu of indemnifying HEP for their costs of performing such remediation. Pursuant to this option, Alon is continuing to perform the ongoing remediation at the Wichita Falls terminal. Any remediation required under the terms of the environmental agreement is limited to the standards under the applicable environmental laws as in effect at February 28, 2005.
Alon has an environmental agreement with Sunoco pursuant to which Alon agreed to indemnify Sunoco against costs and liabilities incurred by Sunoco to the extent 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 March 1, 2006. With respect to any remediation required for environmental conditions existing prior to March 1, 2006, Alon has the option to perform such remediation itself in lieu of indemnifying Sunoco for their costs of performing such remediation.
Alon has accrued environmental remediation obligations of $65,463 ($6,292 current payable and $59,171 non-current liability) at December 31, 2011, and $69,006 ($7,349 current payable and $61,657 non-current liability) at December 31, 2010. The net environmental obligations (net of discount of $13,106) for which discounting were applied were $53,507. Those obligations were discounted at a rate of 4%. The aggregate gross disbursements for Alon's discounted environmental obligations for each of the five years subsequent to December 31, 2011 are as follows: 2012 - $4,173; 2013 - $4,150; 2014 - $4,129; 2015 - $4,059; 2016 - $3,949 and thereafter - $33,047.
In connection with the acquisition of the Bakersfield refinery on June 1, 2010, Alon entered into an indemnification agreement with a prior owner for remediation expenses of conditions that existed at the refinery on the acquisition date. Alon is required to make indemnification claims to the prior owner by March 15, 2015. Alon has recorded current receivables of $706 and $2,675 and non-current receivables of $15,719 and $14,386 at December 31, 2011 and 2010, respectively.
Alon has indemnification agreements with prior owners for part of the remediation expenses at certain West Coast assets. Alon has recorded current receivables of $1,893 and $1,323 and non-current receivables of $1,650 and $3,039 at December 31, 2011 and 2010, respectively.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(dollars in thousands, except as noted)
(20)
Quarterly Information (unaudited)
Selected financial data by quarter is set forth in the table below:
(21)
Subsequent Event
Dividend Declared
On February 2, 2012, Alon declared its regular quarterly cash dividend of $0.04 per share on Alon’s common stock, payable on March 15, 2012, to stockholders of record at the close of business on March 1, 2012.
Alon USA LP Credit Facility
In February 2012, the Alon USA LP Credit Facility maturity date was extended through March 2016.
Paramount Credit Facility
In March 2012, Alon repaid its obligations under the Paramount Credit Facility.
J. Aron Agreement
In February 2012, Alon signed an agreement with J. Aron for the supply of crude oil that will support the operation of the California refineries. The structure of this agreement is also expected to result in lower borrowing costs as Alon used the proceeds from the sale of inventories to repay approximately $57,000 of loans. Also, the structure will substantially reduce the need to issue letters of credit to support the California refineries crude oil purchases and allow Alon to make crude oil purchases without the constraint of increases in crude oil prices customary with a typical revolving credit facility.
Alon Brands Term Loans
In March 2012, Alon issued $30,000 of Series B convertible preferred stock with similar terms as Alon's Series A convertible preferred stock and repaid in full its obligations under the Alon Brands Term Loans. Also as part of the transaction, the warrants issued in conjunction with the Alon Brands Term Loans were surrendered back to Alon.
EXHIBITS
____________
*
Identifies management contracts and compensatory plans or arrangements.
†
Filed under confidential treatment request.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.