Item 1.
Business
Overview
We are an independent crude oil refiner and marketer of refined products based in El Paso, Texas and operate primarily in the Southwest region of the United States, including Arizona, New Mexico and West Texas. Our refinery complex, or refinery, is located in El Paso and has a crude oil refining capacity of 124,000 barrels per day, or bpd, which was expanded during 2006 from 108,000 bpd. Over 90% of all products produced at our refinery consist of light transportation fuels, including gasoline, diesel and jet fuel. Our refinery also has approximately 4.3 million barrels of storage capacity and a 45,000 bpd product marketing terminal, where our refined products are loaded into tanker trucks for local deliveries. In addition, we own an asphalt plant and terminal located adjacent to our refinery which is used to process a portion of our refinery’s residuum production into finished asphalt products. We also own asphalt terminals in Phoenix and Tucson, Arizona, and Albuquerque, New Mexico, which distribute finished asphalt to the areas in which they are located.
Our refinery is located in El Paso on both sides of Trowbridge Drive, which runs east-west and bisects the complex. On the south side of Trowbridge Drive lies the 68,000 bpd South Refinery, with approximately 2.2 million barrels of storage capacity. On the north side of Trowbridge Drive lies the 56,000 bpd North Refinery, with approximately 2.1 million barrels of storage capacity and the product terminal. We acquired the South Refinery assets in 1993 and the North Refinery assets in 2003. See Item 2. “Properties”, for a description of the refineries.
Our refinery benefits from access to both crude oil and refined product pipelines. Crude oil is delivered to our refinery via a pipeline owned and operated by Kinder Morgan Energy Partners, or Kinder Morgan. The pipeline has access to most of the producing oil fields in the Permian Basin in Texas and New Mexico, thereby providing us with a supply of crude oil from fields with long reserve lives. We also have access to blendstocks and refined products from the Gulf Coast through the Magellan South System pipeline that runs from the Gulf Coast to our refinery. Our refined products are delivered to Tucson and Phoenix through the Kinder Morgan East Line, which is currently being expanded, and to Albuquerque and Juarez, Mexico through pipelines owned by Plains All American Pipeline L.P., or Plains. We also supply our refined products at our product marketing terminal and rail loading facilities in El Paso.
Because of our refinery’s location in El Paso, we are well-situated to serve two different geographical areas and thereby diversify our market pricing exposure. Tucson and Phoenix reflect a U.S. West Coast, or West Coast, market pricing structure, while El Paso, Albuquerque and Juarez reflect a U.S. Gulf Coast, or Gulf Coast, market pricing structure. Our refined products typically sell at a premium to those sold on the Gulf Coast due to our advantageous location. In Phoenix, we also benefit from more stringent fuel specifications that require the use of clean burning gasoline, or Phoenix CBG.
We are currently investing significant capital in refinery initiatives that will allow us to improve our crude oil processing flexibility, increase production of higher-value refined products and satisfy certain regulatory requirements. Among these initiatives are the completion of the sulfuric acid regeneration and sulfur gas processing facilities, which will provide us with the capacity to increase our sour crude oil processing from approximately 10% to 50% of our crude oil throughput capacity. The actual percentage of sour crude oil processed will be determined by many factors including sour crude economics and product quality limitations prior to completion of planned gasoline desulfurization projects. We will determine our optimal crude oil slate by first calculating the price difference between WTI crude oil and WTS crude oil. We refer to this differential
as the sweet/sour spread. While WTS crude oil is less expensive than WTI crude oil, we must also consider the fact that processing WTS crude oil results in greater volumes of lower-margin residuum products and may also require additional blendstocks such as alkylate. We will weigh the financial impact of these factors and adjust our crude oil inputs in an attempt to maximize profitability. We also plan to maximize the financial benefits derived from the additional pipeline capacity available to us once the Kinder Morgan East Line expansion is completed. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Capital Spending” for a discussion of our capital expenditures budget.
Initial Public Offering
In January 2006, we completed an initial public offering of 18,750,000 shares of our common stock sold by us, and certain of our stockholders who sold an aggregate of 7,125,000 shares (including over-allotment) of common stock held by them. The initial public offering price was $17.00 per share.
Our net proceeds from the sale of 18,750,000 shares of our common stock were approximately $297.2 million, after deducting underwriting discounts and commissions. We did not receive any of the net proceeds from any sales of shares of common stock by any selling stockholders. The net proceeds from our initial public offering were used as follows:
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to repay $149.5 million of outstanding term loan debt; and
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to replenish cash that was used to fund a $147.7 million distribution to the partners of Western Refining LP immediately prior to the offering.
Also in connection with our initial public offering, pursuant to a contribution agreement, a reorganization of entities under common control was consummated whereby Western Refining, Inc. became the indirect owner of the historical operating subsidiary, Western Refining LP and all of its refinery assets. This reorganization was accomplished by Western Refining, Inc. issuing 47,692,900 shares of its common stock to certain entities controlled by our majority stockholder in exchange for the membership and partner interests in the entities that owned Western Refining LP.
Pending Acquisition
On August 26, 2006, we entered into a definitive merger agreement with Giant Industries, Inc., or Giant, under which we would acquire all of the outstanding shares of Giant. On November 12, 2006, the parties entered into an amendment to the merger agreement. If the transaction closes, we will acquire Giant’s common stock for $77.00 per share in cash. The transaction has been approved by the board of directors of both companies. On February 27, 2007, Giant’s shareholders voted to approve the transaction. The closing of the transaction is subject to various conditions, including compliance with the pre-merger notification requirements of the Hart-Scott-Rodino Antitrust Improvements Act, or HSR Act. The transaction is valued at approximately $1.4 billion, including approximately $280 million of Giant’s outstanding debt, and is not subject to any financing conditions.
We and Giant filed pre-merger notifications with the U.S. antitrust authorities pursuant to the HSR Act on September 7, 2006. We and Giant subsequently entered into an agreement with the Federal Trade Commission, or FTC, on February 20, 2007, in which both companies agreed (i) to respond to additional information requests; (ii) not to certify substantial compliance with the information requests until March 13, 2007; and (iii) not to close our merger with Giant until 30 days after we and Giant certify substantial compliance.
Additionally, on November 22, 2006, Timothy Bisset filed a class action complaint in Arizona state court against Giant, its directors and us in connection with the merger. Mr. Bisset alleges that Giant and its directors breached their fiduciary duty in voting to amend the definitive merger agreement to provide for, among other things, a lower acquisition price of $77.00 per share. Mr. Bisset also alleges that we aided and abetted this breach of fiduciary duty. He also alleges that he and other public stockholders of Giant’s common stock are entitled to enjoin the proposed amended transaction or, alternatively, to recover damages in the event the transaction is completed.
We expect to complete our merger with Giant during the second quarter of 2007. We cannot specify when, or assure that, we and Giant will satisfy or waive all conditions to the merger. Further, there can be no assurance that the FTC, state antitrust authorities, or Mr. Bisset, will not seek injunctive relief to prevent the merger from taking place.
After completing the transaction, Western will have a total crude oil throughput capacity of approximately 223,000 bpd. In addition to our 124,000 bpd refinery in El Paso, we will gain an East Coast presence with a 62,000 bpd refinery in Yorktown, Virginia and will gain two refineries in the Four Corners region of Northern New Mexico with a current combined capacity of 37,000 bpd. Our primary operating areas will encompass the Mid-Atlantic region, far West Texas, Phoenix, Tucson, Albuquerque, Northern Mexico, and the Four Corners region of Utah, Colorado, Arizona, and New Mexico. In addition to the four refineries, our asset portfolio will include refined products terminals in Flagstaff, Arizona and Albuquerque, as well as asphalt terminals in Phoenix, Tucson, Albuquerque and El Paso. Our asset base will also include 155 retail service stations and convenience stores in Arizona, Colorado and New Mexico, a fleet of crude oil and finished product truck transports, and three wholesale petroleum products distributors - Phoenix Fuel Co., Inc., or Phoenix Fuel, primarily in Arizona, Dial Oil Co. primarily in New Mexico and Empire Oil Co. primarily in California.
By expanding our refining operations from one to four facilities, we will significantly diversify our operations. In addition, we will double our lower-cost sour and heavy crude processing capacity as a percent of our total capacity from approximately 12% currently to almost 25%. Our sour and heavy crude processing capacity will reach 46% by the end of 2009, following the completion of our previously announced acid and sulfur gas facilities and our gasoline desulfurization projects at our El Paso refinery. The Yorktown refinery also has the flexibility to incorporate future growth initiatives given its ability to process cost-advantaged feedstocks.
We currently generate most of our revenues from our refining operations in El Paso. Following the closing of the merger, we will generate revenue from four different refineries as well as a diverse mix of complementary retail and wholesale businesses. We expect the merger to be immediately accretive to our earnings per share, excluding one-time transaction costs.
The transaction will be funded through a combination of cash on hand and a $1.9 billion commitment from Bank of America, consisting of up to a $1.4 billion senior secured term loan and a $500 million senior secured revolving credit facility. On August 28, 2006, we deposited $12.5 million into an escrow account. The deposit was subsequently increased to $25.0 million, since the closing of the transaction did not occur on or before November 30, 2006.
