ITEM 1A. RISK FACTORS.
You should be aware that 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 us, you should consider carefully, among other things, the factors and the specific risks set forth below. This annual report 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 on the margin above fixed and variable expenses (including the cost of refinery feedstocks, such as crude oil) at which we are able to sell refined products. We enjoyed historically high refining margins throughout 2005. However, 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. Prices of crude oil, other feedstocks and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline and other refined products. 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 such as the Middle East, West Africa and Venezuela;
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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 U.S.;
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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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U.S. 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.
If the margin between refined product prices and crude oil and other feedstock prices contracts, it could negatively affect our earnings and profitability.
The nature of our business requires 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 LIFO inventory valuation methodology; therefore, 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.
In addition, the volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refinery and other operations affect our operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Future increases in fuel and utility prices may have a negative effect on our results of operations.
Our profitability is linked to the sweet/sour crude oil price spread, which increased significantly in 2005. A decrease in this spread could negatively affect our profitability.
Our profitability is linked to the price spread between sweet crude oil and sour crude oil, which we refer to as the sweet/sour spread. We prefer to refine sour crude oils because they have historically provided wider refining margins than sweet crude oils. During 2005, relatively high demand for sweet crude oils due to increasing demand for lower sulfur fuels resulted in a wider sweet/sour spread. However, a tightening of the sweet/sour spread could adversely affect our profitability, particularly if there is a worldwide softening of product demand that lessens the demand for sweet crude oils.
The dangers inherent in our operations could cause disruptions and could expose us to potentially significant losses, costs or liabilities. We are particularly vulnerable to disruptions in our operations because all of our refining operations are conducted at a single facility.
Our operations are subject to significant hazards and risks inherent in refining operations and in transporting and storing crude oil, intermediate products and refined products. These hazards and risks include, but are not limited to, natural disasters, fires, explosions, pipeline ruptures and spills, third party interference and mechanical failure of equipment at our or third-party facilities, any of which could result in production and distribution difficulties and disruptions, environmental pollution, personal injury or wrongful death claims and other damage to our properties and the properties of others.
Because all of our refining operations are conducted at a single refinery, any such events at our refinery could significantly disrupt our production and distribution of refined products, and any sustained disruption could have a material adverse effect on our business, financial condition 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 refinery receives substantially all of its crude oil and delivers a substantial percentage of its refined products through pipelines. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, 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, financial condition and results of operations.
In January 2006, we received notice from the operator of the Mesa Pipeline (“Mesa”) system, which currently supplies over 90% of our Big Spring refinery’s crude oil requirements, that operations of this system may cease on June 30, 2006 due to a dispute among the owners of the system. While we have begun to implement plans for alternative sources of supply should a shut down of this system occur, any disruption of supply resulting from a cessation of operations of the Mesa system could cause us to be unable to operate the Big Spring refinery at full capacity, which would negatively affect our profitability and cash flows.
If the price of crude oil increases significantly, it could limit our ability to purchase enough crude oil to operate our refinery at full capacity.
We rely in part on borrowings and letters of credit under our revolving credit facility to purchase crude oil for our refinery. If the price of crude oil increases significantly, we may not have sufficient capacity under our revolving credit facility to purchase enough crude oil to operate our refinery at full capacity. A failure to operate our refinery 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 Big Spring refinery at full capacity.
Changes in our credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms of their invoices with us. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our creditors 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 Big Spring refinery at full capacity. A failure to operate our refinery at full capacity could adversely affect our profitability and cash flows.
Covenants and events of default in our debt instruments could limit our ability to undertake certain types of transactions and adversely affect our liquidity.
Our revolving credit agreement dated February 15, 2006, contains negative and financial covenants and events of default that may limit our financial flexibility and ability to undertake certain types of transactions. For instance, we are subject to negative covenants that restrict our activities, including restrictions on creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, providing guaranties, engaging in different businesses, making loans and investments, entering into certain lease obligations, making certain capital expenditures, making certain dividend, debt and other restricted payments, in each case, based on certain financial covenants, compromising or adjusting receivables, engaging in certain transactions with affiliates and amending or waiving certain material agreements. We are also subject to financial covenants that require us to maintain specified financial ratios and to satisfy other financial tests. In addition, under our revolving credit facility, a change of control will be deemed to occur, if Alon Israel ceases to have the power to exercise, directly or indirectly, a controlling influence over our management or policies or cease to own and control at least 25% of the aggregate voting power represented by our outstanding capital stock. If we fail to satisfy the covenants set forth in our revolving credit facility or another event of default occurs under this facility, the maturity of the loan could be accelerated or we could be prohibited from borrowing for our working capital needs. If our borrowings are accelerated and we do not have sufficient cash on hand to pay all amounts due, we could be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all. If we cannot borrow under the revolving credit facility, we would need to seek additional financing, if available, or curtail our operations.
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 volatile market conditions, to compete on the basis of price and to obtain crude oil in times of shortage.
The Longhorn pipeline runs approximately 700 miles from the Houston area of the Gulf Coast to El Paso and has an estimated maximum capacity of 225,000 bpd. This pipeline provides Gulf Coast refiners and other shippers with improved access to markets in West Texas and New Mexico. We anticipate that any additional supply provided by this pipeline will lower prices and increase price volatility in the El Paso market and could adversely affect our sales and profitability in this market.
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, high-volume grocery and dry-goods retailers, such as Albertson’s, Wal-Mart and HEB 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 the retail segment. 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 sales and profitability.
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. We anticipate that compliance with new regulations lowering the permitted level of sulfur in gasoline and highway diesel fuel will require us to spend approximately $25.3 million through 2010. Actual costs could, however, significantly exceed current estimates, and we may be required to incur such costs at an earlier date than planned, particularly if we were to lose our small refiner status. 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.
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 earnings 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 refinery, terminals and convenience stores. Since August 2000, we have spent
approximately $12.3 million with respect to the investigation and remediation of our Big Spring refinery and our terminals. We anticipate spending an additional $4.7 million in investigation and remediation expenses over the next five years. There can be no assurances, however, that we will not have to spend more than this amount. 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 pursuant to the HEP transaction and two of our pipelines pursuant to the Sunoco transaction, 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 - 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 profitability.
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 earnings and cash flows.
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 45 days. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
We are exposed to risks associated with the credit-worthiness of our insurers.
The insurer under three of our environmental policies is The Kemper Insurance Companies, which has experienced significant downgrades of its credit ratings in recent years. Of these three policies, two are 20-year policies that were purchased to protect us against expenditures not covered by our indemnification agreement with FINA, and the third policy is a ten-year policy covering our operations subsequent to our acquisition from FINA. Our insurance brokers have advised us that environmental insurance policies with terms in excess of ten years are not currently generally available and that policies with shorter terms are available only at premiums substantially 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, only at substantially higher premiums than our current premiums with Kemper.
If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively impacted.
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 refining workforce is unionized, and we may face labor disruptions that would interfere with our operations.
As of December 31, 2005, we employed approximately 170 people at our refinery, approximately 120 of whom were covered by a collective bargaining agreement. The collective bargaining agreement expires March 31, 2006. We may not be able to renegotiate our collective bargaining agreement on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreement may not prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse affect on our results of operation and financial condition.
We conduct our convenience store business under a license agreement with 7-Eleven, and the loss of this license could adversely affect the results of operations of our retail segment.
All of our convenience store operations are currently conducted under the 7-Eleven name pursuant to a license agreement between 7-Eleven, Inc. and us. 7-Eleven may terminate the agreement if we default on our obligations under the agreement. This termination would result in our convenience stores losing the use of the 7-Eleven brand name, the accompanying 7-Eleven advertising and certain other brand names used exclusively by 7-Eleven. Termination of the license agreement could have a material adverse affect on our convenience store 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.
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 future
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.
If the price of crude oil increases significantly, it could reduce our profit on our fixed-price asphalt supply contracts.
We enter into fixed-price 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 profits 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.
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, the terms of their indebtedness, tax considerations and legal restrictions.
Three of our executive officers, Messrs. Morris, Hart and Concienne, own shares of non-voting stock of two of our subsidiaries, Alon Assets, Inc., or Alon Assets and Alon USA Operating, Inc., or Alon Operating. As of March 1, 2006, the shares owned by these executive officers represent 5.32% of the aggregate equity interest in these subsidiaries. In addition, these executive officers hold options vesting through 2010 which, if exercised, could increase their aggregate ownership to 8.34% of Alon Assets and Alon Operating. 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 Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”
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 Owners and Management and Related Stockholder Matters.”
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 outside the United States. 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a stockholder vote during the third and fourth quarter of 2005.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASE 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 since our common stock began trading on the New York Stock Exchange on July 28, 2005:
Holders
As of March 1, 2006, there were approximately 26 common stockholders of record.
Dividends
Except with respect to the dividend of approximately $68.4 million paid on August 2, 2005 to our stockholders of record prior to our initial public offering, and the dividend of approximately $4.7 million paid on August 2, 2005 to the minority interest stockholders of record of Alon Operating, we have not paid dividends on our common stock. On February 15, 2006, our Board of Directors announced a regular quarterly cash dividend of $0.04 per share and a special cash dividend of $0.37 per share of our common stock, payable on March 21, 2006 to stockholders of record at the close of business on March 1, 2006. In connection with our cash dividend payment to shareholders on March 21, 2006, the minority interest owners of Alon Assets and Alon Operating will receive an aggregate cash dividend of approximately $1.1 million. We intend to continue to pay quarterly cash dividends on our common stock at an initial annual rate of $0.16 per share. The declaration and payment of future dividends to holders of our common stock will be at the discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, legal requirements, restrictions in our debt agreements and other factors our board of directors deems relevant.
Recent Sales of Unregistered Securities
None.
Use of Proceeds from Registered Securities
On July 27, 2005, the SEC declared effective our registration statements on Form S-1 (Registration Nos. 333-124797 and 333-126952) related to our sale of 11,730,000 shares of our common stock. On August 2, 2005, we completed an initial public offering of all 11,730,000 registered shares at a price of $16.00 per share for an aggregate offering price of approximately $187.7 million. Of the aggregate gross proceeds, approximately $2.4 million was used to pay offering expenses related to the initial public offering, and $13.1 million was used to pay underwriting discounts and commissions. None of the expenses incurred and paid by us in this offering were direct or indirect payments (i) to our directors, officers, general partners or their associates, (ii) to persons owning 10% or more of any class of our equity securities, or (iii) to our affiliates. Net proceeds of the offering after payment of expenses and underwriting discounts and commission were approximately $172.2 million.
The offering was made through an underwriting syndicate led by Credit Suisse, LLC., Deutsche Bank Securities Inc. and Lehman Brothers Inc. as joint book-running managers.
We used the net proceeds from the offering as follows:
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payment of a dividend in the amount of approximately $65.7 million to Alon Israel, a stockholder of the Company;
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payment of a dividend in the amount of approximately $2.7 million to Tabris Investments Inc., a stockholder of the Company;
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payment of a dividend in the amount of approximately $4.7 million to the minority stockholders of Alon USA Operating, Inc., a subsidiary of the Company;
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approximately $20.7 million was used to repay debt due to our parent company, Alon Israel, and $3.6 million was used to repay debt due to Atofina Petrochemicals, Inc.
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approximately $2.5 million was used for general corporate purposes; and
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the remaining $72.3 million, along with $31.6 million of cash from operating activities was used to prepay our $100.0 million secured term loan, including prepayment premiums and accrued interest.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
None.
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 cash flows data for the two years ended December 31, 2002 and 2001, and the selected consolidated balance sheet data as of December 31, 2003, 2002 and 2001, 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 cash flows data for the three years ended December 31, 2005, 2004 and 2003, and the selected consolidated balance sheet data as of December 31, 2005 and 2004, are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
We acquired our business, including a 34.4% interest in our retail subsidiary, Southwest Convenience Stores, LLC., or SCS, and a 60% interest in our subsidiary, Alon USA Capital, Inc., or Alon Capital effective August 1, 2000. We acquired the remaining 65.6% of SCS effective May 1, 2001. A portion of the financing for our acquisition of our business from FINA was in the form of the purchase by investors of 40% of the common stock of Alon Capital, which, through its subsidiaries, holds our refining and other operating assets. On August 21, 2002, we acquired this 40% interest in Alon Capital, which we refer to as the Alon Capital minority interest acquisition. As a result of these transactions, the financial and operating data for periods prior to the effective dates of these transactions may not be comparable to the data for periods after the effective dates of these transactions.
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 sweet/sour spread;
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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 of 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, casualty losses and other matters beyond our control; and
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the other factors discussed under Item 1A “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.
Overview
We are an independent refiner and marketer of petroleum products operating primarily in the Southwestern and South Central regions of the United States. Our business consists of two segments: (1) refining and marketing and (2) retail.
Refining and Marketing Segment. We own and operate a sophisticated sour crude oil refinery in Big Spring, Texas, with a crude oil throughput capacity of 70,000 bpd. We refine and market petroleum products, including gasoline, diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum products, primarily in the Southwestern and South Central regions of the United States.
We conduct the majority of our operations in West Texas, Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in this region as our physically integrated system because we supply our branded and unbranded distributors in this region with refined products produced at our Big Spring refinery and distributed through a network of product pipelines and terminals which we own or access through leases or long-term throughput agreements. We also operate in East Texas and Arkansas. We refer to our operations in this region as our non-integrated system because we supply our branded and unbranded distributors in this region with motor fuels obtained from third parties.
Retail Segment. As of December 31, 2005, we operated 167 convenience stores in West Texas and New Mexico. Our convenience stores typically offer merchandise, food products and motor fuels under the 7-Eleven and FINA brand names. We supply our stores with substantially all of their motor fuel needs with gasoline and diesel produced at our Big Spring refinery.