If the merger has not been consummated by April 30, 2007, either Giant or Western may terminate the transaction unless their breach was the cause of the merger not being consummated by such date. If the merger is terminated after this date and the HSR waiting period has not expired or been waived, Western will forfeit this $25 million deposit to Giant.
Following the closing of the transaction, Paul Foster will remain President and Chief Executive Officer of Western Refining, and Fred Holliger, Giant’s current Chairman and Chief Executive Officer, will serve as a special advisor to our Board of Directors. The combined company will be headquartered in El Paso and will maintain offices in Scottsdale, Arizona.
Process Summary
Our refinery is a nominal 124,000 bpd cracking facility that has historically run WTI crude oil to optimize the yields of higher-value refined products, which currently account for over 90% of our production output. The existing metallurgy at our refinery, combined with our various refinery initiatives, will give us the flexibility to process significantly more West Texas Sour, or WTS, crude oil, which is less expensive than WTI crude oil.
The following table summarizes our refinery’s major process unit capacities. Unit capacities are shown in barrels per stream day, or bpsd, or operating day. The process units are distinguished by their location in either the South Refinery or North Refinery, which are located approximately one-quarter mile apart; however, the operations of the units are integrated as if a single refinery.
Major Process Unit Capacities
(Barrels per Stream Day)
Power Supply
Electricity is supplied to our refinery by El Paso Electric Company via two separate feeders to both the north and south sides of our refinery. Our refinery’s operations can continue at 100 percent of capacity with just one feeder in service to each side. We have an electrical power curtailment plan to conserve power in the event of a partial outage. In addition, we have multiple small, automatic-starting emergency generators to supply electricity for essential lighting and controls as well as various uninterruptible power supply systems located at several units throughout our refinery to continue power supply to process computers and controls in the event of a power outage.
Natural gas is supplied to our refinery via pipeline operated by Oneok WesTex Transmission, L.P. The transportation contract for this natural gas supply is on an interruptible tariff basis. Our refinery can also connect to the Texas Gas Service natural gas distribution system as an alternate natural gas supply source if necessary. We purchase our natural gas separately from the transportation at market rates.
Raw Material Supply
The primary inputs for our refinery consist of crude oil, iso-butane and alkylate. We currently have the capacity to process approximately 124,000 bpd of crude oil, of which approximately 90% is WTI crude oil. We are currently pursuing several strategic initiatives that, once completed, may result in an increased future use of sour crude oil. The following table describes the historical feedstocks for our refinery:
Crude Oil Supply Pipeline
Crude oil is delivered to our refinery via a 450-mile crude oil pipeline owned and operated by Kinder Morgan. The system handles both sweet (WTI) and sour (WTS) crude oil. The main trunkline into El Paso is used solely for the supply of crude oil to us, on a published tariff. Our affiliate acquired the crude oil pipeline in 2003 from Chevron Corporation, or Chevron. In 2004, our affiliate sold the crude oil pipeline to Kinder Morgan, and we simultaneously entered into a 30-year crude oil transportation agreement with Kinder Morgan. The crude oil pipeline has access to the majority of the producing fields in the Permian Basin, thereby providing us with access to a plentiful supply of WTI and WTS crude oil from fields with long reserve lives.
We generally buy our crude oil under contracts with various crude oil providers, including a contract with Kinder Morgan that expires in 2010 and shorter-term contracts with other suppliers, at market-based rates.
Other Feedstocks/Blendstocks
External iso-butane purchases supplement iso-butane manufactured by us and are fed to our refinery’s alkylation unit for the production of the gasoline blendstock alkylate. Normal butane can be characterized as either a feedstock or a refinery-produced product depending on the time of year. During the summer gasoline season, when gasoline specifications limit the amount of light material that can be blended into the pool, excess normal butane produced by our refinery is stored in caverns in New Mexico. In the winter season, as specifications allow, this material is returned to our refinery for gasoline blending. In addition, we supplement our produced volumes with purchases of normal butane.
We have contracts in place for alkylate, which is purchased from the Gulf Coast and delivered via the Magellan South System pipeline that terminates at our refinery. The high octane and low volatility of alkylate make it a premium blendstock for Phoenix CBG, a high-value gasoline produced by our refinery. Our connection to the Magellan South System pipeline allows us to purchase alkylate at a discount relative to competitors who receive it via rail from the Gulf Coast.
We purchase ethanol for seasonal blending with gasoline to meet the EPA’s oxygenated fuel mandate levels. We purchase ethanol from the Midwest region of the U.S. and currently have contracts in place for the majority of our expected ethanol needs. We receive ethanol via railcar deliveries to El Paso, Albuquerque, Phoenix and Tucson.
Refined Products
Pipelines
Outside of the El Paso area, which is supplied via our product terminal, we provide refined products to other areas, including Tucson, Phoenix, Albuquerque and Juarez. Supply to these areas is achieved through pipeline systems that are linked to our refinery. Product distribution to Arizona is delivered via the Kinder Morgan East Line, which connects our refinery to product terminals in Tucson and Phoenix. We also utilize two pipelines owned by Plains to ship product: the first originates at our refinery and terminates in Albuquerque, and the second runs from El Paso to Juarez. A final pipeline owned by Kinder Morgan provides diesel to the Union Pacific railway in El Paso.
Both Kinder Morgan’s East Line and the Plains pipeline to Albuquerque are interstate pipelines regulated by the FERC and currently operate near 100% capacity year-round. The tariff provisions for these pipelines include prorating policies that grant historical shippers line space that is consistent with their prior activities as well as a prorated portion of any expansions, with only a small amount allocated to new shippers. Kinder Morgan announced in 2006 that it had completed its expansion of the East Line between El Paso and Tucson to approximately 147,000 bpd, and 99,000 bpd between Tucson and Phoenix. Kinder Morgan also announced further expansion of the East Line would be completed in 2007. This expansion will initially increase the capacity by another 8% and provide the platform for further incremental expansions through horsepower additions to the system. We intend to fully utilize our prorated allotment of the increased capacity to capitalize on the higher margins typically available in the Phoenix and Tucson areas.
Customers and Refined Products
We sell a variety of refined products to our diverse customer base. Those customers accounting for more than 10% of our revenues in 2006 were Chevron at 16.7%, Phoenix Fuel at 16.7% and PMI Trading Limited (an affiliate of PEMEX), or PMI, at 10.5%. We have a five-year offtake agreement with Chevron that expires in August 2008 with certain renewal options. Our sales to Phoenix Fuel are pursuant to short-term agreements at prices based on various market indices and our sales to PMI are pursuant to spot sales agreements at prices based on various market indices.
Depending on market conditions and seasonal fluctuations, the yield of specific products may be increased to take advantage of pricing changes and to comply with various regulatory requirements. We also purchase additional refined products from other refiners to supplement supply to our customers. These products are the same grade as the products that we currently manufacture.
Gasoline. For 2006, gasoline accounted for approximately 54% of our refinery’s production. Gasoline accounted for 56%, 60% and 62% of our revenues in 2006, 2005 and 2004, respectively. We produce in excess of 40 different specifications of gasoline over the course of a year to address seasonal requirements in each of the areas we serve. We sell gasoline at our product marketing terminal to the El Paso area and via pipeline to other areas, including Phoenix, Tucson, Albuquerque and Juarez. The highest value gasoline produced at our refinery is typically Premium Phoenix CBG. We also currently sell approximately 12,100 bpd of gasoline to a subsidiary of Petroleos Mexicanos, or PEMEX, the Mexican state-owned oil company, in Juarez via a pipeline that originates at our refinery. Outside of our core service areas, we have exchange agreements for limited
volumes with various companies under which we deliver gasoline on their behalf in areas that we serve, and they deliver product on our behalf in other locations.
Diesel. For 2006, diesel fuel accounted for approximately 31% of our refinery’s production. Diesel accounted for 33%, 32% and 29% of our revenues in 2006, 2005 and 2004, respectively. We produce ultra-low sulfur and high-sulfur diesel fuel. Ultra low sulfur diesel fuel is predominantly used for on-road transportation purposes, such as long-haul trucking and automobile travel. In May 2006, we brought our ultra low sulfur diesel unit on line and are currently producing in excess of 30,000 bpd through this unit. High-sulfur diesel fuel is sold for off-road uses such as railroad transportation and mining. We currently sell approximately 7,300 bpd of high-sulfur diesel to the Union Pacific railroad via a pipeline that runs exclusively from our refinery to its fueling station approximately three miles away. We also sell approximately 9,000 bpd of high-sulfur diesel fuel to the Burlington Northern Santa Fe Railway outside Albuquerque via the Plains pipeline. See “- Pipelines” above.
Jet Fuel. For 2006, jet fuel accounted for approximately 8% of our refinery’s production. Jet fuel accounted for 6% of our revenues in 2006, 2005 and 2004. We currently sell jet fuel to the U.S. federal government and to airlines operating at the El Paso International Airport.
Residuum. For 2006, residuum accounted for approximately 4% of our refinery’s production. We historically sold our residuum for use primarily as an asphalt blendstock to Chevron under a supply agreement, which we terminated in December 2005. In May 2006, we purchased an asphalt plant and terminals from Chevron. The asphalt plant is located in El Paso adjacent to our refinery and is being used to process a portion of residuum production into finished asphalt products. We are now selling our residuum to third parties at market-based rates, or we process it further into finished asphalt at our plant.
Refinery Location/Southwest Region
A refinery’s location can have an important impact on its refining margins because location can influence access to feedstocks and the efficient distribution of refined products. There are five regions in the U.S. (called Petroleum Administration for Defense Districts, or PADDs). For example, we deliver to the western portion of PADD III (New Mexico and West Texas) but not the Gulf Coast market in the eastern portion of PADD III. We also deliver to the eastern portion of PADD V (Arizona), which lacks refining capacity and relies upon pipelines from Texas through El Paso and the West Coast market. Refined products to our destinations are supplied from the seven refineries in the Southwest region as well as from refined product pipelines from outside this area, including the Gulf Coast and the West Coast (primarily Los Angeles, California).
Refined product pricing in some of our destinations benefits from the supply constraints generally described above. The Phoenix and Tucson areas, in particular, have a shortage of refining capacity and limited pipeline availability, which results in refineries serving these areas earning a premium on product sales compared to refineries serving other areas. These constraints are anticipated to persist as the potential for increased supply from West Coast refineries is limited by California’s regulatory environment, projected California demand growth and high costs associated with capacity expansions. Pricing differences between Phoenix, El Paso and Gulf Coast regular and premium gasolines are shown in the following table (in cents per gallon, or cpg):
Source: Oil Price Information Service (OPIS)
(1)
Average spot price.
(2)
Average price for products sold at product marketing terminals in the location indicated.
(3)
Average price for Phoenix grade CBG gasoline.
Competition
We operate in the U.S. Southwest region, which includes the areas of West Texas, New Mexico and Arizona. Refined products are supplied from this region’s seven refineries as well as from refineries located in other regions, including the Gulf Coast and the West Coast (primarily Los Angeles), via interstate pipelines.
The Southwest region has a total refining capacity of approximately 620,000 bpd. Petroleum refining and marketing is highly competitive. The principal competitive factors affecting us are costs of crude oil and other feedstocks, refinery efficiency, refinery product mix and costs of product distribution and transportation. We primarily compete with Valero Energy Corp., ConocoPhillips Company, Alon USA Energy, Inc., Holly Corporation and Giant Industries, Inc, as well as refineries in other regions of the country that serve the regions we serve through pipelines. Because of their geographic diversity, larger and more complex refineries, integrated operations and greater resources, some of our competitors may be better able to withstand volatile market conditions, to compete on the basis of price, to obtain crude oil in times of shortage, and to bear the economic risk inherent in all phases of the refining industry.
The Longhorn refined products pipeline, which was completed in late 2004, 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 West Texas and New Mexico. To date, we have not observed any material margin deterioration from the operation of the Longhorn Pipeline. Any additional supply provided by these pipelines or by the Kinder Morgan pipeline expansion could lower prices and increase price volatility in areas that we serve and could adversely affect our sales and profitability.
Governmental Regulation
All of our operations and properties are subject to extensive federal, state and local environmental and health and safety regulations governing, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances; the emission and discharge of materials into the environment; waste management; and characteristics and composition of gasoline and diesel fuels. Our operations also require numerous permits and authorizations under various environmental and health and safety laws and regulations. Failure to comply with these permits or environmental laws generally could result in fines, penalties or other sanctions or a revocation of our permits. We have made, and will continue to make, significant capital and other expenditures related to environmental and health and safety compliance, including with respect to our air permits and the low sulfur gasoline and ultra low sulfur diesel regulations. Furthermore, we expect to make significant environmental capital expenditures in connection with the planned capacity expansion and upgrade of our refinery. For additional details on capital expenditures related to regulatory requirements and our refinery capacity expansion and upgrade; see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Capital Spending.”
Periodically, we receive communications from various federal, state and local governmental authorities asserting violation(s) of environmental laws and/or regulations. These governmental entities may also propose or assess fines or require corrective action for these asserted violations. We intend to respond in a timely manner to all such communications and to take appropriate corrective action. We do not anticipate any such matters currently asserted will have a material adverse impact on our financial condition, results of operations or cash flows.
Clean Air Act
The EPA has embarked on a Petroleum Refinery Enforcement Initiative (“Initiative”), whereby it is investigating industry-wide noncompliance with certain Clean Air Act rules. The Initiative has resulted in many refiners entering into consent decrees typically requiring substantial capital expenditures for additional air pollution control equipment and penalties. Since December 2003, the Company has been voluntarily discussing with the EPA a settlement pursuant to the Initiative. Negotiations with the EPA regarding this Initiative have focused exclusively on air emission programs. The Company does not expect these negotiations to result in any soil or groundwater remediation or clean-up requirements. While at this time it is not known precisely how the Initiative or any resulting settlement may affect the Company, the Company expects to be required to pay penalties and to install additional pollution controls, and, as a result, its operating costs and capital expenditures may increase. Based on current negotiations and information, the Company has estimated the total capital expenditures that may be required pursuant to the Initiative would be approximately $22 million. These capital expenditures would primarily be for installation of a flare gas recovery system on the south-side of our refinery and installation of nitrogen oxides, or NOx, emission controls. As of December 31, 2006, we had invested $6.2 million on the flare gas recovery system with the remaining $7.8 million budgeted to be spent in 2007. Estimated expenditures for the NOx emission controls project of $8.0 million will occur from 2007 through 2013. These amounts have been included in the Company’s estimated capital expenditures for regulatory projects. Based on current information, the Company does not expect any settlement pursuant to the Initiative to have a material adverse effect on its business, financial condition or results of operations or that any penalties or increased operating costs related to the Initiative will be material. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Capital Spending - Regulatory Projects.”
Reduction of Sulfur Content in Light Fuels
The EPA has adopted regulations under the Clean Air Act that require significant reductions in the sulfur content in gasoline and diesel fuel. These regulations required most refineries to begin reducing sulfur content in gasoline to 30 parts per million, or ppm, in January 1, 2004, with full compliance by January 1, 2006, and require reductions in sulfur content in diesel to 15 ppm beginning in June 1, 2006, with full compliance by January 1, 2010.
However, we applied for and received “small refiner status” under the EPA low sulfur gasoline and ultra low sulfur diesel programs. A small refiner is one having less than 1,500 employees and an average crude oil capacity of less than 155,000 bpd. As a “small refiner,” we do not have to meet the 30 ppm gasoline standard until January 2011 since we fully implemented the new on-road diesel sulfur content standard of 15 ppm by June 1, 2006. If we lose our status as a “small refiner,” we would be required to incur capital expenditures for these gasoline and diesel standards at an earlier date.
Upon the completion of the Giant acquisition, we will no longer qualify as a “small refiner.” The rules provide for a period of at least 30 months to comply with the 30 ppm gasoline standard after losing “small refiner status” due to such merger. We anticipate meeting the standard in the required time. Our compliance with the new reduced sulfur standards in gasoline will require capital expenditures of $185 million through 2009. Our capital cost estimate for gasoline sulfur compliance has increased significantly from previous estimates due to enhanced scope definition for the fluid catalytic cracker, or FCC, gasoline hydrotreater, development and inclusion of costs related to the LSR hydrotreating unit, scope definition for offsites and infrastructure modifications needed to support gasoline sulfur compliance, project cost escalation and related
cost contingencies. For additional details, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Spending.”
In addition to the benefits described above for being classified as a “small refiner” under the EPA rules, we qualify for designation as a small refiner under tax legislation. This legislation allows us to immediately deduct up to 75% of the ultra low sulfur diesel compliance costs when incurred for tax purposes. Furthermore, the law allows the remaining 25% of ultra low sulfur diesel compliance costs to be recovered as tax credits with the commencement of ultra low sulfur diesel manufacturing. We estimate that approximately $114 million of our capital expenditures will qualify for this accelerated deduction/tax credit treatment. The loss of our “small refiner” status upon the completion of the Giant acquisition will not impact this accelerated deduction/tax treatment.
Environmental Remediation
Certain environmental laws hold current or previous owners or operators of real property liable for the costs of cleaning up spills, releases and discharges of petroleum or hazardous substances, even if these owners or operators did not know of and were not responsible for such spills, releases and discharges. These environmental laws also assess liability on any person who arranges for the disposal or treatment of hazardous substances, regardless of whether the affected site is owned or operated by such person. The groundwater and certain solid waste management units and other areas at and adjacent to our refinery have been impacted by prior spills, releases and discharges of petroleum or hazardous substances and are currently undergoing remediation by us and Chevron pursuant to certain agreed administrative orders with the Texas Commission on Environmental Quality, or TCEQ. Chevron retained liability for, and control of, certain environmental liabilities and remediation activities that existed, or arise out of events occurring, prior to our acquisition of the North Refinery assets. For example, Chevron retained responsibility to remediate their solid waste management units in accordance with its Resource Conservation Recovery Act permit and retained liability for, and control of, certain groundwater remediation responsibilities. We currently believe that we have adequate insurance to cover the costs of the remaining activities; however, to the extent that these indemnity and insurance obligations are not fulfilled, we may incur significant costs in connection with these clean-ups. Furthermore, in the future we may be required to remediate pollution conditions at the refinery not addressed by the agreed administrative orders or to remediate newly discovered pollution conditions.