Summary of 2005 Developments
In February 2005, we completed the contribution of certain of our pipeline and terminal assets to HEP. In exchange for this contribution we received $120 million in cash and 937,500 subordinated Class B limited partnership units in HEP. Simultaneously with this transaction, we entered into a Pipelines and Terminal Agreement with HEP with an initial term of 15 years and three subsequent five year renewal terms exercisable at our sole discretion. Pursuant to the Pipelines and Terminal Agreement, we have agreed to transport and store minimum volumes of refined products in these pipelines and terminals and to pay specified tariffs and fees for such transportation and storage during the term of the agreement.
In March 2005, we successfully completed a major turnaround at our Big Spring refinery. Other than the planned low sulfur diesel project scheduled for the second quarter 2006, we believe the completion of this project will enable us to operate our Big Spring refinery without significant planned maintenance shut downs for the next four to five years. In connection with this turnaround, we expanded our crude oil throughput capacity from 62,000 bpd to 70,000 bpd. The cost of the expansion project was approximately $6.4 million, or $800 per bpd of additional throughput capacity.
On August 2, 2005, we completed an initial public offering of 11,730,000 shares of our common stock at a price of $16.00 per share for an aggregate offering price of approximately $187.7 million. We received approximately $172.2 million in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15.5 million or $1.32 per share. The initial public offering represented the sale by us of a 25.1% interest in our company. See “- Liquidity and Capital Resources” and “- Initial Public Offering” below for additional information.
2005 continued to reflect the positive refinery fundamentals experienced in 2004. These positive fundamentals, including strong refining margins and favorable differentials between WTI and WTS crude oil, resulted in significantly enhanced results of operations reported in 2005 compared to 2004. The effects of the favorable refining margins and WTI/WTS crude oil differentials were partially offset by decreased production in the third quarter of 2005 as a result of the acceleration of a reformer catalyst regeneration that was previously scheduled for January 2006. See “- Factors Affecting Comparability” for additional information. Results of our operations are further described under “- Results of Operations” and “- Liquidity and Capital Resources.” Selected financial data is presented below:
Major Influences on Results of Operations
Refining and Marketing. Our earnings and cash flow from our refining and marketing segment are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire 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 affects our earnings.
In order to measure our operating performance, we compare our per barrel refinery operating margin to certain industry benchmarks, specifically the Gulf Coast and Group III, or mid-continent, 3/2/1 crack spreads. A 3/2/1 crack spread in a given region 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 low-sulfur diesel and the market value of WTI crude oil. We calculate the Group III 3/2/1 crack spread using the market values of Group III conventional gasoline and low-sulfur diesel and the market value of WTI crude oil. The Gulf Coast and Group III crack spreads are proxies for the per barrel refinery operating margin that a crude oil refiner situated in the Gulf Coast and Group III region, respectively, would expect to earn if it refined WTI crude oil and sold conventional gasoline and low-sulfur diesel. We calculate our refinery operating margin by dividing the margin between net sales and cost of sales attributable to our refining and marketing segment, exclusive of net sales and cost of sales relating to our non-integrated system, by our Big Spring refinery’s throughput volumes. We exclude net sales and cost of sales relating to our non-integrated system from our refinery operating margin because the refined products we sell in this region are obtained from third-party suppliers and are not produced at our Big Spring refinery.
Our refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. In addition, we are able to access domestic and foreign crude oils available on the Gulf Coast through the Amdel pipeline, which enables us to better optimize our crude supply. As a result, our refinery operating margin generally exceeds the Gulf Coast 3/2/1 crack spread. Over the past two years our refinery operating margin exceeded the Group III 3/2/1 crack spread. The Group III market area has experienced product supply constraints in recent years due to insufficient pipeline capacity from the Gulf Coast to the Group III market area. The supply constraints have typically caused Group III products to be priced at a premium to Gulf Coast products, although in 2005, the Gulf Coast and Group III crack spread were comparable. 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 WTS crude oil. We refer to this differential as the sweet/sour spread. A widening of the sweet/sour spread can favorably influence our refinery operating margin.
The results of operations from our refining and marketing segment are also significantly affected by our Big Spring refinery’s operating costs, particularly the cost of natural gas used for fuel and the cost of electricity.
Natural gas prices have historically been volatile. For example, natural gas prices ranged between $5.79 and $15.38 per million British thermal units, or MMBTU, in 2005. Typically, electricity prices fluctuate with natural gas prices.
Demand for gasoline and asphalt products is generally higher during summer months than during winter months due to seasonal increases in highway traffic and road construction work. As a result, the operating results for our refining and marketing segment for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters. The effects of seasonal demand for gasoline and asphalt 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 refinery operations 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 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. Because crude oil and refined products are essentially commodities, 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.
Retail. Our earnings and cash flows from our retail segment are primarily affected by the sales and margins of retail merchandise and the sales volumes and margins of motor fuels at our convenience stores. The gross margin of our retail merchandise is retail merchandise sales less the delivered cost of the retail merchandise, net of vendor discounts, measured as a percentage of total retail merchandise sales. Our retail merchandise sales are driven by convenience, branding and competitive pricing. Motor fuel margin is sales less the delivered cost of fuel and motor fuel taxes, measured on a cents per gallon, or cpg, basis. Our motor fuel margins are driven by local supply, demand and competitor pricing. Our retail sales are seasonal and peak in the second and third quarters of the year, while the first and fourth quarters usually experience lower overall sales.
Outlook
We believe that we are well positioned to capitalize on the expected positive refining industry fundamentals in 2006. As a result of our 2005 crude oil capacity expansion at the Big Spring refinery, we plan to increase production in 2006. We plan to complete our ultra low-sulfur diesel upgrades to reduce the sulfur content in all of our diesel fuel products to 15 ppm in the second quarter of 2006. Our increased production capabilities and the conversion of all of our finished diesel fuel production to meet the required low-sulfur specifications is expected to allow us to fully participate in the anticipated positive refinery margin environment in 2006.
The positive refining industry fundamentals experienced in 2004 and 2005 have continued in the first two months of 2006. We expect that continued concern over adequate refining capacity to meet demand, tight product inventories as a result of heavy turnaround activity scheduled for the first half of 2006 and the widening of the sweet/sour crude oil differential will result in a favorable outlook for refining margins in 2006.
Our outlook for diesel margins is positive in 2006, due to high distillate demand and as a result of the EPA’s tightening of the diesel fuel specifications that take effect on June 1, 2006. We expect an industry-wide loss of finished diesel production as a result of refineries inability to convert current levels of diesel fuel production to low-sulfur diesel grades which meet the new specifications. In addition, low-sulfur diesel inventories are expected to drop due to scheduling and supply constraints during the transition period to meet low-sulfur diesel specifications in the pipelines, terminals and retail outlets. While diesel margins are expected to outpace gasoline margins, our outlook for gasoline margins is also favorable as demand is expected to exceed supply due to continued supply constraints related to, among other things, reduced gasoline production as a result of the elimination by Congress of MTBE in the gasoline pool and the seasonal shift to summer-grade gasoline in early March 2006.
The average sweet/sour crude oil differential for the first two months of 2006 was well above historical sweet/sour crude oil differentials. As sour crude oil has typically accounted for over 90% of our crude throughput, we believe our refinery margins will benefit from the continued widening of the sweet/sour differential. The higher sweet/sour differential in 2006 is primarily due to the continued increased demand for sweet crude oils due to low-sulfur specifications, higher incremental sour crude oil production and the expected introduction of low priced Canadian sour crude oil into the Midwest and Gulf Coast regions. Overall, we believe that we are well positioned to capitalize on the expected positive refining industry fundamentals and our expected favorable outlook for refined product margins and sweet/sour crude oil differentials.
Factors Affecting Comparability
Our financial condition and operating results over the three-year period ended December 31, 2005 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.
The contribution of assets in connection with the HEP transaction on February 28, 2005 reduced property, plant and equipment, net, by approximately $37.7 million.
Pursuant to our Pipelines and Terminals Agreement with HEP, we have agreed to transport and store minimum volumes of refined products in the pipelines and terminals contributed to HEP during the term of such agreement. Beginning March 1, 2005, tariff and terminalling fees associated with the Pipelines and Terminals Agreement are reflected as a component of cost of sales. In the periods prior to the HEP transaction, tariff and terminalling fees related to the contributed assets were eliminated through consolidation of our financial statements. As of March 1, 2005, the majority of all operating expenses related to the pipelines and terminals contributed to HEP are no longer incurred by us, resulting in an offsetting decrease in cost of sales. However, we anticipate that the additional tariff and terminalling fees will be greater than the operating expenses that we will no longer incur, resulting in a net increase to cost of sales. This net increase to cost of sales has the effect of reducing our refinery operating margin.
The HEP transaction was recorded as a partial sale for accounting purposes. We recognized pre-tax gain of $38.6 million in the ten-month period ending December 31, 2005 in connection with the transaction. This pre-tax gain includes $6.5 million of deferred gain, which was recognized in September 2005, as a result of events which permitted us to accelerate recognition of a portion of the deferred gain. We expect the remaining $63.9 million of deferred gain to be recognized between now and 2017. In addition, $6.7 million of pro-rata gain was subtracted from the carrying value of our investment in HEP in our consolidated balance sheet as a basis adjustment. See Note 4 of the consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
In the first quarter of 2005, we successfully completed a major turnaround at our Big Spring refinery. In connection with this turnaround, we expanded our crude oil throughput capacity from 62,000 bpd to 70,000 bpd. Our expanded crude oil processing capability should enable us to spread our fixed costs over a higher production base and, consequently, should lower our per barrel direct operating expense. In addition, the increased throughput capacity should result in increased production and higher sales volumes, which will affect the comparability of our future operating results to periods prior to the expansion. Our average refinery production was 64,393 bpd for 2005, reflecting effects of the crude oil throughput expansion, partially offset by reduced production resulting from the planned major turnaround completed in the first quarter of 2005. Average refinery production was 70,065 bpd for the last three quarters of 2005, compared to average production of 47,060 bpd for the first quarter of 2005. Average refinery production was 61,372 bpd for 2004.
Results of Operations
Net Sales. Net sales consist primarily of sales of refined petroleum products through our refining and marketing segment and sales of merchandise, including food products and motor fuels, through our retail segment.
For the refining and marketing segment, net sales consist of gross sales, net of customer rebates, discounts and excise taxes. Net sales for our refining and marketing segment include inter-segment sales to our retail segment, which are eliminated through consolidation of our financial statements. Retail net sales consist of gross merchandise sales, less rebates, commissions and discounts, and gross fuel sales, including motor fuel taxes. For our petroleum products, net sales are mainly affected by crude oil and refined product prices and volume changes caused by operations. Our merchandise sales are affected primarily by competition and seasonal influences.
Cost of Sales. Refining and marketing cost of sales includes crude oil and other raw materials, inclusive of 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 goods excludes depreciation and amortization expense.
Direct Operating Expenses. Direct operating expenses, all of which relate to our refining and marketing segment, include costs associated with the actual operations of our refinery, 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 segment corporate overhead and marketing expenses are also included in SG&A expenses.
Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for us and our two operating segments for the years ended December 31, 2005, 2004 and 2003. The summary financial data for our two 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.
ALON USA ENERGY, INC. CONSOLIDATED
REFINING AND MARKETING SEGMENT
(1)
Net sales include inter-segment sales to our retail segment at prices which approximate market price. These inter-segment sales are eliminated through consolidation of our financial statements.
(2)
Our buy/sell arrangements involve linked purchase and sales related to refined product contracts entered into to address location or grade requirements. Included in cost of sales are amounts which approximate the revenues resulting from these transactions. See Note 2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
(3)
Gain on disposition of assets reported in 2005 reflects the initial pre-tax gain recognized in connection with assets contributed in the February 28, 2005 HEP transaction and recognition of deferred gain recorded in the ten months following the transaction. The transaction was recorded as a partial sale for accounting purposes.
(4)
Non-integrated marketing sales volume represents refined products sales to our wholesale marketing customers located in our non-integrated region. The refined products we sell in this region are obtained from third-party suppliers. Non-integrated marketing margin represents the margin between net sales and cost of sales attributable to our non-integrated refined products sales volume expressed on a per barrel basis.
(5)
Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and costs of sales exclusive of depreciation and amortization expense, attributable to our refining and marketing segment, exclusive of net sales and cost of sales relating to our non-integrated system, by our Big Spring refinery’s throughput volumes. We exclude net sales and cost of sales from our non-integrated system because the refined products we sell in this system are not produced at our refinery. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margin to these crack spreads to assess our operating performance relative to other participants in our industry.
(6)
Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses, exclusive of depreciation and amortization expense, by our refinery throughput.
(7)
Total refinery throughput represents the aggregate volume of crude oil and blendstock used in the refinery production process.
(8)
Total refinery production represents the barrels per day of various finished products produced from processing crude and other refinery feedstocks through the crude units and other conversion units at our refinery.
(9)
2005 throughput reflects the effect of the downtime associated with the planned major turnaround in the first throughput of quarter 2005. Refinery throughput increased to an average of 70,419 bpd for the last three quarters of 2005, compared to average throughput of 47,447 bpd for the first quarter 2005. Refinery production increased to an average production of 70,065 bpd for the last three quarters of 2005, compared to average production of 47,060 bpd for the first quarter 2005.
(10)
Refinery utilization represents average daily crude oil throughput divided by crude capacity, excluding planned periods of downtime for maintenance and turnarounds.
RETAIL SEGMENT
(1)
Cost of sales includes inter-segment purchases of motor fuels from our refining and marketing segment at prices which approximate market prices. These inter-segment purchases are eliminated through consolidation of our financial statements.