In addition to clean-up costs, we may face liability for personal injury or property damage due to exposure to chemicals or other hazardous substances that we may have manufactured, used, handled or disposed of or that are located at or released from our refinery or otherwise related to our current or former operations. We may also face liability for personal injury, property damage, natural resource damage or for clean-up costs for the alleged migration of petroleum or hazardous substances from our refinery to adjacent and other nearby properties.
There have recently been various discussions of legislation which, if passed, could affect our financial condition and operations. Following the 2005 Gulf Coast hurricanes, there have been increasing legislative discussions about the need to increase U.S. refining capacity and ease the regulatory restrictions that have limited the construction of new refineries and expansion of existing refineries in the U.S. If such legislation is adopted, our costs of regulatory compliance could decrease and, as a result of new refinery construction and existing refinery expansion, competition in our industry may increase. There has also been discussion about legislation to increase taxes or impose price controls on refined products, which, if adopted, could have an adverse effect on our financial condition.
Employees
As of December 31, 2006, we had 416 employees. 231 of our employees are covered by collective bargaining agreements, which expire in April 2009. We consider our relations with our employees to be satisfactory, and we have not suffered any work stoppages at our refinery as a result of labor disputes since we assumed operational control of the refinery in August 2003.
Item 1A.
Item 1A.
Risk Factors
In addition to the other information in this report and our other filings with the SEC, you should carefully consider the following risk factors in evaluating us and our business.
Risk Factors
The price volatility of crude oil, other feedstocks, refined products and fuel and utility services may have a material adverse effect on our earnings and cash flows.
Our earnings 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. 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.
In recent years, the prices of crude oil, other feedstocks and refined products have fluctuated substantially. 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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demand for crude oil and refined products, especially in the U.S., China and India;
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worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa and Latin America;
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the level of foreign and domestic production of crude oil and refined products and the level of crude oil, feedstocks and refined products imported into the U.S., which can be impacted by accidents, interruptions in transportation, inclement weather or other events affecting producers and suppliers;
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U.S. government regulations;
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utilization rates of U.S. refineries;
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changes in fuel specifications required by environmental and other laws, particularly with respect to oxygenates and sulfur content;
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the ability of the members of the Organization of Petroleum Exporting Countries, or OPEC, to maintain oil price and production controls;
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development and marketing of alternative and competing fuels;
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pricing and other actions taken by competitors that impact the market;
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product pipeline capacity, including the Longhorn pipeline, as well as Kinder Morgan’s planned expansion of its East Line, both of which could increase supply in our service areas and therefore reduce our margins;
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accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our plants, machinery or equipment, or those of our suppliers or customers; and
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local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our service areas.
Future volatility may have a negative effect on our results of operations to the extent that the margin between refined product prices and feedstock prices narrows.
The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Crude oil and refined products are commodities; therefore, we have no control over the changing
market value of these inventories. Because our inventory is valued at the lower of cost or market value under the “last-in, first-out”, or LIFO, inventory valuation methodology, 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 products sold.
In addition, the volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refinery affects 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. Natural gas prices have historically been volatile. Typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a negative effect on our results of operations.
We have a limited operating history as a stand-alone company, and our previous financial statements may not be indicative of future performance.
Fiscal year 2004 was the first full year in which we owned and operated our integrated refinery. In light of our acquisition of the North Refinery assets, our financial statements only reflect the impact of that acquisition since that date and therefore make comparisons with prior periods difficult. As a result, our limited historical financial performance makes it difficult for shareholders to evaluate our business and results of operations to date and to assess our future prospects and viability. Furthermore, our brief operating history has resulted in revenue and profitability growth rates that may not be indicative of our future results of operations. As a result, the price of our common stock may be volatile.
If the price of crude oil increases significantly or our credit profile changes, it could have a material adverse effect on our liquidity and 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 $150 million revolving credit facility, or revolving credit facility, to purchase crude oil for our refinery. 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 or require additional support such as letters of credit. 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, which could hinder our ability to purchase sufficient quantities of crude oil to operate our refinery at full capacity. In addition, if the price of crude oil increases significantly, we may not have sufficient capacity under our revolving credit facility, or sufficient cash on hand, 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 earnings and cash flows.
The dangers inherent in our operations could cause disruptions and could expose us to potentially significant losses, costs or liabilities. We are particularly vulnerable to disruptions in our operations because all of our refining operations are conducted at a single refinery complex.
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, the following:
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natural disasters;
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fires;
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explosions;
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pipeline ruptures and spills;
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third-party interference;
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disruption of natural gas deliveries under our interruptible natural gas delivery contract;
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disruptions of electricity deliveries; and
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mechanical failure of equipment at our refinery or third-party facilities.
Any of the foregoing 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. There is also risk of mechanical failure and equipment shutdowns both in general and following unforeseen events. Furthermore, in such situations, undamaged refinery processing units may be dependent on or interact with damaged sections of our refinery and, accordingly, are also subject to being shut down.
Our refinery consists of many processing units, several of which have been in operation for a long time. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs, or our planned turnarounds may last longer than anticipated. Scheduled and unscheduled maintenance could reduce our revenues and increase our costs during the period of time that our units are not operating. Furthermore, any extended, non-excused downtime of our refinery could cause us to lose line space on these refined product pipelines if we cannot otherwise utilize our pipeline allocations.
Because all of our refining operations are conducted at a single refinery complex, any events described above 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 could experience business interruptions caused by pipeline shutdown.
Our refinery is dependent on a 450-mile pipeline owned by Kinder Morgan, for the delivery of all of our crude oil. Because our crude oil refining capacity is approaching the delivery capacity of the pipeline, our ability to offset lost production due to disruptions in supply with increased future production is limited due to this crude oil supply constraint. In addition, we will be unable to take advantage of further expansion of our refinery’s production without securing additional crude oil supplies or pipeline expansion. We also deliver a substantial percentage of our refined products through three principal product 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 other events beyond our control. Our prolonged inability to receive crude oil or transport refined products on pipelines that we currently utilize could have a material adverse effect on our business, financial condition and results of operations.
Severe weather, including hurricanes along the Gulf Coast, could interrupt the supply of some of our feedstocks.
Our crude oil supplies come from the Permian Basin in Texas and New Mexico and therefore are generally not subject to interruption from severe weather, such as hurricanes. However, we obtain certain of our feedstocks, such as alkylate, and some refined products we purchase for resale by pipeline from Gulf Coast refineries. We rely on transported feedstocks to produce a portion of our Phoenix CBG and other refined products. In addition, we currently depend on rail shipments of sulfuric acid to and from acid regeneration facilities in Louisiana to conduct our refining operations. These Gulf Coast refineries and acid regeneration facilities are subject to damage or production interruption from hurricanes or other severe weather. If our supply of feedstocks or sulfuric acid is interrupted, our business, financial condition and results of operations would be adversely impacted.
Competition in the refining and marketing industry is intense, and an increase in competition in the areas in which we sell our refined products could adversely affect our sales and profitability.
We compete with a broad range of refining and marketing companies, including certain multinational oil companies. Because of their geographic diversity, larger and more complex refineries, integrated operations and greater resources, some of our competitors may be better able to withstand volatile market conditions, to compete on the basis of price, to obtain crude oil in times of shortage and to bear the economic risks inherent in all phases of the refining industry. In addition, based on the strong fundamentals for the global refining
industry, capital investments for refinery expansions and new refineries in international markets have increased, which may result in greater U.S. imports of refined products.
We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production and have retail outlets. Competitors that have their own production or extensive retail outlets, with brand-name recognition, are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. If we are unable to compete effectively with these competitors, both within and outside of our industry, there could be a material adverse effect on our business, financial condition and results of operations.
The Longhorn refined products pipeline, which was completed in late 2004, 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 West Texas and New Mexico. In addition, Kinder Morgan announced in 2006 that it had completed its expansion of the East Line between El Paso and Tucson to approximately 147,000 bpd, and 99,000 bpd between Tucson and Phoenix. Kinder Morgan also announced further expansion of the East Line would be completed in 2007. This expansion will initially increase the capacity by another 8% and provide the platform for further incremental expansions through horsepower additions to the system. Any additional supply provided by these pipelines could lower prices and increase price volatility in areas that we serve and could adversely affect our sales and profitability.
We may incur significant costs to comply with environmental and health and safety laws and regulations.
Our operations and properties are subject to extensive federal, state and local environmental and health and safety regulations governing, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances, the emission and discharge of materials into the environment, waste management and characteristics and composition of gasoline and diesel fuels. If we fail to comply with these regulations, we may be subject to administrative, civil and criminal proceedings by governmental authorities, as well as civil proceedings by environmental groups and other entities and individuals. A failure to comply, and any related proceedings, including lawsuits, could result in significant costs and liabilities, penalties, judgments against us or governmental or court orders that could alter, limit or stop our operations.
In addition, new environmental 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, there could be a material adverse effect on our business, financial condition and results of operations.
We have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.
If we cannot generate cash flow or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to comply with certain environmental standards by the current EPA-mandated deadlines or pursue our business strategies, in which case our operations may not perform as well as we currently expect. We have substantial short-term and long-term capital needs, including those for capital expenditures that we will make to comply with the low sulfur content specifications of the Tier II gasoline standards and on- and off-road diesel laws and regulations. Our short-term working capital
needs are primarily crude oil purchase requirements, which fluctuate with the pricing and sourcing of crude oil. We also have significant long-term needs for cash, including those to support our expansion and upgrade plans, as well as for regulatory compliance.
Our operations involve environmental risks that could give rise to material liabilities.
Our operations, and those of prior owners or operators of our properties, have previously resulted in spills, discharges or other releases of petroleum or hazardous substances into the environment, and such spills, discharges or releases could also happen in the future. Past or future spills related to any of our operations, including our refinery, product terminals or transportation of refined products or hazardous substances from those facilities, may give rise to liability (including strict liability, or liability without fault, and cleanup responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. For example, we could be held strictly liable under the Comprehensive Environmental Responsibility, Compensation and Liability Act, or CERCLA, for contamination of properties that we currently own or operate and facilities to which we transported or arranged for the transportation of wastes or by-products for use, treatment, storage or disposal, without regard to fault or whether our actions were in compliance with law at the time. Our liability could also increase if other responsible parties, including prior owners or operators of our facilities, fail to complete their clean-up obligations. Based on current information, we do not believe these liabilities are likely to have a material adverse effect on our business, financial condition or results of operations, but in the event that new spills, discharges or other releases of petroleum or hazardous substances occur or are discovered or there are other changes in facts or in the level of contributions being made by other responsible parties, there could be a material adverse effect on our business, financial condition and results of operations.
In addition, we may face liability for alleged personal injury or property damage due to exposure to chemicals or other hazardous substances located at or released from our refinery or otherwise related to our current or former operations. We may also face liability for personal injury, property damage, natural resource damage or for clean-up costs for the alleged migration of contamination or other hazardous substances from our refinery to adjacent and other nearby properties.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations.
Our operations require numerous permits and authorizations under various laws and regulations, including environmental and health and safety laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes, which may involve significant costs, to limit impacts or potential impacts on the environment and/or health and safety. A violation of these authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or refinery shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or expensive upgrades to our existing pollution control equipment, which could have a material adverse effect on our business, financial condition or results of operations.
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 facility 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:
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creating liens;
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engaging in mergers, consolidations and sales of assets;
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incurring additional indebtedness;
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providing guarantees;
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engaging in different businesses;
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making investments;
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making certain dividend, debt and other restricted payments;
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engaging in certain transactions with affiliates; and
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entering into certain contractual obligations.
We are also subject to financial covenants that require us to maintain specified financial ratios and to satisfy other financial tests. 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 loans could be accelerated or we could be prohibited from borrowing for our working capital needs and issuing letters of credit. If the loans 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 or issue letters of credit under the revolving credit facility, we would need to seek additional financing, if available, or curtail our operations.
Our ability to pay dividends in the future is limited by contractual restrictions and cash generated by operations.
We currently pay a quarterly dividend. However, we are a holding company, and all of our operations are conducted through our subsidiaries. Consequently, we will rely on dividends or advances from our subsidiaries to fund our dividends. The ability of Western Refining LP, our operating subsidiary, to pay dividends and our ability to receive distributions from that entity are subject to applicable local law and other restrictions including, but not limited to, restrictions in our revolving credit facility, including minimum operating cash and net worth requirements. Such laws and restrictions could limit the payment of dividends and distributions to us which would restrict our ability to pay dividends. In addition, our payment of dividends will depend upon our ability to generate sufficient cash flows. Our board of directors will review our dividend policy periodically in light of the factors referred to above, and we cannot assure you of the amount of dividends, if any, that may be paid in the future.
Changes to the current tax laws could result in the imposition of entity level state taxation on our operating subsidiary, which would result in a reduction in our anticipated cash flow.
Our operating subsidiary is organized as a partnership, which generally is not subject to entity level state franchise tax in the jurisdictions in which it is organized or operates. However, current laws may change, subjecting our operating subsidiary to entity level state taxation. For example, because of state budget deficits, in May 2006, the State of Texas enacted a new business tax that is imposed on our gross margin to replace the State’s current franchise tax. The new legislation’s effective date is January 1, 2008, which means that our first Texas Margins Tax (“TMT”) return will not become due until May 15, 2008, and will be based on our 2007 operations. Although the new TMT is imposed on an entity’s gross margin rather than on its net income, certain aspects of the tax make it similar to an income tax. Therefore, we will account for the new TMT as an income tax. The impact of the TMT is expected to increase our effective tax rate by up to 1%.
Our insurance policies do not cover all losses, costs or liabilities that we may experience.
Our insurance coverage does not cover all potential losses, costs or liabilities. Our business interruption insurance coverage does not apply unless a business interruption exceeds 45 days and the loss exceeds $1 million. 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 may not be able to successfully implement our business strategies.
Our business strategies include the implementation of several capital expenditure projects designed to increase the productivity and profitability of our refinery. Many factors beyond our control may prevent or hinder our implementation of some or all of our planned capital expenditure projects or lead to cost overruns, including new or more expensive obligations to comply with environmental regulations, a downturn in refining margins, technical or mechanical problems, lack of available capital and other factors. Failure to successfully implement these profit-enhancing strategies on a timely basis or at all may adversely affect our business prospects and competitive position in the industry.
In addition, a component of our growth strategy is to selectively acquire complementary assets for our refinery in order to increase earnings and cash flow. Our ability to do so will be dependent upon several factors, including our ability to identify attractive 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.
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, including our President and Chief Executive Officer, Executive Vice President, Executive Vice President-Refining, Chief Administrative Officer and Assistant Secretary, Chief Financial Officer and Treasurer and Vice President-Legal, Secretary and General Counsel. 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 would be unavailable to us for any reason, we would be required to hire other personnel to manage and operate our company. We may not 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, 2006, we employed 416 people, 231 of whom were covered by a collective bargaining agreement. The collective bargaining agreement expires in April 2009. 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 business, financial condition and results of operations.
Terrorist attacks, threats of war or actual war may negatively affect our operations, financial condition, results of operations and prospects.
Terrorist attacks in the U.S. and the war in Iraq, 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 and terminals such as ours or pipelines such as the ones on which we depend for our crude oil supply and refined product distribution) may be at greater risk of future terrorist attacks than other possible targets. 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 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.
While we currently maintain insurance that provides coverage against terrorist attacks, such insurance has become increasingly expensive and difficult to obtain. As a result, insurance providers may not continue to offer this coverage to us on terms that we consider affordable, or at all.
Our operating results are seasonal and generally lower in the first and fourth quarters of the year.
Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. In addition, oxygenate is added to the gasoline in our service areas during the winter months, thereby increasing the total supply of gasoline. This combination of decreased demand and increased supply during the winter months can lower prices in the winter months. We also schedule refinery downtime for maintenance and repairs during the winter months. 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. In addition to the overall seasonality of our business, unseasonably warm weather in the winter months in the areas that use heating oil could have the effect of reducing demand for heating oil, which could result in lower prices for diesel in our service areas and reduce operating margins.
Three of our customers each account for more than 10% of our refined product sales, and the complete loss of any of them may have a material adverse impact on our sales and profitability.
In 2006, Chevron, Phoenix Fuel and PMI accounted for 16.7%, 16.7% and 10.5% of our refined product sales, respectively. We have a five-year offtake agreement with Chevron that expires in August 2008 with certain renewal options. Our sales to Phoenix Fuel are pursuant to short-term agreements at prices based on various market indices and our sales to PMI are pursuant to spot sales agreements at prices based on various market indices. If we were to lose all, or substantially all, of these sales and be unable to replace them with other sales at market rates, it would have a material adverse impact on our sales and profitability. Competition in the refining and marketing business is intense. To the extent surplus supplies of refined products become available; it would likely enhance the competition for these customers.
We will be exposed to risks relating to evaluations of controls required by Section 404 of the Sarbanes-Oxley Act of 2002.
We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002. We are required to comply with Section 404 as of December 31, 2007. However, we cannot be certain
as to the timing of completion of our evaluation, testing and remediation actions or the impact of the same on our operations. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board rules and regulations that remain unremediated. We are required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A “material weakness” is a significant deficiency or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC or the New York Stock Exchange, or NYSE. In addition, failure to comply with Section 404 or the report by us of a material weakness may cause investors to lose confidence in our financial statements, and our stock price may be adversely affected as a result. If we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets, and our stock price may be adversely affected.