(2)
Fuel margin represents the difference between motor fuel revenues and the net cost of purchased 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.
(3)
Fuel sales price per gallon represents the average sales price for motor fuels sold through our retail segment
(4)
Merchandise margin represents the difference between merchandise sales revenues and the delivered cost of merchandise purchases, net of rebates and commissions, expressed as a percentage of merchandise sales revenues. Merchandise margins, also referred to as in-store margins, are commonly used in the retail industry to measure in-store, or non-fuel, operating results.
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Net Sales
Consolidated. Net sales for 2005 were $2,328.5 million, compared to $1,707.6 million for 2004, an increase of $620.9 million or 36.4%. This increase was primarily due to higher than average refined product prices and increased refined product sales volume as a result of the completion of our 8,000 bpd throughput capacity expansion in the first quarter of 2005.
Refining and Marketing Segment. Net sales for our refining and marketing segment were $2,147.4 million for 2005, compared to $1,523.9 million for 2004, an increase of $623.5 million or 40.9%. The increase in net sales was primarily the result of significantly higher refined product prices in 2005 compared to 2004. The increase in refined product prices that we experienced was similar to the price increases experienced in the Gulf Coast markets. The average price of Gulf Coast gasoline in 2005 increased 42.4 cpg, or 36.4%, to 158.8 cpg, compared to 116.4 cpg in 2004. The average Gulf Coast diesel price in 2005 increased 56.6 cpg, or 51.0%, to 167.6 cpg compared to 111.0 cpg in 2004. Also contributing to the increase in sales revenues was an increase in sales volume. Our sales volume increased by 16.4 million gallons, or 1.2%, to 1,337.6 million gallons in 2005 compared to 1,321.2 million gallons in 2004. This increase in sales volume resulted primarily from the 8,000 bpd throughput capacity expansion completed in the first quarter of 2005, which resulted in average refinery production of 64,393 bpd in 2005 compared to 61,372 bpd in 2004, despite the effects of a reformer catalyst regeneration in September 2005 and the effects of the planned major turnaround in the first quarter 2005. Average refinery production increased to 70,065 bpd in the last three quarters of 2005, compared to average production of 47,060 bpd in the first quarter 2005.
Retail Segment. Net sales for our retail segment were $326.5 million for 2005 compared to $301.5 million for 2004, an increase of $25.0 million or 8.3%. This increase was primarily due to higher average retail fuel prices. Average retail fuel prices were $2.20 per gallon for 2005, compared to average retail fuel prices of $1.76 per gallon for 2004. Additionally, merchandise gross sales increased 2.5% to $133.3 million for 2005, compared to $130.1 million for 2004. This increase was partially offset by a decline in retail motor fuel sales volume. Our retail motor fuel sales volume decreased by 9.8 million gallons, or 10.1%, to 87.7 million gallons in 2005 compared to 97.5 million gallons in 2004. This decrease was due to competitive pressures from an increased presence of larger retailers in some of our retail markets.
Cost of Sales
Consolidated. Cost of sales was $1,990.3 million for 2005, compared to $1,470.0 million for 2004, an increase of $520.3 million or 35.4%. This increase resulted primarily from higher crude oil prices.
Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $1,866.5 million for 2005, compared to $1,342.4 million for 2004, an increase of $524.1 million or 39.0%. This increase was primarily due to significantly higher crude oil prices and the increase in refinery production in 2005 compared to 2004. The average price per barrel of WTS for 2005 increased $14.42 per barrel to $51.87 per barrel, compared to $37.45 per barrel for 2004, an increase of 38.5%. In addition, approximately $12.9 million of the increase in cost of sales related to transportation expense associated with the throughput agreement with HEP.
Retail Segment. Cost of sales for our retail segment was $269.2 million for 2005, compared to $245.3 million for 2004, an increase of $23.9 million or 9.7%. This increase was primarily attributable to higher motor fuel costs, partially offset by a decrease in fuel sales volume.
Direct Operating Expenses
Direct operating expenses were $93.8 million for 2005, compared to $75.7 million for 2004, an increase of $18.1 million or 23.9%. Of this increase, approximately $15.3 million was attributable to an increase in natural gas prices in 2005 compared to 2004. The average price of natural gas was $9.01 per MMBTU in 2005, compared to $6.19 per MMBTU in 2004, an increase of 45.6%. Overall energy usage also increased as a result of the 8,000 bpd throughput capacity expansion in the first quarter 2005. In addition, repairs and maintenance expense increased in 2005 as a result of routine maintenance projects that were completed in conjunction with the major turnaround completed in the first quarter of 2005 and in connection with the reformer catalyst regeneration performed in the third quarter 2005.
Selling, General and Administrative Expenses
Consolidated. SG&A expenses for 2005 were $73.2 million, compared to $73.6 million in 2004, a decrease of $0.4 million or 0.5%.
Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for 2005 were $22.9 million, compared to $23.7 million for 2004, a decrease of $0.8 million or 3.3%. This decrease was primarily due to a reduction of bad debt expense and professional fees.
Retail Segment. SG&A expenses for 2005 were $49.8 million, compared to $49.3 million for 2004, an increase of $0.5 million or 1.0%. This increase was primarily due to increased credit card brokerage fees as a result of the higher fuel prices, which were partially offset by decreased healthcare and workers compensation insurance costs.
Depreciation and Amortization
Depreciation and amortization for 2005 was $20.9 million, compared to $19.1 million for 2004, an increase of $1.8 million or 9.4%. This increase was primarily attributable to the completion of the various capital projects in late 2004 and the first half of 2005. Partially offsetting this increase was a reduction in depreciation due to the disposition of assets in the HEP transaction.
Operating Income
Consolidated. Operating income for 2005 was $188.8 million. Excluding $38.6 million of net gain on disposition of assets resulting from the HEP transaction, which management believes enhances period-to-period comparability, operating income for 2005 was $150.2 million, compared to $69.2 million (excluding the $0.2 million gain on disposition of assets) for 2004, an increase of $81.0 million or 117.1%. This increase was primarily attributable to higher operating income in our refining and marketing segment.
Refining and Marketing Segment. Operating income for our refining and marketing segment for 2005 was $188.2 million. Excluding $38.6 million of gain on disposition of assets resulting from the HEP transaction, operating income for 2005 was $149.6 million, compared to operating income for 2004 of $68.6 million, an increase of $81.0 million or 118.1%. This increase was primarily attributable to the increase in our refinery operating margins and increased sales volumes as a result of the 8,000 bpd crude oil throughput capacity expansion at our Big Spring refinery in the first quarter of 2005. Our refinery operating margin for 2005 increased $4.27 per barrel to $12.30 per barrel, compared to $8.03 per barrel in the 2004. This increase was attributable, in part, to higher differentials between refined product prices and crude oil prices as a result of decreases in finished product inventories, concern over adequate refining capacity to meet demand and continued year-on-year demand increases at above historical levels in the United States and abroad. The Gulf Coast 3/2/1 crack spread increased by $4.68 per barrel to an average of $11.45 per barrel in 2005 compared to an average of $6.77 per barrel in 2004, an increase of 69.1%. Also contributing to this increase was a widening of the sweet/sour spread. The average sweet/sour spread increased $.65 per barrel to $4.62 per barrel for 2005 compared to the average sweet/sour spread of $3.97 per barrel for 2004, an increase of 16.4%.
Retail Segment. Operating income for our retail segment was $2.9 million for 2005 and $2.7 million (excluding the $0.2 million gain on disposition of assets) for 2004. Our average retail motor fuel margin increased 2.0 cpg to 14.9 cpg in 2005, compared to 12.9 cpg in 2004, an increase of 15.5%. Partially offsetting this increase was a decrease in motor fuel sales volumes as a result of weaker demand in some markets due to the higher prices. The increase in gross merchandise sales were partially offset by a slight decrease in merchandise gross margin to 33.2% in 2005, compared to 33.5% in 2004.
Interest Expense
Interest expense was $19.3 million in 2005, compared to $23.7 million in 2004, a decrease of $4.4 million or 18.6%. Interest expense for 2005 reflects the repayment of $55.3 million of debt during 2005 and the significant reductions of borrowings under our revolving credit facility as a result of increases in cash from operating activities and funds received as a result of the HEP transaction in the first quarter 2005 and the completion of our initial public offering in the third quarter of 2005.
Income Tax Expense
Income tax expense was $65.5 million in 2005 compared to $18.3 million in 2004, an increase of $47.2 million. The increase in income tax expense was attributable to our increased 2005 taxable income compared to 2004. Our effective tax rate for 2005 was 37.4% and reflects the $1.1 million benefit of the Jobs Creation Act tax credit for 2005. Our effective tax rate was 39.8% for 2004.
Minority Interest In Income of Subsidiaries
Minority interest in income of subsidiaries represents the proportional share of net income related to non-voting common stock owned by minority shareholders in two of our subsidiaries, Alon Assets and Alon Operating. Minority interest in income of subsidiaries was $5.8 million for 2005, compared to $2.6 million for 2004, an increase of $3.2 million. This increase was attributable to our increased after-tax income in 2005 as a result of the factors discussed above. This increase was partially offset by a reduction in the minority interest ownership percentage to 4.8% in the third quarter of 2005 compared to 8.4% in 2004 as a result of the issuance of additional voting common stock by Alon Assets and Alon Operating in the third quarter of 2005 and the repurchase of shares of non-voting common stock by Alon Assets and Alon Operating in the first quarter of 2005.
Net Income
Net income was $104.0 million for 2005, compared to $25.1 million for 2004, an increase of $78.9 million or 314.3%. This increase was attributable to the factors discussed above.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Net Sales
Consolidated. Net sales for 2004 were $1,707.6 million, compared to $1,410.8 million for 2003, an increase of $296.8 million or 21.0%. This increase was primarily due to favorable market conditions resulting from higher refined product prices, partially offset by a decrease in sales volume.
Refining and Marketing Segment. Net sales for our refining and marketing segment were $1,523.9 million for 2004, compared to $1,225.0 million for 2003, an increase of $298.9 million or 24.4%. The increase in net sales was primarily the result of significantly higher refined product prices in 2004 compared to 2003. The average price of Gulf Coast gasoline in 2004 increased 29.5 cpg, or 34.0%, to 116.4 cpg, compared to 86.9 cpg in 2003. The average Gulf Coast diesel price in 2004 increased 28.8 cpg, or 35.0%, to 111.0 cpg compared to 82.2 cpg in 2003. The increase in net sales was partially offset by a 5.2%, or 72.4 million gallons, decrease in sales volumes in 2004 compared to 2003. This decrease was due, in part, to the non-renewal of several distributor supply contracts in our non-integrated system that expired in late 2003 and early 2004. The decrease was also due to reduced production resulting from unplanned downtime and repairs to our catalytic cracking unit as we neared the end of our major turnaround cycle.
Retail Segment. Net sales for our retail segment were $301.5 million for 2004 compared to $278.2 million for 2003, an increase of $23.3 million or 8.4%. This increase was primarily due to higher average retail fuel prices. Average retail fuel prices were $1.76 per gallon for 2004, compared to average retail fuel prices of $1.47 per gallon for 2003. This increase was partially offset by a decrease in fuel sales volume of 2.9 million gallons, or 3.0%, to 97.5 million gallons in 2004 as compared to 100.4 million gallons in 2003 and a decrease in merchandise sales. The decrease in fuel sales volume and merchandise sales was primarily related to closing three stores in 2004.
Cost of Sales
Consolidated. Cost of sales was $1,470.0 million for 2004, compared to $1,215.0 million for 2003, an increase of $255.0 million or 21.0%. This increase was primarily due to higher crude oil prices, partially offset by reduced crude oil purchases in 2004, due to slightly reduced crude throughput at our Big Spring refinery.
Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $1,342.4 million for 2004, compared to $1,084.2 million for 2003, an increase of $258.2 million or 23.8%. This increase was primarily due to significantly higher crude oil prices. The average price per barrel of WTS for 2004 increased $9.09
per barrel to $37.45 per barrel, compared to $28.36 per barrel for 2003, an increase of 32.1%. The increase in cost of sales was partially offset by a decline in our crude oil purchases as a result of reduced crude throughput at the Big Spring refinery.
Retail Segment. Cost of sales for our retail segment was $245.3 million for 2004, compared to $223.3 million for 2003, an increase of $22.0 million or 9.9%. This increase was primarily attributable to higher motor fuel costs, partially offset by a decrease in fuel sales volume as a result of closing three stores in 2004.
Direct Operating Expenses
Direct operating expenses were $75.7 million for 2004, compared to $66.1 million for 2003, an increase of $9.6 million or 14.5%. This increase was primarily attributable to increased energy costs resulting from higher natural gas prices. The average price of natural gas was $6.19 per MMBTU in 2004, compared to $5.50 per MMBTU in 2003, an increase of 12.5%. In addition, increased maintenance labor costs and maintenance expenditures contributed to the increase in direct operating expenses.
Selling, General and Administrative Expenses
Consolidated. SG&A expenses for 2004 were $73.6 million, compared to $69.1 million in 2003, an increase of $4.5 million or 6.5%. This increase was attributable to higher professional fees and employment related costs in our refining and marketing segment and higher insurance premiums and utility prices in our retail segment.
Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for 2004 were $23.7 million, compared to $20.1 million for 2003, an increase of $3.6 million or 17.9%. This increase was primarily attributable to higher legal and consulting fees and higher employee incentive awards.
Retail Segment. SG&A expenses for 2004 were $49.3 million, compared to $48.4 million for 2003, an increase of $0.9 million or 1.9%. This increase was primarily due to increased workers compensation insurance and health insurance costs.
Depreciation and Amortization
Depreciation and amortization for 2004 was $19.1 million, compared to $18.3 million for 2003, an increase of $0.8 million or 4.4%. This increase resulted from additions to property, plant and equipment as a result of capital expenditures in 2004 and a full year of depreciation associated with 2003 capital expenditures.
Operating Income
Consolidated. Operating income for 2004 was $69.4 million, compared to $42.3 million for 2003, an increase of $27.1 million or 64.1%. This increase was primarily attributable to higher operating income in our refining and marketing segment.
Refining and Marketing Segment. Operating income for our refining and marketing segment for 2004 was $68.6 million, compared to $42.0 million for 2003, an increase of $26.6 million or 63.3%. This increase was attributable to the significant increase in our refinery operating margins, partially offset by higher direct operating expenses and SG&A expenses. Our refinery operating margin increased $2.23 per barrel to $8.03 per barrel in 2004, compared to $5.80 per barrel in 2003. This increase was attributable, in part, to higher differentials between refined product prices and crude oil prices. The Gulf Coast 3/2/1 crack spread increased by 43.1% from an average of $4.73 per barrel in 2003 to an average of $6.77 per barrel in 2004. Also contributing to this increase was a widening of the sweet/sour spread which increased to an average of $3.97 per barrel in 2004 compared to $2.75 per barrel in 2003, an increase of 44.4%.
Retail Segment. Operating income for our retail segment was $2.9 million for 2004, compared to $2.4 million for 2003, an increase of $0.5 million or 20.8%. The increase in merchandise and motor fuel margins were partially offset by increased SG&A expenses. Our merchandise margin increased to 33.5% in 2004, compared to 33.0% in 2003. Our average retail motor fuel margin increased 1.0 cpg to 12.9 cpg in 2004, compared to 11.9 cpg in 2003, an increase of 8.4%.
Interest Expense
Interest expense was $23.7 million in 2004, compared to $16.3 million in 2003, an increase of $7.4 million or 45.4%. Interest expense for 2004 reflects a net increase of $34.7 million in outstanding term loan debt resulting from our incurrence of $100.0 million of indebtedness under our senior secured term loan in January 2004, as well as $0.7 million of non-cash debt issuance costs associated with this transaction and the application of the proceeds to repay our existing term debt. In addition, higher crude oil prices in 2004 compared to 2003 resulted in increased letter of credit fees relating to our crude oil purchases.
Income Tax Expense
Income tax expense was $18.3 million in 2004 compared to $9.1 million in 2003, an increase of $9.2 million. The increase in income tax expense was attributable to our increased 2004 taxable income compared to 2003. Our effective tax rate for 2004 was 39.8% as compared to 37.6% for 2003.
Minority Interest In Income of Subsidiaries
Minority interest in income of subsidiaries was $2.6 million for 2004, compared to $0.7 million for 2003, an increase of $1.9 million. This increase was primarily attributable to the increase in net income as a result of the factors discussed above and the issuance of additional stock under the Alon Assets and Alon Operating stock option plans.
Net Income
Net income was $25.1 million for 2004, compared to $14.1 million for 2003, an increase of $11.0 million or 78.0%. 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 and borrowings under our revolving credit facility. In addition, our liquidity was enhanced during the third quarter of 2005 by the receipt of $72.3 million net cash proceeds received from our initial public offering after the payment of commissions and expenses, debt prepayment, dividends to pre-offering stockholders, minority interest stockholders and general corporate expenditures. We believe that our cash on hand, cash flows from operating activities, borrowings under our revolving credit facility and other capital resources will be sufficient to satisfy the anticipated cash requirements associated with our existing operations 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. In addition, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors, including any expansion of our business that we complete.
Cash Flow
The following table sets forth our consolidated cash flows for the years ended December 31, 2005, 2004 and 2003:
Cash Flows Provided By Operating Activities
Net cash provided by operating activities for 2005 was $137.9 million, compared to net cash provided by operating activities of $76.7 million for 2004. The $61.2 million net increase in cash provided by operating
activities was primarily due to increased net income (excluding after-tax gains on dispositions of assets), resulting from higher refinery operating margins and increased refinery production as a result of the expansion of the Big Spring refinery crude oil capacity and the major turnaround in the first quarter of 2005. Working capital, net of cash and short-term investments, was $(46.1) million at December 31, 2005 compared to $(18.9) million at December 31, 2004, a decrease of $27.2 million. This decrease was primarily due to higher crude oil prices, products prices and increased sales volume.
Net cash provided by operating activities for 2004 was $76.7 million compared to net cash provided by operating activities of $76.2 million for 2003. Cash flow from operating activities for 2004 was primarily attributable to operating income of $69.4 million, resulting from higher refinery operating margins. Cash flow from operating activities for 2003 was primarily attributable to improved operating income of $42.3 million and an increase in trade payables due to the increase in crude oil prices. Working capital, net of cash, was $(18.9) million at December 31, 2004 compared to $(2.2) million at December 31, 2003, a decrease of $16.7 million. This decrease was primarily attributable to the net increase in trade payables as a result of higher crude prices in 2004, partially offset by increased accounts receivable balance resulting from higher product prices.
Net cash provided by operating activities for 2003 was $76.2 million. Cash flow from operating activities for 2003 was primarily attributable to operating income of $42.3 million and an increase in trade payables due to the increase in crude oil prices. Working capital, net of cash, decreased by $27.7 million, compared to $(2.2) million at December 31, 2003. This decrease was primarily attributable to reduced inventories from 2002 levels and an increase in trade payables as a result of higher crude oil prices.
Cash Flows Used In Investing Activities
Net cash used in investing activities increased to $107.0 million in 2005 from $39.9 million in 2004. This increase was primarily attributable to our $185.3 million investment in highly liquid short-term debt instruments and turnaround and chemical catalyst expenditures of $12.0 million due to the major turnaround in the first quarter of 2005, partially offset by the receipt of $118.0 of net cash proceeds in connection with the HEP transaction. Capital expenditures in 2005 totaled $23.0 million and included $12.1 million for regulatory and compliance projects, $1.8 million for the completion of our throughput capacity expansion project, $1.4 million for retail store automation and $7.7 million for various sustaining and capital improvement projects.
Net cash used in investing activities increased to $39.9 million in 2004 from $34.7 million during 2003. Our primary investments in 2004 included $10.0 million of deferred payment for the 2002 Alon Capital minority interest acquisition, $9.4 million for the acquisition of the Trust and River pipeline systems, $5.0 million for the initial phase of our Big Spring refinery’s throughput capacity expansion project, $4.0 million for EPA low-sulfur fuel projects, $2.3 million for chemical catalysts and turnaround preparations and $4.3 million for retail acquisitions and improvements. The remaining $4.9 million was spent on sustaining capital needs and growth opportunities, including the acquisition of our asphalt facility in Bakersfield, California.
Net cash used in investing activities totaled $34.7 million in 2003. Our primary investments in 2003 included $13.6 million for our low-sulfur gasoline project, $10.0 million of deferred payment for the 2002 Alon Capital minority interest acquisition and $4.1 million for the acquisition of three retail locations. The remaining $7.0 million was spent on sustaining capital needs and growth opportunities.
Cash Flows Provided By (Used In) Financing Activities
Net cash provided by financing activities was $42.5 million in 2005, compared to net cash provided by financing activities of $19.2 million in 2004. Cash provided by financing activities in 2005 included the net proceeds from our initial public offering on August 2, 2005 of $74.8 million after payment of commissions and expenses, debt prepayment, dividends to pre-offering stockholders and minority interest stockholders. In addition, cash used in financing activities during 2005 included additional debt reduction of $31.0 million.
Net cash provided by financing activities was $19.2 million in 2004, compared to net cash used in financing activities of $39.7 million in 2003. This difference was primarily attributable to the $100.0 million in new borrowings under our term loan in January 2004. Approximately $43.7 million of existing term debt and $21.6 million of borrowings under our revolving credit facilities were retired with the term loan proceeds.
Net cash used in financing activities in 2003 was $39.7 million. The use of cash in 2003 reflected the reduction in our net borrowings under our revolving credit facility due to increased operating income and decreased working capital needs.
Initial Public Offering
On August 2, 2005, we completed an initial public offering of 11,730,000 shares of our common stock at a price of $16.00 per share for an aggregate offering price of approximately $187.7 million. We received approximately $172.2 million in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15.5 million or $1.32 per share.
On August 2, 2005, we paid our stockholders of record prior to our initial public offering aggregate dividends of approximately $68.4 million, and the minority interest stockholders of Alon Operating were paid aggregate dividends of approximately $4.7 million. During August 2005, we utilized a portion of the proceeds from our initial public offering to repay the remaining $20.7 million of outstanding debt owed to our parent company, Alon Israel, and $3.6 million of outstanding debt owed to FINA. As of December 31, 2005, the remaining proceeds from the initial public offering were invested in various highly liquid, low-risk debt instruments with maturities of three months or less or low-risk debt instruments with maturities in excess of three months. On January 19, 2006, we used the remaining $72.3 million of the proceeds, along with cash from operating activities, to repay our $100.0 million term loan facility. See Item 5 “-Use of Proceeds from Registered Securities.”
Cash, Cash Equivalents and Short-Term Investment Position and Indebtedness
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 and are invested in conservative, highly rated instruments issued by financial institutions or government entities with strong credit standings. Short-term investments primarily consist of highly-rated auction rate securities (“ARS”). Although ARS may have long-term stated maturities, generally 10 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. ARS may be liquidated at par on the rate reset date, which is in intervals of seven to 49 days, depending on the terms of the security. These securities are carried at cost, which approximates market value. As of December 31, 2005, our total cash and cash equivalents were $136.8 million, our short-term investments were $185.3 million and we had total debt of approximately $132.4 million. On January 19, 2006, we used cash of approximately $103.9 million to repay our term loan, including a $3.0 million prepayment premium and $0.9 million accrued interest.
Summary of Indebtedness. The following table sets forth the principal amounts outstanding under our bank credit facilities, retail mortgages and equipment loans at December 31, 2005:
Revolving Credit Facility. We entered into a revolving credit facility on July 31, 2000, which was amended and restated on January 14, 2004 and further amended and restated on February 15, 2006. The Israel Discount Bank of New York, or Israel Discount Bank, acts as agent administrative agent, co-arranger, collateral agent and lender and Bank Leumi act as co-arranger and lender under the revolving credit facility. The initial size of the revolving credit facility is $160.0 million with options to increase the size of the facility to $240.0 million upon the increase of crude oil prices or an increase in our throughput capacity. Prior to the amendment, the amount available under the previous revolving credit facility was $141.6 million.
Borrowing availability under the revolving credit facility is limited at any time to the lower of the total current size of the revolving credit facility at that time, which is initially $160.0 million, or the amount of the
borrowing base under the revolving credit agreement. As of December 31, 2005, the borrowing base under the revolving credit facility was $337.8 million. The entire revolving credit facility is available in the form of letters of credit, and of revolving loans. The borrowings under the revolving credit facility bear interest at the Eurodollar rate plus 1.50% per annum. The revolving credit facility is jointly and severally guaranteed by all of our subsidiaries except for our retail subsidiaries. The revolving credit facility is secured by cash, accounts receivable, inventory and related assets. All fixed assets previously securing the facility were released in conjunction with the amendment of the facility on February 15, 2006.
Our revolving credit facility contains restrictive covenants, such as restrictions on change of control, creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, giving guaranties, engaging in different businesses, making loans and investments, entering into certain lease obligations, making certain capital expenditures and making certain dividend, debt and other restricted payments, however, these covenants do not restrict our activities so long as we maintain the financial covenants described below, on a pro-forma basis after giving effect to these activities. Our revolving credit facility also contains covenants that restrict us from compromising or adjusting receivables, engaging in certain transactions with affiliates and amending or waiving certain material agreements. The revolving credit facility contains financial covenants requiring Alon USA to maintain:
Compliance with these covenants is determined in the manner specified in the documentation governing the revolving credit facility. Consolidated EBITDA under our revolving credit facility represents net income plus minority interest, income tax expense, interest expense, depreciation and amortization and is measured each quarter on a rolling twelve-month basis. This calculation of consolidated EBITDA differs from the calculation of Adjusted EBITDA presented elsewhere in this Annual Report on Form 10-K. As of December 31, 2005, we were in compliance with all of these covenants.
Under our revolving credit facility, a change of control will be deemed to occur, if Alon Israel ceases to have the power to exercise, directly or indirectly, a controlling influence over our management or policies or ceases to own and control at lease 25% of the aggregate voting power represented by our outstanding capital stock.
The revolving credit facility expires on January 1, 2010. As of December 31, 2005 there were no borrowings outstanding and approximately $131.7 million of letters of credit outstanding under the revolving credit facility.
Term Loan. We entered into a term credit facility, or term facility, on December 16, 2003, which was amended and restated as of January 14, 2004, and further amended on February 10, 2005 and May 6, 2005. Credit Suisse was the administrative agent and collateral agent under the term facility. On January 19, 2006, we made a payment of approximately $103.9 million in satisfaction of all of our outstanding obligations under the term facility and terminated the term facility. Of this amount, $100.0 million represented a voluntary prepayment of the outstanding principal under the term facility, approximately $0.9 million represented accrued and unpaid interest on the principal balance and $3.0 million represented a prepayment premium. Borrowings under the term facility bore
interest, at our option, at either adjusted LIBOR plus 6.5% per annum, or at the alternate base rate plus 5.5% per annum, but not less than 10% per annum. We did not have the right to prepay outstanding principal amounts prior to January 17, 2006. Borrowings outstanding under the term facility would have matured on January 14, 2009.