Our controlling stockholders may have conflicts of interest with other stockholders in the future.
Mr. Paul Foster, our President and Chief Executive Officer, and Messrs. Jeff Stevens, Ralph Schmidt and Scott Weaver, our Executive Vice President, former Chief Operating Officer and current director, and Chief Administrative Officer and Assistant Secretary, respectively, own approximately 59% of our common stock. As a result, Mr. Foster and the other members of this management group will be able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other stockholders, the outcome of any corporate transaction or other matter submitted to our stockholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. So long as this group continues to own a significant amount of the outstanding shares of our common stock, they will continue to be able to strongly influence or effectively control our decisions, including whether to pursue or consummate potential mergers or acquisitions, asset sales and other significant corporate transactions. The interests of Mr. Foster and the other members of this management group may not coincide with the interests of other holders of our common stock.
We are a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for, and may rely on, exemptions from certain corporate governance requirements.
Under these rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements of the NYSE, including:
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the requirement that a majority of our board of directors consist of independent directors;
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the requirement that we have a nominating/corporate governance committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and
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the requirement that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.
We presently do not have a majority of independent directors on our board and are relying on the exemptions from the NYSE corporate governance requirements set forth in the first bullet point above. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE.
Our pending acquisition of Giant Industries, Inc. may not be successful and we may not realize the anticipated benefits from this acquisition.
We may be unable to obtain the governmental and regulatory approvals necessary in order to consummate the Giant acquisition. Even if we do obtain these approvals, and even if the other conditions to the
consummation of the Giant acquisition are satisfied, our acquisition of Giant may pose certain risks to our business. Giant has suffered three fires at its refineries in the past year, and as a result, their insurance costs have increased and the terms of their insurance coverage have been adversely affected. Giant has also suffered increased costs associated with several major capital projects. In addition to the risks ordinarily associated with a significant merger acquisition, we will also be exposed to risks arising from these events and other operational risks that may affect Giant differently than they currently affect us. Although we expect to realize strategic, operational and financial benefits as a result of the Giant acquisition, we cannot predict whether and to what extent such benefits will be achieved. In particular, the success of the Giant acquisition will depend, in part, on our ability to realize anticipated refinery efficiencies and cost savings from assuming the control of Giant’s businesses. No assurances can be given that we will be able to achieve these efficiencies and cost savings.
Our ability to meet our future debt service obligations related to the Giant acquisition and to reduce our total indebtedness will be dependent upon our future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. We cannot assure that our business will continue to generate sufficient cash flow from operations to service our future indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing. Such refinancing might not be possible and additional financing might not be available on commercially acceptable terms or at all.
In addition, we will face certain challenges as we work to integrate Giant’s operations into our business. In particular, the Giant acquisition will significantly expand our geographic scope, the types of business in which we are engaged, the number of our employees and the number of refineries we operate, thereby presenting us with significant challenges as we work to manage the substantial increases in scale resulting from the acquisition. We must integrate a large number of systems, both operational and administrative. Delays in this process could have a material adverse effect on our revenues, expenses, operating results and financial condition. In addition, events outside of our control, including changes in state and federal regulation and laws as well as economic trends, also could adversely affect our ability to realize the anticipated benefits from the Giant acquisition.
We can give no assurance that our acquisition of Giant will perform in accordance with our expectations. Despite our due diligence efforts, we must necessarily base any assessment of Giant on inexact and incomplete information and assumptions with respect to operations, profitability and other matters that may prove to be incorrect. We can give no assurance that our expectations with regards to integration and synergies will materialize. Our failure to successfully integrate and operate Giant, and to realize the anticipated benefits of the acquisition, could adversely affect our operating, performing and financial results.
Additionally, on November 22, 2006, Timothy Bisset filed a class action complaint in Arizona state Court against Giant, its directors and us in connection with the merger. Mr. Bisset alleges that Giant and its directors breached their fiduciary duty in voting to amend the definitive merger agreement to provide for, among other things, a lower acquisition price of $77.00 per share. Mr. Bisset also alleges that we aided and abetted this breach of fiduciary duty. He also alleges that he and other public stockholders of Giant’s common stock are entitled to enjoin the proposed amended transaction or, alternatively, to recover damages in the event the transaction is completed.
Item 1B.
Item 1B.
Unresolved Staff Comments
None.
Item 2.
Item 2.
Properties
The South Refinery
The South Refinery began operations in 1931 as a simple topping refinery and was modernized and converted in 1954 into a 17,000 bpd cracking refinery. During 1990 and 1991, the crude oil unit, FCC unit
and alkylation unit were significantly expanded and a vacuum unit was added. In 2000, entities owned by our management acquired the assets of the South Refinery. Currently, the South Refinery consists of a 68,000 bpd of crude oil refinery capacity with approximately 2.2 million barrels of storage capacity. In addition, the South Refinery has a 31,800 bpd FCC unit, a jet fuel merox unit, an alkylation unit and a sulfur plant.
The North Refinery
The North Refinery began operations in 1928, also as a simple topping refinery. It was converted into a cracking refinery in 1957 and further modernized in 1972 with the addition of a naphtha hydrotreater, catalytic reformer and sulfur plant. In August 2003, we acquired the North Refinery assets and assumed all operating responsibilities. The North Refinery currently has refining assets consisting of 56,000 bpd of crude oil processing, 25,500 bpd of reforming and 30,000 bpd of ULSD hydrotreating. In addition, the North Refinery has approximately 2.1 million barrels of storage capacity and a product-marketing terminal with demonstrated capacity of 45,000 bpd and a permitted capacity of 48,000 bpd.
Asphalt Plant and Terminals
In May 2006, we acquired an asphalt plant and terminal with a capacity of 5,000 bpd located adjacent to our refinery in El Paso, Texas, that is being used to process a portion of our residuum production into finished asphalt products. We also acquired asphalt terminals located in Phoenix, Tucson, and Albuquerque, that are used to distribute finished asphalt to the market areas in which they are located.
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, financial condition or results of operations.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock is listed on the New York Stock Exchange, or NYSE, under the symbol “WNR”. As of March 2, 2007, we had 54 holders of record of our common stock. The following table summarizes the high and low sales prices of our common stock as reported on the New York Stock Exchange Composite Tape for the quarterly periods in the last fiscal year (since our initial public offering in January 2006) and dividends declared on our common stock for the same periods:
Prior to our initial public offering in January 2006, there was no established trading market for our common stock. Our common stock began trading on the NYSE on January 19, 2006. Accordingly, no trading information is available for our common stock prior to that date.
Securities Authorized for Issuance Under Equity Compensation Plans
See Part III, Item 12. “Security Ownership of Certain Beneficial Owners and Management.”
Performance Graph
The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any further filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, each as amended, except to the extent we specifically incorporate it by reference into such filing.
The following graph compares the cumulative 11-month total stockholder return on the Company’s common stock relative to the cumulative total stockholder returns of the Standard & Poor’s, or S&P, 500 index, and a customized peer group of seven companies that includes: Alon USA Energy Inc, Delek US Holdings Inc, Frontier Oil Corp., Holly Corp., Sunoco Inc, Tesoro Corp. and Valero Energy Corp. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common stock and peer group on January 19, 2006. The index on December 31, 2006 and its relative performance are tracked through this date.
COMPARISON OF 11 MONTH CUMULATIVE TOTAL RETURN*
Among Western Refining, Inc, The S & P 500 Index and a Peer Group
*
$100 invested on 1/19/06 in stock or on 12/31/05 in index-including reinvestment of dividends.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
(1)
These repurchases were in private transactions not on an exchange directly with employees of the Company to provide funds to satisfy payroll withholding taxes for such employees in connection with the vesting of restricted shares awarded under the Company’s Long-Term Incentive Plan. The repurchased shares are now held by the Company as treasury shares.
Item 6.
Item 6.
Selected Financial and Operating Data
The following tables set forth our summary historical financial and operating data for the periods indicated below. The summary results of operations and financial position data for 2006 and 2005 have been derived from the consolidated financial statements of Western Refining, Inc. and its subsidiaries including Western Refining LP. The summary statement of operations data for the years ended December 31, 2003 and 2004, and the summary balance sheet data as of December 31, 2004 have been derived from the audited financial statements of our predecessor, Western Refining LP. The summary statement of operations data for 2002, and the summary balance sheet data as of December 31, 2002, and 2003 have been derived from the financial statements of Western Refining LP.
The information presented below should be read in conjunction with Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion together with the financial statements and the notes thereto included elsewhere in this report. This discussion contains forward-looking statements that are based on management’s current expectations, estimates and projections about our business and operations. The cautionary statements made in this report should be read as applying to all related forward-looking statements wherever they appear in this report. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors, including those we discuss under Item 1A. “Risk Factors” and elsewhere in this report. You should read “Risk Factors” and “Forward-Looking Statements.” In this Item 7, all references to “Western Refining,” “the Company,” “we,” “us,” and “our” refer to Western Refining, Inc., or WNR, and the entities that became its subsidiaries upon closing of our initial public offering (including Western Refining Company, L.P., or Western Refining LP), unless the context otherwise requires or where otherwise indicated.