Mortgage Loans and Equipment Loans. We entered into mortgage and equipment loan agreements with GE Capital Franchise Finance Corporation on October 1, 2002. Pursuant to these agreements, we formed two new retail finance subsidiaries, which received $22.3 million in mortgage loans and $12.7 million in equipment loans. The mortgage loans and equipment loans bear interest at a fixed rate of 8.06% per annum and 8.30% per annum, respectively. The loans are guaranteed by Alon USA and secured by liens on the properties and equipment owned by the retail finance subsidiaries. The loans contain representations and warranties, affirmative, negative and financial covenants and events of default that we believe are customary for financings of this kind. The mortgage loans are payable on a 20-year amortization schedule, and the equipment loans are payable on a ten-year amortization schedule. As of December 31, 2005, we had $30.6 million aggregate principal amount outstanding under the GE mortgage loans and equipment loans. In 2003 and 2004, we obtained $2.3 million in mortgage and equipment loans to finance the acquisition of new retail locations and equipment. The interest rates on these loans range from 5.5% to 9.7% with five to 15-year payment terms.
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 capital expenditure budgets, including expenditures for chemical catalyst and turnarounds, for 2006 and 2007 are $38.2 million and $42.7 million, respectively. The following table summarizes our expected capital expenditures for 2006 and 2007 by operating segment and major category:
Clean Air Capital Expenditures. We expect to spend approximately $25.3 million over the next five years to comply with the Federal Clean Air Act regulations requiring a reduction in sulfur content in gasoline and diesel fuels, including $9.9 million for low-sulfur diesel compliance in 2006.
As of December 31, 2005, we had completed substantially all of the expenditures required to meet regulatory requirements under the Voluntary Emission Reduction Permit program, or VERP, sponsored by the Texas Commission on Environmental Quality, or TCEQ, and for Maximum Achievable Control Technologies for petroleum refineries, or MACT II, which required additional air emission controls for certain processing units at our Big Spring refinery.
The estimated capital expenditures described above are summarized in the table below. If we were to lose our status as a small refiner, expenditures for the low-sulfur gasoline requirements would be accelerated.
Turnaround and Chemical Catalyst Costs. We completed a major turnaround on substantially all of our major processing units, including the crude unit and the fluid catalytic cracking unit, in the first quarter of 2005, at a cost of approximately $8.0 million. Chemical catalyst replacement costs associated with the turnaround were approximately $3.1 million. An additional $0.9 million was spent in the third quarter 2005 in connection with a reformer catalyst regeneration which had originally been scheduled for January 2006.
Between our major turnarounds, we also perform periodic scheduled turnaround projects on various units at our Big Spring refinery.
Contractual Obligations and Commercial Commitments
Information regarding our known contractual obligations of the types described below as of December 31, 2005 is set forth in the following table.
(a)
We repaid approximately $24.3 million of outstanding debt with a portion of the proceeds received from our initial public offering, of which $3.6 million was due within one year and $20.7 million was due within five years.
(b)
Includes $100.0 million of indebtedness owed under our term facility. We prepaid all amounts outstanding under the term facility in the first quarter of 2006.
(c)
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.
(d)
Other commitments include refinery maintenance services costs and management fees to our parent. These management fees were terminated in connection with our initial public offering for an aggregate payment of $6.0 million, of which $2.0 million was paid in August 2005 and the remaining $4.0 million was paid in January 2006.
As of December 31, 2005, we did not have any capital lease obligations or any agreements to purchase goods or services, other than those included in the table above, that were binding on us and that specified all significant terms.
Our “other non-current liabilities” are described in our consolidated financial statements included elsewhere in this in this Annual Report on Form 10-K. For most of these liabilities, timing of the payment of such liabilities is not fixed and therefore cannot be determined as of December 31, 2005. However, certain expected payments related to our anticipated pension contributions in 2006 and other post-retirement benefits obligations are discussed in Note 12 of our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
Off-Balance Sheet Arrangements
We have no 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 marketing 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 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. For example, in the second half of 2001, market prices were significantly lower than our inventory cost determined under our LIFO valuation method, which resulted in our recording a non-cash charge of $23.2 million to cost of sales and a corresponding decrease in the value of our crude oil and refined products inventory. In 2002, market prices rose substantially, allowing us to recover $18.6 million of the 2001 inventory write-down to market value with a corresponding non-cash credit to cost of sales. Any such recovery results in a non-cash accounting adjustment, increasing the value of our crude oil and refined products inventory and decreasing our cost of sales. Our results of operations could continue to include such non-cash write-downs and recoveries of inventory if market prices for crude oil and refined products return to levels comparable to those in 2001. A reduction of inventory volumes during 2005 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 $2.4 million in 2005. Market values of crude oil, refined products and blendstocks exceeded LIFO costs by $52.2 million at December 31, 2005.
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, and 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 catalysts used in 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 SFAS No. 144, Accounting for the Impairment of Disposal of Long-Lived Assets. 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 as income in the period that includes the enactment date.
Asset Retirement Obligations. Effective January 1, 2003, we adopted Statement No. 143, Accounting for Asset Retirement Obligations, which established accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. An entity is required to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability should be recognized when a reasonable estimate of fair value can be made.
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.
New Accounting Standards and Disclosures
In December 2004, the FASB issued Statement of Accounting Standards No. 123R, Share-Based Payment (SFAS No. 123R), which requires expensing of stock options and other share-based compensation payments to employees and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing pro forma disclosure only. This standard is effective as of January 1, 2006 and will apply to all awards granted, modified, cancelled or repurchased after that date as well as the unvested portion of prior rewards. Because we use the minimum value method of measuring equity share options for pro forma disclosure purposes under SFAS No. 123, we will apply SFAS No. 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006. The adoption of SFAS No. 123R is not expected to have a material effect on our financial position or results of operations.
In November 2004, the FASB issued Statement No. 151, “Inventory Costs,” which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material, and requires that those items be recognized as current-period charges. Statement No. 151 also requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. Statement No. 151 is effective for fiscal years beginning after June 15, 2005, and is not expected to affect our financial position or results of operations.
In December 2004, the FASB issued Statement No. 153, “Exchanges of Nonmonetary Assets,” which addresses the measurement of exchanges of nonmonetary assets. Statement No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets, which was previously provided by APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. Statement No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement No. 153 is effective for nonmonetary asset exchanges occurring in interim periods beginning after June 15, 2005. The adoption of Statement No. 153 did not have a material effect on our financial position or results of operations.
In May 2005, the FASB issued FASB Statement No. 154, “Accounting Changes and Error Corrections.” Statement 154 establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to a newly adopted accounting principle. This statement will be effective for all accounting changes and any error corrections occurring after January 1, 2006.
In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Retirement Obligations,” or FIN 47, which 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. We adopted FIN 47 at December 31, 2005. The impact of adoption had no effect on our consolidated financial statements.
In December 2004 the FASB issued FASB Staff Position FAS 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004” (“Jobs Creation Act”) which requires a company that qualifies for the deduction for domestic production activities under the Jobs Creation Act to account for it as a special deduction under FASB Statement No. 109, Accounting for Income Taxes, as opposed to an adjustment of recorded deferred tax assets and liabilities. We have included the $1.1 million effects of this special deduction in our calculation of the deferred income tax provision.
In September 2005, the Emerging Issues Task Force, (EITF) reached a consensus concerning the accounting for linked purchase and sale arrangements in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The EITF concluded that generally requires non-monetary exchanges of finished goods inventory within the same line of business be recognized at the carrying value of the inventory transferred. The consensus is to be applied to new buy/sell arrangements entered in reporting periods beginning after March 15, 2006. We do not expect the impact of this EITF Issue No. 04-13 consensus to have a material effect on our financial position or results of operations.
Reconciliation of Amounts Reported Under Generally Accepted Accounting Principles
Reconciliation of Adjusted EBITDA to amounts reported under generally accepted accounting principles in financial statements.
EBITDA represents earnings before minority interest, income tax expense, interest expense, depreciation and amortization. Adjusted EBITDA represents EBITDA, exclusive of 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 minority interests, interest expense, income taxes, gain on disposition of assets and the accounting effects of capital expenditures and acquisitions, items which may vary for different companies for reasons unrelated to overall operating performance. EBITDA, is the basis for calculating selected financial ratios as required in the debt covenants in our revolving credit agreement. See “ - Liquidity and Capital Resources - Cash, Cash Equivalents and Short-Term Investment Position and Indebtedness.”
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 minority stockholders 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 the EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.
Because of these limitations, EBITDA and 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 EBITDA and Adjusted EBITDA only supplementally.
The following table reconciles net income to EBITDA and Adjusted EBITDA for the years ended December 31, 2005, 2004 and 2003, respectively:
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Quantitative and Qualitative Disclosure 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, feedstocks and refined products, 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, 2005, we held approximately 1.8 million barrels of crude and product inventories valued under the LIFO valuation method with an average cost of $30.04 per barrel. Market value exceeded carrying value of LIFO costs by $52.2 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 to $1.8 million.
In accordance with SFAS No. 133, 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, 2005:
Interest Rate Risk
As of December 31, 2005, $100.0 million of our outstanding debt was at floating interest rates. This debt was repaid in full on January 19, 2006.
ITEM 8.
ITEM 8.
CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE.
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.
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 Securities Exchange Act of 1934 (the “Exchange Act”). This section includes the information concerning the controls and controls evaluation referred to in the certifications.
Evaluation of 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 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 submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.
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, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information concerning our directors set forth under “Corporate Governance Matters - The Board of Directors” in the proxy statement for our May 9, 2006 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 Item 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.
The information set forth under “Executive Compensation,” “Compensation Committee Report on Executive Compensation” and “Stockholder Return Performance Graph” 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.
The information set forth under “Certain Relationships and Related Transactions” 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)
Consolidated Financial Statements and Schedule
See Index to Consolidated Financial Statements and Schedule on page.
(2)
Exhibits:
Reference is made to the Index of Exhibits immediately preceding the exhibits hereto, which index in incorporated herein by reference.
+
Filed herewith.
*
Identifies management contracts and compensatory plans or arrangements.

Filed under confidential treatment request.
ALON USA ENERGY, INC. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE
Page
Audited Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2005 and 2004
Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2005, 2004 and 2003
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003
Notes to Consolidated Financial Statements
ALON USA ENERGY, INC. (PARENT COMPANY ONLY)
INDEX TO CONDENSED FINANCIAL STATEMENTS AND SCHEDULE
Audited Condensed Financial Statements:
Report of Independent Registered Public Accounting Firm
Alon USA Energy, Inc. (Parent Company Only) Condensed Balance Sheets as of December 31, 2005 and 2004
Alon USA Energy, Inc. (Parent Company Only) Condensed Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003
Alon USA Energy, Inc. (Parent Company Only) Condensed Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003
Alon USA Energy, Inc. (Parent Company Only) Notes to Condensed 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 (the “Company”) as of December 31, 2005 and 2004, 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, 2005. 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, 2005 and 2004, and the results of their operations, and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 11 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, in 2003.
/s/ KPMG LLP
Dallas, Texas
March 13, 2006
ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands except share data)
The accompanying notes are an integral part of these consolidated financial statements.
ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(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 STOCKHOLDERS’ EQUITY
(dollars in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
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 Southwestern and South Central regions of the United States. Alon’s business consists of two operating segments: (1) Refining and Marketing and (2) Retail.
Refining and Marketing Segment. Alon owns and operates a refinery in Big Spring, Texas. The refinery can process a variety of crude oils, including regionally produced sour crude oil or Gulf Coast and imported crude oils transported on the Amdel and White Oil crude pipelines, which connect the refinery to the Gulf Coast. Alon refines crude oil into petroleum products including various grades of gasoline, diesel fuel, petrochemical feedstocks, asphalt and specialty blended asphalts. Alon primarily markets gasoline and diesel under the FINA brand name at approximately 1,250 locations in five states. Alon’s product distribution network includes seven product pipelines and accesses six product terminals, which are owned or accessed through lease or long-term throughput agreements.
Retail Segment. Alon operates 167 branded 7-Eleven convenience stores in West Texas and New Mexico. These convenience stores typically offer merchandise, food products and motor fuels under the 7-Eleven and FINA brand names. Substantially all of the fuel sold by these stores is produced by Alon’s refinery and is transported to the stores through Alon’s pipeline and terminal networks.
(2) Summary of Significant Accounting Policies
(a) Basis of Presentation
The consolidated financial statements include the accounts of Alon Energy and its subsidiaries. All significant intercompany balances and transactions have been eliminated. Minority interest in Alon’s subsidiaries is reported separately in the accompanying consolidated balance sheets. Minority interest in income of subsidiaries is reported net of income taxes and after elimination of significant intercompany transactions.
On July 6, 2005, Alon (i) increased its authorized common shares to 100,000,000 and (ii) effected a 33,600-for-1 stock split of its common shares, resulting in 35,001,120 common shares outstanding. The earnings per share information and all common share information have been retroactively restated for 2005 and prior periods presented to reflect this stock split (Note 16).
(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, net of applicable excise taxes, for products sold by both the refining and marketing segment and the retail segment are recorded upon delivery of the products to their customers, which is the point at which title to the products is transferred, the customer has assumed risk of loss, and when payment has either been received or collection is reasonably assured. Transportation, shipping and handling costs incurred are reported in cost of sales.
Revenues include the sales of certain 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. The results of these linked refined product buy/sell transactions are recorded in sales and cost of sales in the accompanying statement of operations at fair value. In the ordinary course of business, logistical and refinery
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
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 accompanying statement of operations. Such sales are infrequent and the effects of the sales on operating results are not significant.
For the year’s ended December 31, 2005, 2004 and 2003, Alon recorded revenues related to linked refined product sales of $35,924, $72,354 and $21,783, respectively. For the years ended December 31, 2005, 2004 and 2003, Alon recorded costs related to linked refined product sales of $36,418, $72,651 and $22,414, respectively.
(d) Cost Classifications
Refining and marketing cost of sales includes crude oil and other raw materials, inclusive of 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 goods excludes depreciation and amortization, which is presented separately in the accompanying statement of operations.
Direct operating expenses, all of which relate to Alon’s refining and marketing segment, include costs associated with the actual operations of the refinery, 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 Alon’s crude oil and product pipelines are considered to be transportation costs and are reflected in the cost of sales in the accompanying statement of operations.
Selling, general and administrative expenses consist primarily of costs relating to the operations of the convenience stores, including labor, utilities, maintenance and retail corporate overhead costs. Refining and marketing segment corporate overhead and marketing expenses are also included in selling, general and administrative expenses.
Interest expense consists of interest expense, letters of credit and financing fees, amortization of deferred debt issuance costs less 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) Short-Term Investments
Short-term investments primarily consist of highly-rated auction rate securities (“ARS”). Although ARS may have long-term stated maturities, generally 10 to 30 years, Alon has designated these securities as available-for-sale and has classified them as current because it views them as available to support its current operations. ARS may be liquidated at par on the rate reset date, which is in intervals of seven - 49 days, depending on the terms of the security. These securities are carried at cost, which approximates market value.
(g) Accounts Receivable
The majority of accounts receivable are 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. Historically such losses have been minimal. Reserve for bad debts is based on a combination of current sales, historical charge-offs and specific accounts identified as high risk.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
(h) Inventories
Crude oil, refined products and blendstocks for the refining and marketing segment 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 product, 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 segment merchandise inventories is determined under the retail inventory method and cost for retail segment fuel inventories is determined under the first-in, first-out (FIFO) method.
(i) Hedging Activity
Alon follows Statement of Financial Accountings Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, effective January 1, 2001. Alon considers all forwards, futures, and option contracts to be part of its risk management strategy. Alon has elected not to designate derivative contracts as cash flow hedges for financial accounting purposes. Accordingly, net unrealized gains and losses for changes in the fair value on open derivative contracts are recognized in current cost of sales.
(j) HEP Investment
The investment in HEP consists of 937,500 of subordinated class B limited partnership units in HEP and is accounted for under the equity method. These units maybe converted into common units after March 2010, or before as described in the limited partnership agreement. The fair market value of 937,500 HEP common units as of December 31, 2005 was $34,584.
(k) Property, Plant, and Equipment
The carrying value of property, plant, and equipment includes the fair value of the asset retirement obligation and have been reflected in the accompanying 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 month 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 marketing segment expenditures for routine repairs and maintenance costs are charged to direct operating expense as incurred. Retail segment routine repairs and maintenance costs are charged to selling, general and administrative expense as incurred. The applicable costs and accumulated depreciation of assets that are sold, retired, or otherwise disposed of are removed from the accounts and the resulting gain or loss is recognized.
(l) Impairment of Long-Lived Assets and Assets to Be Disposed Of
Long-lived assets and certain identifiable intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset 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. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. These future cash flows and fair values are estimates based on management’s judgment and assumptions.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
(m) Asset Retirement Obligations
Effective January 1, 2003, Alon adopted Statement No. 143, Accounting for 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 this statement 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 (Note 11).
In March of 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Retirement Obligations (“FIN 47”), which 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. Alon adopted FIN 47 at the end of fiscal 2005. The impact of adoption had no effect on Alon’s consolidated financial statements as all such asset-retirement activities are included in Alon’s asset-retirement obligation under SFAS No. 143.
(n) Turnarounds and Chemical Catalyst 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 Alon’s consolidated balance sheet. 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. Amortization of deferred turnaround and chemical catalyst costs are presented in “depreciation and amortization” in Alon’s consolidated statement of operations.
(o) 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.
(p) Stock-Based Compensation
Alon accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Accordingly, compensation cost for stock options is measured as the excess of the estimated fair value of the common stock over the exercise price and is recognized over the scheduled vesting period on an accelerated basis. Stock compensation expense is presented as selling, general and administrative expenses in the accompanying statements of operations (Note 18).
Alon uses the minimum value method for calculating the fair value impact of SFAS No. 123, Accounting for Stock-Based Compensation (SFAS No. 123). Accordingly, there is no significant pro forma impact on net earnings and earnings per share from adoption of SFAS No. 123.
(q) 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.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
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. Recoveries of environmental remediation costs from other parties are recorded as assets when the receipt is deemed probable (Note 10). Estimates are updated to reflect changes in factual information, available technology or applicable laws and regulations.
(r) Earnings Per Share
Earnings per share is computed by dividing net income by the weighted average of the common shares outstanding. Weighted average shares outstanding for all periods presented reflect the effect of the 33,600-for-one stock split which was effected on July 6, 2005. The shares issued in our initial public offering are reflected in the weighted average shares outstanding at December 31, 2005.
(s) Other Comprehensive Income
Comprehensive income consists of net income and other gains and losses affecting stockholders’ equity that, under United States generally accepted accounting principles, are excluded from net income, such as minimum pension liability adjustments and gains and losses related to certain derivative instruments. The balance in other comprehensive loss, net of tax reported in Alon’s consolidated statements of stockholder’s equity consists solely of minimum pension liability adjustments.
(t) Commitments and Contingencies
Liabilities for loss contingencies, including environmental remediation costs not within the scope of FASB Statement No. 143, Accounting for Asset Retirement Obligations, 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, in accordance with FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts.
(u) New Accounting Standards and Disclosures
In December 2004, the FASB issued Statement of Accounting Standards No. 123R, Share-Based Payment (SFAS No. 123R), which requires expensing of stock options and other share-based compensation payments to employees and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing proforma disclosure only. This standard is effective for Alon as of January 1, 2006. Because, as a private company, Alon used the minimum value method of measuring equity share options for pro forma disclosure purposes under SFAS No. 123, Alon will apply SFAS No. 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006. The adoption of SFAS No. 123R is not expected to have a significant effect Alon’s financial position or results of operations.
In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. This interpretation addresses the consolidation by business enterprises of variable interest entities as defined in the interpretation. The interpretation applies immediately to interests in variable interest entities created after December 31, 2003, and to interests in variable interest entities obtained after December 31, 2003. The adoption of this interpretation in the first quarter of 2004 had no impact on Alon’s consolidated financial statements.
In November 2004, the FASB issued Statement No. 151, Inventory Costs, which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material and requires that those items be recognized as current-period charges. Statement No. 151 also requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. Statement No. 151
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
is effective for fiscal years beginning after June 15, 2005, and is not expected to affect Alon’s financial position or results of operations.
In December 2004, the FASB issued Statement No. 153, Exchanges of Nonmonetary Assets, which addresses the measurement of exchanges of nonmonetary assets. Statement No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets, which was previously provided by APB Opinion No. 29, Accounting for Nonmonetary Transactions, and replaces it with an exception for exchanges that do not have commercial substance. Statement No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement No. 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The adoption of Statement No. 153 did not have a material effect Alon’s financial position or results of operations.
In May 2005, the FASB issued FASB Statement No. 154, Accounting Changes and Error Corrections. Statement 154 establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to a newly adopted accounting principle. This statement will be effective for all accounting changes and any error corrections occurring after January 1, 2006.
In March of 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Retirement Obligations (“FIN 47”), which 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. FIN 47 was adopted by Alon at December 31, 2005. The impact of adoption had no effect on Alon’s consolidated financial statements.
In December 2004 the FASB issued FASB Staff Position (“FSP”) FAS 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004 (“Jobs Creation Act”) which requires a company that qualifies for the deduction for domestic production activities under the Jobs Creation Act to account for it as a special deduction under FASB Statement No. 109, Accounting for Income Taxes, as opposed to an adjustment of recorded deferred tax assets and liabilities. Alon has included the $1,111 effects of this special deduction in its calculation of the December 31, 2005 income tax expense.
In September 2005, the Emerging Issues Task Force, (EITF) reached a consensus concerning the accounting for linked purchase and sale arrangements in EITF Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. The EITF concluded that non-monetary exchanges of finished goods inventory within the same line of business be recognized at the carrying value of the inventory transferred. The consensus is to be applied to new buy/sell arrangements entered in reporting periods beginning after March 15, 2006. Such buy/sell transactions will be recorded as net sales in the statement of operations beginning January 1, 2006. The adoption of EITF Issue No. 04-13 consensus is not expected to have a material effect on Alon’s financial position or results of operations.
(3) Initial Public Offering of Alon
On August 2, 2005, Alon USA Energy, Inc. completed an initial public offering of 11,730,000 shares of its common stock at a price of $16.00 per share for an aggregate offering price of $187,680. Alon received approximately $172,158 in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15,522, or $1.32 per share. The initial public offering represented the sale of a 25.1% interest in Alon.
Alon’s use of proceeds from the initial public offering included the distribution of dividends to pre-offering stockholders of record, the prepayment of debt and general corporate purposes (Notes 13, 16 and 21).
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
(4) Sale of Pipelines and Terminals
HEP Transaction. On February 28, 2005, Alon completed the contribution of the Fin-Tex, Trust and River product pipelines, the Wichita Falls and Abilene product terminals and the Orla tank farm to Holly Energy Partners, LP (“HEP”). In exchange for this contribution, which is referred to as the HEP transaction, Alon received $120,000 in cash, prior to closing costs of approximately $2,000, and 937,500 subordinated Class B limited partnership units of HEP (“Units”).
Simultaneously with this transaction, Alon entered into a Pipelines and Terminals Agreement with HEP providing continued access to these assets for an initial term of 15 years and 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.
The entire cash consideration of $120,000 was financed by high-yield debt issued by HEP with a 10-year maturity (“HEP Debt”). Alon Pipeline Logistics, LLC, a majority-owned subsidiary of Alon (“Alon Logistics”) entered into an agreement with the general partner of HEP providing for Alon Logistics to indemnify the general partner for cash payments such general partner has to make toward satisfaction of the principal or interest under the HEP Debt following a default by HEP (provided that such cash payments exceed the difference between the amount of HEP Debt over the indemnity amount). The initial indemnity amount was limited to the lower of (a) $110,850 or (b) the outstanding amount of HEP Debt. The indemnity terminates at such time as Alon Logistics no longer holds any HEP units and subject to other terms described in the indemnification agreement. The indemnification amount may be reduced from time to time per terms described in the indemnification agreement. The indemnification obligation is specific to Alon Logistics and does not extend to other Alon entities, even if the HEP units are transferred to such other entities. The fair value of this debt guarantee of $1,075 is recorded in other non-current liabilities in the December 31, 2005 consolidated balance sheet.
The HEP transaction was recorded as a partial sale for accounting purposes resulting in a pre-tax gain of $102,461, net of transaction costs and the fair value of the indemnity to the general partner of HEP. Alon recognized an initial pre-tax gain of $26,742. The remaining $75,719 of the gain was deferred. As the HEP units received in the transaction are accounted for under the equity method of accounting for investments in limited partnerships, $6,715 of the pro rata gain was deferred and subtracted from the carrying value of the investment in the HEP units. The remaining deferred gain will be recognized as the indemnification obligation is reduced, over a period of approximately 12 years or less depending on circumstances described in the indemnification agreement. Alon exercised its rights under the indemnification agreement to reduce the indemnity amount by $10,000, resulting in an additional gain of $6,499, and a corresponding decrease in the deferred gain balance. The deferred gain is recorded $11,427 as a current liability and $52,433 as a long-term liability in the December 31, 2005 consolidated balance sheet.
(5) Segment Data
Alon’s revenues are derived from two operating segments: (i) Refining and Marketing and (ii) Retail. The operating segments adhere to the accounting policies used for Alon’s consolidated financial statements as described in Note 2. 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 on operating income.
(a) Refining and Marketing Segment
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
The refining and marketing segment includes a complex sour crude oil refinery, its crude oil and refined products pipeline systems and its refined products terminalling operations. Alon’s refinery produces petroleum products including various grades of gasoline, diesel fuel, jet fuel, petrochemical feedstocks, asphalt and other petroleum based products. In addition, finished products are acquired through exchange agreements and third-party suppliers. Alon primarily markets gasoline and diesel under the FINA brand name, through a network of approximately 1,250 locations. 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.
(b) Retail Segment
Alon’s retail segment operates 167 owned and leased 7-Eleven branded convenience store sites operating primarily in 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 under the 7-Eleven and FINA brand names.
(c) Corporate
Operations that are not included in either of the two segments are included in the category Corporate. These operations consist primarily of corporate headquarter operating and depreciation expenses.
Segment data as of and for the years ended December 31, 2005, 2004 and 2003 is presented below.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
Operating income for each segment consists of net revenues less cost of sales, direct operating expenses, selling, general and administrative expenses, depreciation and amortization and gain on disposition of assets. Sales between segments are transferred at current market prices. Consolidated totals presented are after intersegment eliminations.
Total assets of each segment consist of net property, plant and equipment, inventories, short-term investments, cash and cash equivalents, accounts receivables and other assets directly associated with the segment’s operations. Corporate assets consist primarily of corporate headquarters information technology and administrative equipment.
(6) Derivatives and Hedging Activities
(a) Fair Value of Financial Instruments
The carrying amounts of Alon’s cash and cash equivalents, short-term investments, receivables, payables and accrued expenses approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of long-term debt approximates fair value. Derivative financial instruments are carried at fair value, which is based on quoted market prices.