Company Overview
We are an independent crude oil refiner and marketer of refined products based in El Paso, Texas, and operate primarily in the Southwest region of the United States, including Arizona, New Mexico, and West Texas. Our refinery complex, or refinery, is located in El Paso and has a crude oil refining capacity currently of 124,000 barrels per day, or bpd, which was expanded during 2006 from 108,000 bpd. Over 90% of all products produced at our refinery consist of light transportation fuels, including gasoline, diesel and jet fuel. Our refinery also has approximately 4.3 million barrels of storage capacity and a 45,000 bpd product marketing terminal, where our refined products are loaded into tanker trucks for local deliveries. In addition, we own an asphalt plant and terminal located adjacent to our refinery which is used to process a portion of its residuum production into finished asphalt products. We also own asphalt terminals in Phoenix and Tucson, Arizona, and Albuquerque, New Mexico, which distribute finished asphalt to the market areas in which they are located.
We are currently investing significant capital in refinery initiatives that will allow us to improve our crude oil processing flexibility, increase production of higher-value refined products and satisfy certain regulatory requirements. Among these initiatives are the completion of the sulfuric acid regeneration and sulfur gas processing facilities, which will provide us with the capacity to increase our sour crude oil processing from approximately 10% to 50% of our crude oil throughput capacity. The actual percentage of sour crude oil processed will be determined by many factors including sour crude economics and product quality limitations prior to completion of planned gasoline desulfurization projects. We will determine our optimal crude oil slate by first calculating the price difference between WTI crude oil and WTS crude oil. We refer to this differential as the sweet/sour spread. While WTS crude oil is less expensive than WTI crude oil, we must also consider the fact that processing WTS crude oil results in greater volumes of lower-margin residuum products and may also require additional blendstocks such as alkylate. We will weigh the financial impact of these factors and adjust our crude oil inputs in an attempt to maximize profitability. We also plan to maximize the financial benefits derived from the additional pipeline capacity available to us once the Kinder Morgan East Line expansion is completed. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Capital Spending” for a discussion of our capital expenditures budget.
Pending Acquisition of Giant Industries, Inc.
On August 26, 2006, we entered into a definitive merger agreement with Giant, under which we would acquire all of the outstanding shares of Giant. On November 12, 2006, the parties entered into an amendment to the merger agreement. If the transaction closes, we will acquire Giant’s common stock for $77.00 per share in cash. The transaction has been approved by the board of directors of both companies. On February 27, 2007, Giant’s shareholders voted to approve the transaction. The closing of the transaction is subject to various conditions, including compliance with the pre-merger notification requirements of the HSR Act. The transaction is valued at approximately $1.4 billion, including approximately $280 million of Giant’s outstanding debt, and is not subject to any financing conditions.
We and Giant filed pre-merger notifications with the U.S. antitrust authorities pursuant to the HSR Act on September 7, 2006. We and Giant subsequently entered into an agreement with the FTC on February 20, 2007, in which both companies agreed (i) to respond to additional information requests; (ii) not to certify substantial compliance with the information requests until March 13, 2007; and (iii) not to close our merger with Giant until 30 days after we and Giant certify substantial compliance.
Additionally, on November 22, 2006, Timothy Bisset filed a class action complaint in Arizona state court against Giant, its directors and us in connection with the merger. Mr. Bisset alleges that Giant and its directors breached their fiduciary duty in voting to amend the definitive merger agreement to provide for, among other things, a lower acquisition price of $77.00 per share. Mr. Bisset also alleges that we aided and abetted this breach of fiduciary duty. He also alleges that he and other public stockholders of Giant’s common stock are entitled to enjoin the proposed amended transaction or, alternatively, to recover damages in the event the transaction is completed.
We expect to complete our merger with Giant during the second quarter of 2007. We cannot specify when, or assure that, we and Giant will satisfy or waive all conditions to the merger. Further, there can be no assurance that the FTC, state antitrust authorities, or Mr. Bisset, will not seek injunctive relief to prevent the merger from taking place.
After completing the transaction, we will have a total crude oil throughput capacity of approximately 223,000 bpd. In addition to our 124,000 bpd refinery in El Paso, we will gain an East Coast presence with a 62,000 bpd refinery in Yorktown, Virginia and will gain two refineries in the Four Corners region of Northern New Mexico with a current combined capacity of 37,000 bpd. Our primary operating areas will encompass the Mid-Atlantic region, far West Texas, Phoenix and Tucson, Arizona, Northern Mexico, Albuquerque, New Mexico and the Four Corners region of Utah, Colorado, Arizona, and New Mexico. In addition to the four refineries, our asset portfolio will include refined products terminals in Flagstaff, Arizona and Albuquerque, as well as asphalt terminals in Phoenix, Tucson, Albuquerque and El Paso. Our asset base will also include 155 retail service stations and convenience stores in Arizona, Colorado and New Mexico, a fleet of crude oil and finished product truck transports, and three wholesale petroleum products distributors - Phoenix Fuel Co., Inc. primarily in Arizona, Dial Oil Co. primarily in New Mexico and Empire Oil Co. primarily in California.
By expanding our refining operations from one to four facilities, we will significantly diversify our operations. In addition, we will double our lower-cost sour and heavy crude processing capacity as a percent of our total capacity from approximately 12% currently to almost 25%. Our sour and heavy crude processing capacity will reach 46% by the end of 2009, following the completion of our previously announced acid and sulfur gas facilities and our gasoline desulfurization projects at our El Paso refinery. The Yorktown refinery also has the flexibility to incorporate future growth initiatives given its ability to process cost-advantaged feedstocks.
We currently generate most of our revenues from our refining operations in El Paso. Following the closing of the merger, we will generate revenue from four different refineries as well as a diverse mix of complementary retail and wholesale businesses. We expect the merger to be immediately accretive to our earnings per share, excluding one-time transaction costs.
The transaction will be funded through a combination of cash on hand and a $1.9 billion commitment from Bank of America, consisting of up to a $1.4 billion senior secured term loan and a $500 million senior secured revolving credit facility. On August 28, 2006, we deposited $12.5 million into an escrow account. The deposit was subsequently increased to $25.0 million, since the closing of the transaction did not occur on or before November 30, 2006.
If the merger has not been consummated by April 30, 2007, either Giant or Western may terminate the transaction unless their breach was the cause of the merger not being consummated by such date. If the merger is terminated after this date and the HSR waiting period has not expired or been waived, Western will forfeit this $25 million deposit to Giant.
Following the closing of the transaction, Paul Foster will remain President and Chief Executive Officer of Western Refining, and Fred Holliger, Giant’s current Chairman and Chief Executive Officer, will serve as a
special advisor to our Board of Directors. The combined company will be headquartered in El Paso and will maintain offices in Scottsdale.
Initial Public Offering
In January 2006, we completed an initial public offering of 18,750,000 shares of our common stock sold by us, and certain of our stockholders sold an aggregate of 7,125,000 shares (including over-allotment option) of common stock held by them. The initial public offering price was $17.00 per share.
Our net proceeds from the sale of 18,750,000 shares of our common stock were approximately $297.2 million, after deducting underwriting discounts and commissions. We did not receive any of the net proceeds from any sales of shares of common stock by any selling stockholders. The net proceeds from our initial public offering were used as follows:
•
to repay $149.5 million of outstanding term loan debt; and
•
to replenish cash that was used to fund a $147.7 million distribution to the partners of Western Refining LP immediately prior to the offering.
Also in connection with our initial public offering, pursuant to a contribution agreement, a reorganization of entities under common control was consummated whereby Western Refining, Inc. became the indirect owner of the historical operating subsidiary, Western Refining LP, and all of its refinery assets. This reorganization was accomplished by Western Refining, Inc. issuing 47,692,900 shares of its common stock to certain entities controlled by our majority stockholder in exchange for the membership and partner interests in the entities that owned Western Refining LP.
Major Influences on Results of Operations
Our earnings and cash flows from operations are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks, all of which are commodities. The cost to acquire feedstocks and the price of the refined products that we ultimately sell depend on numerous factors beyond our control. These factors include the supply of, and demand for, crude oil, gasoline and other refined products, which in turn depend on 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 operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is primarily the spread between crude oil and refined product prices that affects our earnings and cash flow.