(b) Derivative Financial Instruments
Alon selectively utilizes commodity derivatives to manage its exposure to commodity price fluctuations and interest rate-related derivative instruments to manage its exposure on its debt instruments. Alon does not enter into derivative instruments for any purpose other than cash flow hedging purposes. Accordingly, Alon does not speculate using derivative instruments. Alon has elected not to designate derivative instruments as cash flow hedges for financial accounting purposes. Therefore, changes in the fair value of the derivative instruments are included in income in the period of the change. There is not a significant credit risk on Alon’s derivative instruments which are transacted through counterparties meeting established collateral and credit criteria.
Commodity Instruments
Alon occasionally uses crude oil and refined product commodity futures contracts to reduce financial exposure related to price changes on anticipated transactions. Crude oil and refined product forward contracts are used to facilitate the supply of crude oil to the refinery and the sale of refined products while managing price exposure.
At December 31, 2005, Alon held net forward contracts for purchases of 25 thousand barrels of refined products at an average price of $63.62 per barrel with a fair value of $1,796. At December 31, 2004, Alon held net forward contracts for sales of 5 thousand barrels of refined products at an average price of $48.38 per barrel with a fair value of $232. These contracts were not designated as hedges for accounting purposes. Accordingly, net unrealized gains of $206 and losses of $10 were recorded as an adjustment to net sales in the consolidated statement of operations for the years ended December 31, 2005 and 2004, respectively.
In accordance with SFAS No. 133, 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 Alon’s consolidated financial statements.
(7) Accounts Receivable
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 credit quality of Alon’s customer base and the large number of customers comprising 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. Alon’s allowance for doubtful accounts is reflected as a reduction of accounts receivable in the consolidated balance
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollar in thousands except as noted)
sheets. The balance in the allowance account was $1,145 and $1,322 at December 31, 2005 and 2004, respectively. For the three-year period ended December 31, 2005, no sales to a single customer accounted for more than 10% of Alon’s net sales.
(8) Inventories
Alon’s inventories 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, 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 and blendstock inventories totaled 1,819 barrels and 1,907 barrels as of December 31, 2005 and 2004, respectively. A reduction of inventory volumes during 2005 resulted in a liquidation of LIFO inventory layers carried at lower costs which prevailed in prior years. The liquidation decreased cost of sales by approximately $2,493 in 2005.
Market values of crude oil, refined products and blendstocks inventories exceeded LIFO costs by $52,198 and $25,756 at December 31, 2005 and 2004, respectively.
(9) Property, Plant, and Equipment, Net
Property, plant, and equipment consisted of the following:
The useful lives on depreciable assets used to determine depreciation expense were as follows:
Alon capitalized interest of $927, $301, and $297 for the years ended December 31, 2005, 2004, and 2003, respectively.
(10) Other Assets
Other assets consisted of the following:
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
In connection with the acquisition of the refinery, pipeline and terminal assets from Atofina Petrochemicals, Inc. (“FINA”) in August 2000, FINA agreed to indemnify Alon for the costs of environmental investigations, assessments, and clean-ups of known conditions that existed at the acquisition date. Such indemnification is limited to an aggregate of $20,000 over a ten-year period. Annual indemnification is limited to a ceiling of $5,000 except that the ceiling may be increased by the amount (up to $5,000) in cases by which the previous year’s ceiling exceeded actual costs. FINA retains liability for third-party claims received within ten years of the acquisition alleging personal injury or property damage resulting from FINA’s use of the acquired assets prior to the acquisition. Alon’s management does not expect expenditures for remediation of existing contamination to exceed the indemnification limitations. Alon also has insurance coverage for amounts in excess of $20,000, up to $40,000 during the ten-year indemnification period. Accordingly, at December 31, 2005 and 2004, Alon has recorded a current receivable of $1,750 and $3,000 and a non-current receivable of $3,257 and $4,314 from FINA, respectively, and corresponding accrued environmental liabilities (Note 19).
Debt issuance costs are amortized over the term of the related debt using the effective interest method. Amortization of deferred debt issuance costs is recorded as interest expense in the accompanying statements of operations. Amortization of debt issuance costs was $1,883, $1,329, and $902 for the years ended December 31, 2005, 2004, and 2003, respectively.
(11) Accrued Liabilities
Alon’s current accrued liabilities and non-current other liabilities at December 31, 2005 and 2004 consisted of the following:
Alon adopted the Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143), on January 1, 2003 and recognized a $336 cumulative effect of adoption, net of $173 of income tax benefit in connection with future estimated costs for dismantling certain refinery and pipeline assets. SFAS No. 143 requires that Alon record the fair value of liability associated with an asset retirement obligation. No additional accrual was recorded under FIN 47. Alon’s asset retirement obligation relates to the removal of underground storage tanks and debranding costs at Alon’s owned and leased retail sites and the dismantlement and disposal of certain pipeline, terminal, and refinery assets. The asset retirement obligation for storage tank removal
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
on leased retail sites is 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 Alon’s asset retirement obligations for the years ended December 31, 2005 and 2004:
(12) Employee and Postretirement Benefits
Alon has two defined benefit pension plans covering substantially all of its refining and marketing segment employees. 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.
In addition to providing pension benefits, certain health care and life insurance benefits (other benefits) are provided to active and certain retired employees who meet eligibility requirements defined in the plan documents. The health care benefits in excess of certain limits are insured.
Alon’s retiree medical plan provides prescription drug benefits, which were affected by the Medicare Prescription Drug Improvement and Modernization Act of 2003(the “Act”), signed into law in December 2003. The Act introduces a prescription drug benefit under Medicare (“Medicare Part D”), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In May 2004, the FASB issued FASB Staff Position No. 106-2 (“FSP 106-2”), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which provides guidance for the accounting of the federal subsidy. Alon incorporated the effects of the Act into the regular measurement of plan obligations as of December 31, 2004, which resulted in an immaterial reduction in the accumulated postretirement benefit obligation.
The measurement dates used to determine pension and other postretirement benefit measures for the pension plan and the postretirement benefit plan is December 31, 2005 and 2004. Financial information related to Alon’s pension plans and other postretirement benefits is presented below.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
As of December 31, 2005 and 2004, the accumulated benefit obligation for each of Alon’s pension plans was in excess of plan assets. The aggregate 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, 2005, 2004 and 2003 were as follows:
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
The weighted-average assumptions used to determine net periodic benefit costs for the years ended December 31, 2005, 2004 and 2003 were as follows:
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 return is based exclusively on historical returns.
For measurement purposes, a 9.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005. The rate was assumed to decrease gradually to 6.0% through 2009 and remain at that level thereafter. 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, 2005 and 2004 was as follows:
The investment policies and strategies for the assets of Alon’s pension benefits and postretirement benefits plans is to provide returns in excess of the benchmark measured over a rolling five year period. 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 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 a blend of domestic and international stocks of various sizes of capitalization. The aggregate asset allocation is reviewed on an annual basis.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
Cash Flows
Alon contributed $3,354 and $2,729 to the pension plan for the years ended December 31, 2005 and 2004, respectively, and expects to contribute $2,900 to the pension plan in 2006. There were no employee contributions to the plans.
The following benefits expected to be paid in each year 2006 - 2010 are $808; $1,078; $937; $1,021; and $1,136, respectively. The aggregate benefits expected to be paid in the five years from 2011 - 2015 are $11,651. The expected benefits are based on the same assumptions used to measure Alon’s benefit obligation at December 31, 2005 and include estimated future employee service.
During the period from January 1, 2003 through December 31, 2005, the return on plan assets and plan contributions did not increase sufficiently to cover the increase in benefits to be paid to participants. This put the plan into an unfunded accumulated pension obligation position and, in accordance with SFAS No. 87, Employer’s Accounting for Pensions, Alon recorded an unfunded accrued pension cost of $575, $1,196 and $506 at December 31, 2005, 2004 and 2003, respectively. Of the unfunded pension cost $335, net of a $240 tax benefit, $723, net of a $472 tax benefit and $313, net of a $193 tax benefit, was reflected as a component of comprehensive income for the years ended December 31, 2005, 2004 and 2003, respectively.
The assumed health care cost trend rates used to determine the projected postretirement benefit obligation are as follows:
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care and life insurance plans. A one-percentage-point change in assumed health care cost trend rates could have the following effects:
Alon sponsors a 401(k) plan in which employees of Alon’s retail segment may participate by contributing up to 15% of their pay after completing one year of service. Alon matches from 25% to 75% of the employee contribution, depending on the employee’s years of service. This match is limited to 6% of employee pay with full vesting of matching and contributions occurring after five years of service. Alon’s contribution for the years ended December 31, 2005 and 2004 was $165 and $164, respectively.
A summary of Alon’s long-term debt follows:
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
On January 14, 2004 Alon entered into a senior secured term loan facility (secured term loan) in the aggregate amount of $100,000 maturing in January 2009. The term loan accrues interest at LIBOR (4.37% at December 31, 2005 and 2.56% at December 31, 2004) plus 6.5% per year, but not less than 10% per annum, and is subject to a minimum annual payment of $2,500 per year which can be increased under certain circumstances or declined by lenders as defined in the agreement. This facility includes certain restrictions and covenants, including, among other things, limitations on capital expenditures, dividend restrictions and minimum net worth and coverage ratios. On January 19, 2006 the $100,000 principal was paid in full with available cash on hand (Note 21).
(b)
Revolving Credit Facility
As of December 31, 2005, Alon had a revolving credit facility which provides for commitments of $141,600 for a three-year term. In addition, Alon has a separate credit facility for the issuance of letters of credit for up to $20,000. Subject to commitment amounts and terms, the revolving credit facility provides for the issuance of letters of credit and up to $82,000 of which is available for revolving credit loans. The revolving credit facility is primarily used for issuance of letters of credit (principally for crude oil purchases). Alon is charged various fees and expenses in connection with this facility, including facility fees and various letter of credit fees. No amounts were outstanding under this revolving credit facility at December 31, 2005. Amounts outstanding under this revolving credit facility accrue interest at the Eurodollar plus 2.5%. This facility includes certain restrictions and covenants, including, among other things, limitations on capital expenditures, dividend restrictions and minimum net worth and coverage ratios.
On February 15, 2006 the above revolving credit facility was amended, increasing the facility to $240,000 with a minimum of $160,000 and extending the term to January 2010. Amounts outstanding under this revolving credit facility accrue interest at the Eurodollar rate plus 1.5% per year (Note 21).
As of December 31, 2005 and 2004, Alon had $131,727 and $100,676, respectively, of outstanding letters of credit under the revolving credit facility and the other credit facility.
(c)
Retail Mortgages and Equipment Loans
On October 1, 2002, Alon entered into a $35,000 term loan agreement. The agreement consists of a 20-year $22,300 mortgage loan bearing a fixed interest rate of 8.06% per annum and a 10-year $12,700 equipment loan at a fixed rate of 8.30% per annum, secured by certain property, plant, and equipment used in Alon’s retail segment.
These mortgages and equipment loans are to be repaid in monthly principal and interest installments of $346 beginning December 1, 2002, decreasing to $187 after December 1, 2012.
In 2003, Alon obtained $1,545 in mortgage loans to finance the acquisition of new retail locations. The interest rates on these loans range between 5.5% and 9.7%, with 5 to 15 year payment terms.
(d)
Atofina Deferred Purchase Price
Deferred payments due to FINA in connection with the acquisition of marketing assets in 2000 were paid in full in August, 2005.
(e)
Subordinated Notes Payable
As of December 31, 2004, Alon had unsecured subordinated notes payable to its parent company, Alon Israel (“Alon Israel”) of $36,300, subordinated notes payable to former minority interest owners of $3,700, and subordinated notes payable to certain members of executive management of $13. In 2005 Alon paid the outstanding balances in full.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
(f)
Maturity of Long-Term Debt
The aggregate scheduled maturities of long-term debt for each of the five years subsequent to December 31, 2004 are as follows: 2006 - $4,487; 2007 - $4,590; 2008 - $4,795; 2009 - $94,714; 2010 - $2,406 and 2011 and thereafter - $21,398. At December 31, 2005, the debt maturities in 2006 through 2008 reflect the scheduled $2,500 annual payments on the secured term loan and 2009 reflects the $92,500 final payment on the secured term loan. The secured term loan was prepaid on January 19, 2006 (Note 21).
(g)
Interest and Financing Expense
Interest and finance expense included in the accompanying statements of operations consisted of the following:
Income tax expense included the following:
A reconciliation between the income tax expense computed on pretax income at the statutory federal rate and the actual provision for income taxes is as follows:
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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.
Alon and Alon Israel are parties to a consulting agreement whereby Alon Israel provides strategic planning and management consulting services to Alon for an annual fee of $1,500 through September 30, 2003 and $4,000 a year beginning October 1, 2003. In July 2005, the term of the agreement was extended until December 31, 2009 and Alon’s payment obligations under the agreement were terminated in exchange for an aggregate payment to Alon Israel of $6,000, $2,000 of which was paid and expensed in 2005 and the remainder of which was paid in the first quarter 2006 and will be amortized over the remaining term of the contract. Alon Israel’s obligations to provide consulting services under the amended agreement will remain in effect through the end of the term of the agreement.
At January 1, 2005, Alon had subordinated notes payable to Alon Israel, the former minority owners of Alon USA Capital and certain members of executive management totaling $49,200, including accrued interest. All balances outstanding under these notes were paid in full during 2005 (Note 13).
(a)
Common and preferred stock
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 preferred stock, $0.01 par value. Issued and outstanding shares were 46,809,857 and 35,001,120 shares of common stock as of December 31, 2005 and 2004, respectively. There were no issued and outstanding shares of preferred stock as of December 31, 2005 and 2004.
For the years ended December 31, 2005, 2004 and 2003, activity in the number of common stock was as follows:
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
(b)
Initial Public Offering
On August 2, 2005 Alon completed an initial public offering of 11,730,000 shares of its common stock at an aggregate price of $187,680 (Note 3).
On July 6, 2005 Alon (i) increased its common stock to 100,000,000 and (ii) effected a 33,600-for-1 stock split of its common shares, resulting in 35,001,120 common shares outstanding. The earnings per share information and all common share information have been retroactively restated for all prior periods presented to reflect this stock split (Note 2).
Upon the completion of Alon’s initial public offering on August 2, 2005 (Note 3), the board of directors of each of Alon and Alon USA Operating, Inc. approved the payment of special dividends to pre-offering stock holders of record. The applicable stock holders of record of Alon were paid aggregate cash dividends of $68,479 and the minority interest stockholders of record of Alon USA Operating, Inc were paid aggregate cash dividends of $4,652.
On February 15, 2006, Alon announced a quarterly and special cash dividend (Note 21).
Basic earnings per share is calculated as net income divided by the average number of shares of common stock outstanding. Diluted earnings per share included the dilutive effective of restricted shares using the treasury stock method.
Alon has two employee incentive compensation plans, (i) the 2005 Incentive Compensation Plan and (ii) the 2000 Incentive Stock Compensation Plan.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
The 2005 Incentive Compensation Plan was approved by the stockholders in November, 2005, and is a component of Alon’s overall executive incentive compensation program. The Incentive Compensation Plan permits the granting of awards in the form of options to purchase common stock, stock appreciation rights, restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses to Alon’s directors, officers and key employees. Other than the restricted share grants discussed below, there have been no other awards granted under this program.
In August 2005, Alon granted an award of 10,791 shares of restricted stock to certain directors, officers and key employees in connection with the initial public offering. The participants were allowed to acquire shares at a discounted price of $12.00 per share with a grant date fair value of $16.00 per share. In November 2005, Alon granted an award of 65,172 shares of restricted stock to certain directors, officers and key employees with a grant date fair value of $20.42 per share. Non-employee directors are awarded an annual grant of Alon’s common stock valued at $25,000. In 2005, 2,774 shares of restricted stock were awarded to two of Alon’s non-employee directors with a stock grant date fair value of $18.03 per share. All restricted shares granted under the Incentive Compensation Plan vest over a period of three years, assuming continued service at vesting.
Pursuant to SFAS No. 123, Accounting for Stock-Based Compensation, Alon has elected to account for its stock-based compensation under APB Opinion No. 25. Under APB Opinion No. 25, Alon uses the intrinsic value method to account for compensation cost related to stock awards. Accordingly, compensation expense is recorded over the vesting period based on the excess of the estimated fair value of the common stock over the exercise price. Alon recognizes stock compensation expense using the accelerated vesting method prescribed by FASB Interpretation No. 28. Such compensation expense amounted to $388 for the year ended December 31, 2005, the first year such awards were available under the 2005 Incentive Compensation Program.
At August 1, 2000 (inception), Alon USA Operating, Inc. (“Alon Operating”) and Alon Assets, Inc (“Alon Assets”), majority owned, fully consolidated subsidiaries of Alon, adopted a stock option plan (the “Plan”) pursuant to which Alon’s board of directors may grant stock options to certain officers and executive management. The 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. All authorized options were granted in 2000. All stock options have ten-year terms. The options are subject to accelerated vesting and become fully exercisable if Alon achieves certain financial performance and debt service criteria. Upon exercise, Alon will reimburse the option holder for the exercise price of the shares and under certain circumstances the related federal and state taxes (gross up liability). This plan was closed to new participants subsequent to August 1, 2000, the initial grant date. Total compensation expense recognized under this plan was $2,336, $530, and $683 at December 31, 2005, 2004, and 2003, respectively.
The following table summarized the stock option activity for Alon Assets and Alon Operating for the years ended December 31, 2005 and 2004:
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
At December 31, 2005, the number of options exercisable was 1,212 for Alon Assets and 455 for Alon Operating.
At December 31, 2004, Discount Bank Corp. Inc. (“DBC”), the parent company of one of our lenders, held warrants to purchase 1,435 shares of non-voting common stock of Alon Assets and 538 shares of non-voting common stock of Alon Operating for an aggregate exercise price of $659. In 2005 DBC exercised its rights to purchase shares of Alon Assets and Alon Operating and Alon reacquired the shares for an aggregate payment of $3,040.
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. 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 fifteen years. Certain long-term operating leases relating to buildings, land and pipelines include options to renew for additional periods. At December 31, 2005, minimum lease payments on operating leases were as follows:
Total rental expense was $11,235, $12,042, and $13,163 for the years ended December 31, 2005, 2004, and 2003, respectively. Contingent rentals and subleases were not significant.
(b)
Other Commitments
In the normal course of business, Alon has long-term commitments to purchase services, such as natural gas, electricity and water for use by its refinery, terminals, pipelines and retail locations. Alon is also party to various refined product and crude oil supply and exchange agreements. These agreements are short-term in nature or provide terms for cancellation.
Under the terms of the Pipelines and Terminals Agreement with HEP, Alon has committed to transport and store minimum volumes of refined products in the pipelines and terminals acquired by HEP for an initial period of 15 years. Tariffs and services fees are set at competitive rates and the agreement provides for a reduction of the minimum volume requirement under certain circumstances.
Alon is involved in various other claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on Alon’s financial position, results of operations or liquidity.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
Alon is subject to loss contingencies pursuant 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 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 unknown 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 five to ten years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.
In connection with the HEP transaction, Alon entered into 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 $0.1 million 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 $20.0 million, including any amounts paid by Alon to HEP with respect to indemnification for breaches of Alon’s representations and warranties under the 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 which is subject to Alon’s environmental indemnity from FINA. 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.
In connection with the sale of the Amdel and White Oil Pipelines, on March 1, 2006, Alon entered into a Purchase and Sale 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 under the Purchase and Sale Agreement to perform such remediation itself in lieu of indemnifying Sunoco for their costs of performing such remediation.
Alon has accrued environmental remediation obligations of $4,736 ($1,750 current payable and $2,986 non-current liability), at December 31, 2005 and $7,058 ($3,000 current payable and $4,058 non-current liability), at December 31, 2004.
Alon completed the construction of a new $14,600 gasoline desulfurization facility in the fourth quarter 2003, ensuring compliance with the small refiner status regulations mandated by the Federal Clean Air Act, which requires a reduction of the sulfur content in gasoline by January 1, 2004. Alon continues to evaluate new Environmental Protection Agency standards that will require a reduction in sulfur content in diesel fuel manufactured for on-road
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
consumption by 2010. Alon spent approximately $5,113 in 2005 and expects to spend approximately $25,300 over the next five years to comply with these regulations.
Alon has elected to join the Voluntary Emission Reduction Permit program, sponsored by the Texas Commission on Environmental Quality. This program allows facilities to permit grandfathered emission sources through a phased installation of emission control equipment using ten-year Best Available Control Technology. To qualify as a grandfathered source, the equipment must not have been modified since 1972. Alon’s emission control installation plan ends in December 2006. As of December 31, 2005, Alon had spent approximately $11,151 and had completed substantially all of the expenditures required to meet regulatory requirements under the Voluntary Emission Reduction Permit program.
(20)
Quarterly Information (unaudited)
Selected financial data by quarter is set forth in the table below:
On January 19, 2006, Alon made a payment of approximately $103,900 in satisfaction of its outstanding borrowings under the secured term loan agreement, including applicable accrued interest and prepayment premiums, with available cash on hand. $100,000 represents a voluntary prepayment of the outstanding principal under the term loan agreement, approximately $3,000 represents a prepayment premium and $900 represents accrued and unpaid interest on the principal balance. Alon entered into the $100,000 term loan facility, on January 14, 2004. The term loan facility matured in January 2009. The $3,000 prepayment premium and $3,894 of unamortized debt issuance costs will be reflected as interest expense in the first quarter 2006 consolidated statement of operations.
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands except as noted)
(b)
Dividend Announcement
On February 15, 2006 Alon’s Board of Directors announced a quarterly cash dividend of $0.04 per share on the company’s common stock, payable on March 21, 2006 to stockholders of record at the close of business on March 1, 2006. The Board of Directors also announced a special cash dividend of $0.37 per share on the company’s common stock, payable on March 21, to stockholders of record at the close of business on March 1, 2006. In connection with Alon’s cash dividend payment to shareholders on March 21, 2006, Alon’s minority interest owners of Alon Assets and Alon Operating will receive an aggregate cash dividend of approximately $1,088.
(c)
Revolving Credit Facility Amendment
On February 15, 2006 Alon entered into an amended revolving credit agreement with its lenders. The total commitment under the facility was increased from $141,600 to $240,000 and is for, among other things, working capital, acquisitions and other general corporate purposes. The initial size of the facility is $160,000 with options to increase the size to $240,000.
Under this amended facility, the term has been extended through January 2010; existing borrowing costs and letter of credit fees have been reduced; most covenants have been eased; there are substantially no limitation on incurrence of debt, distribution of dividends or investment activities absent existing or resulting default; and the retail subsidiaries have been excluded from the facility. The facility is secured by cash, accounts receivable, inventory and related assets. All fixed assets previously securing the facility have been released.
(d)
Crude Oil Pipelines Disposition
On March 1, 2006 Alon sold its Amdel and White Oil pipelines, which had been inactive since December 2002, to an affiliate of Sunoco Logistics Partners L.P., (“Sunoco”) for a total consideration of approximately $68,000. In conjunction with the sale of the Amdel and White Oil pipelines, which had been inactive since December 2002, Alon entered into a 10-year pipeline Throughput and Deficiency Agreement with Sunoco Logistics Partners L.P., with an option to extend the agreement by four additional thirty month periods. The Throughput and Deficiency Agreement will allow Alon to maintain our physically integrated system by retaining crude oil transportation rights on the pipelines from the Gulf Coast. Pursuant to the Throughput and Deficiency Agreement, Alon has agreed to ship a minimum of 15,000 barrels per day on the pipelines during the term of the agreement.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Alon USA Energy, Inc.:
Under date of March 13, 2006, we reported on the consolidated balance sheets of Alon USA Energy, Inc. and subsidiaries as of December 31, 2005 and 2004, 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, 2005. Our report refers to a change in the method of accounting for asset retirement obligations in 2003. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related consolidated financial statement schedule. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement schedule based on our audits.
In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ KPMG LLP
Dallas, Texas
March 13, 2006
ALON USA ENERGY, INC. (PARENT COMPANY ONLY)
CONDENSED BALANCE SHEETS
(dollars in thousands)
1. (b) SCHEDULES TO THE FINANCIAL STATEMENTS (PARENT ONLY) - SCHEDULE I
ALON USA ENERGY, INC. (PARENT COMPANY ONLY)
CONDENSED STATEMENTS OF OPERATIONS
(dollars in thousands)
ALON USA ENERGY, INC. (PARENT COMPANY ONLY)
CONDENSED STATEMENTS OF CASH FLOWS
(unaudited, dollars in thousands)
ALON USA ENERGY, INC. (PARENT COMPANY ONLY)
NOTES TO CONDENSED FINANCIAL STATEMENTS
(unaudited, dollars in thousands, except share and per share data)
(1)
Basis of Presentation
At December 31, 2005, the agreements governing indebtedness of certain direct and indirect subsidiaries of Alon, such subsidiaries are restricted from making dividend payments, loans or advances to Alon. These restrictions result in restricted net assets (as defined in Rule 4-08(e)(3) of Regulation S-X) of Alon’s direct and indirect subsidiaries exceeding 25% of the consolidated net assets of Alon and its subsidiaries. Upon the prepayment of the secured term loan on January 19, 2006 and the amendment of the revolving credit facility on February 15, 2006, these restrictions are no longer in effect.
The accompanying condensed financial statements summarize Alon’s unaudited financial position as of December 31, 2005 and December 31, 2004 and the unaudited results of operations and cash flows for the years ended December 31, 2005, 2004 and 2003.
The Alon USA Energy, Inc. (Parent Company Only) condensed financial statements should be read in conjunction with the consolidated financial statements of Alon and Subsidiaries included elsewhere herein.
(2)
Initial Public Offering
On August 2, 2005, Alon completed an initial public offering of 11,730,000 shares of its common stock at a price of $16.00 per share for an aggregate offering price of $187,680. Alon received approximately $172,158 in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15,522, or $1.32 per share. The initial public offering represented the sale of a 25.1% interest in Alon (Note 3 of the consolidated financial statements).
As of December 31, 2004, Alon had unsecured subordinated notes payable to its parent company, Alon Israel, of $36,300. Alon retired $25,000 of the subordinated debt in February 2005, with the cash received in the form of a dividend from its wholly-owned subsidiary, Alon USA, Inc. The remaining principal and related accrued interest totaling $20,709 was paid in full on August 2, 2005 with proceeds received in Alon’s initial public offering of common stock (Notes 3 and 13 of the consolidated financial statements).
In August 2005, Alon paid $68,479 in the form of a cash dividend to its pre-offering stockholders of record. The dividend represented a portion of the proceeds from the initial public offering (Notes 3 and 16 of the consolidated financial statements).
(5)
Dividends Received
In February 2005, Alon received $25,000 in the form of a cash dividend from its wholly-owned subsidiary, Alon USA, Inc. The dividend represented a portion of the proceeds Alon USA, Inc., through its subsidiaries, received as a result of the HEP transaction (Note 4 of the consolidated financial statements).
SIGNATURES
Pursuant to the requirements of Section 13 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.
Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on behalf of the registrant and in the capacities and on the dates indicated have signed this report below.
+
Filed herewith.
*
Identifies management contracts and compensatory plans or arrangements.

Filed under confidential treatment request.