In order to measure our operating performance, we compare our per barrel refinery gross margin to certain industry benchmarks, specifically the Gulf Coast 3/2/1 and West Coast 5/3/2 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. A 5/3/2 crack spread in a given region is calculated assuming that five barrels of a benchmark crude oil are converted, or cracked, into three barrels of gasoline and two barrels of diesel. We calculate the Gulf Coast 3/2/1 crack spread using the market values of Gulf Coast 87 octane gasoline, Gulf Coast ultra low sulfur diesel and WTI crude oil priced at Cushing, Oklahoma. We calculate the West Coast 5/3/2 crack spread using the market values of Los Angeles 85.5 octane gasoline, Los Angeles ultra low sulfur diesel and WTI crude oil priced at Cushing, Oklahoma. The Gulf Coast and West Coast crack spreads are proxies for the per barrel refinery gross margin that a crude oil refiner situated in the Gulf Coast and West Coast region, respectively, would expect to earn if it refined crude oil and sold conventional gasoline and low sulfur diesel. We calculate our per barrel refinery gross margin by dividing the difference between net sales and cost of products sold by our refinery’s total throughput volume.
While these crack spread measurements provide a benchmark for our gasoline and diesel margins, they do not take into account other factors that impact our overall refinery gross margins. For example, our refinery gross margin per barrel is reduced by the sale of lower value products such as residuum and propane. In addition, our refinery gross margin is further reduced because our refinery product yield is less than our total refinery throughput volume.
Tucson and Phoenix typically reflect a West Coast market pricing structure, while El Paso, Albuquerque, and Juarez, Mexico typically reflect a Gulf Coast market pricing structure. Our refined products typically sell at a premium to those sold on the Gulf Coast due to high demand growth and limited local refining capacity
in our service areas. In Phoenix, we also benefit from more stringent fuel specifications that require the use of CBG, which is typically one of our highest value products.
Our results of operations are also significantly affected by our refinery’s operating costs and expenses (other than crude oil purchases), especially the cost of feedstocks and blendstocks (particularly alkylate), natural gas used for fuel and the cost of electricity. Natural gas prices have historically been volatile. Typically, electricity prices fluctuate with natural gas prices.
Demand for gasoline is generally higher during summer months than during winter months due to seasonal increases in highway traffic. 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. The effects of seasonal demand for gasoline are partially offset by seasonality in demand for diesel, which in our region is generally higher in winter months as east-west trucking traffic moves south to avoid winter conditions on northern routes.
Safety, reliability and the environmental performance of our refinery operations are critical to our financial performance. Unplanned downtime of our refinery generally results in lost refinery gross margin opportunity, increased maintenance costs and a temporary increase in working capital investment and inventory. We attempt to mitigate the financial impact of planned downtime, such as a turnaround or a major maintenance project, through a planning process that considers product availability, margin environment and the availability of resources to perform the required maintenance. As a result, we generally schedule our downtime during the winter months. We performed a planned maintenance turnaround during the first quarter of 2006 at a cost of $22.2 million, which was expensed during that same quarter. There were no other planned maintenance turnarounds during the remainder of 2006. Our next planned major maintenance turnaround is scheduled for early 2008.
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 commodities, we have no control over the changing market value of these inventories. Our inventory is valued at the lower of cost or market value under the last-in, first-out, or LIFO, inventory valuation methodology. For periods in which the market price declines below our LIFO cost basis, we could be subject to significant fluctuations in the recorded value of our inventory and related cost of products sold.
We terminated our residuum supply agreement with Chevron in December 2005. We believe that the historical pricing under this agreement reflected a below-market price for our residuum. We are now selling our residuum to third parties at market-based rates. In May 2006, we acquired an asphalt plant and terminal located adjacent to our refinery in El Paso, that is used to process a portion of our residuum production into finished asphalt products. We also acquired asphalt terminals located in Phoenix, Tucson, and Albuquerque, that distribute finished asphalt to the market areas in which they are located.
Sour crude oil has historically accounted for approximately 10% of our refinery’s crude oil throughput, but our current capital spending initiatives will provide us with the flexibility to increase our sour crude oil processing capability by the end of 2007 or early 2008 at our El Paso refinery. We will determine our optimal crude oil slate by first calculating the difference between the value of WTI crude oil and the value of WTS crude oil. We refer to this differential as the sweet/sour spread. While WTS crude oil is less expensive than WTI crude oil, we must also consider the fact that processing WTS crude oil results in greater volumes of lower-margin residuum products and may also require additional blendstocks such as alkylate. We will weigh the financial impact of these factors and adjust our crude oil inputs in an attempt to maximize profitability.
Factors Impacting Comparability of Our Financial Results
Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons discussed below.
Refinancing and Prior Indebtedness
On July 29, 2005, we refinanced a prior term loan with a new $200 million term loan facility, under which we borrowed $150.0 million. Subject to certain conditions, the balance of the term loan facility could have been borrowed at any time until November 30, 2005; however, we elected to terminate this commitment as of October 28, 2005. At December 31, 2005, the balance of this loan was $149.5 million. In January 2006, we paid off the term loan with proceeds from our initial public offering. In connection with such repayment, we recorded an expense in January 2006 of approximately $2.0 million related to the write-off of deferred financing costs incurred in connection with the July 2005 refinancing.
On July 29, 2005, we refinanced a prior line of credit for $140 million with a new $150 million revolving credit facility. This new line of credit is used primarily to support the issuance of letters of credit in connection with our purchases of crude oil. At December 31, 2006 and 2005, there were no amounts outstanding under this refinanced credit facility.
In connection with the debt refinancing that occurred in July 2005, we incurred $4.9 million in new deferred financing costs that will be amortized over the life of the related facilities, except for $2.0 million that was written off in January 2006 upon repayment of the term loan. In addition, we recorded an expense of $3.3 million in 2005 related to the write-off of previously recorded deferred financing costs.
Changes in Our Legal Structure
Prior to our initial public offering in January 2006, our operations were conducted by an operating partnership, Western Refining LP. Immediately prior to the closing of our initial public offering, Western Refining LP became an indirect, wholly-owned subsidiary of Western Refining as a result of a series of steps. As a result, we now report our results of operations and financial condition as a corporation on a consolidated basis rather than as an operating partnership.
Historically, we did not incur income taxes because our operations were conducted by an operating partnership that was not subject to income taxes. Partnership capital distributions were made to our partners to fund the tax obligations resulting from the partners being taxed on their proportionate share of the partnership’s taxable income. As a consequence of our change in structure, we now recognize deferred tax assets and liabilities to reflect net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial and tax reporting purposes. As of January 24, 2006, our estimated net deferred tax liability was $21.3 million. In connection with the change to a corporate holding company structure immediately prior to the closing of our initial public offering, we recorded income tax expense of $21.3 million in the first quarter of 2006 for the cumulative effect of recording our estimated net deferred tax liability. This initial net deferred tax liability was based upon the assumption that a certain voluntary election would be made by Western Refining LP when it filed its 2005 income tax returns. Western Refining LP filed its 2005 income tax returns in September 2006 and the voluntary election was changed from the original assumption. Primarily due to this change, a reduction of $12.9 million was made to the initial net deferred tax liability, which was reflected as an adjustment to the provision for income taxes during the third quarter of 2006. The impact of recording our estimated net deferred tax liability decreased diluted earnings per share by $0.13 for the twelve months ended December 31, 2006. In addition, we now incur income taxes, and our financial statements reflect the actual impact of income taxes beginning in the first quarter of 2006.
Our income tax provision for the year ended December 31, 2006 was $112.4 million. The effective tax rate was 35.4%, including the initial deferred tax liability discussed in the preceding paragraph. As a small refiner, our tax provision was favorably impacted by the immediate deduction of up to 75% of our expenditures, when incurred, related to our ultra low sulfur diesel compliance costs. Furthermore, the law allows the remaining 25% of ultra low sulfur diesel compliance costs to be recovered as tax credits with the commencement of low sulfur diesel manufacturing, which for us started in June of 2006. In addition, our effective tax rate will be impacted starting in 2007 as a result of the State of Texas enacting the TMT. The impact of the TMT is expected to increase our effective tax rate by up to 1%.
In connection with our initial public offering, we assumed the obligations under an equity appreciation rights plan that was an obligation of one of the partners of Western Refining LP. We terminated such plan in exchange for a cash payment of $28.0 million to the participants in such plan immediately prior to the consummation of our offering. In addition, we granted such participants 1,772,041 restricted shares of our common stock, which will vest ratably each quarter for two years. As of December 31, 2005, $28.0 million of compensation expense related to this equity appreciation rights plan had been recorded by Western Refining LP, of which $24.0 million was recorded during 2005 and $4.0 million in 2004. The fair market value of the restricted stock, determined at the date of grant, will be amortized over the vesting period as stock-based compensation expense included in selling, general and administrative expenses.
Major Maintenance Turnaround
We completed a planned maintenance turnaround on the south-side of our refinery during the first quarter of 2006. As a result, half of the refinery was shut down for a period of approximately 16 days while the turnaround was being performed. The cost of the turnaround was $22.2 million, which was expensed in the first quarter of 2006. Our next planned major maintenance turnaround is scheduled for early 2008. Most of our competitors, however, capitalize and amortize maintenance turnarounds.
Public Company Expenses
We believe that our annual general and administrative expenses will increase as a result of becoming a public company following our initial public offering. This increase will be due to the cost of tax return preparations, accounting support services, filing annual and quarterly reports with the SEC, increased audit fees, compliance costs related to Section 404 of the Sarbanes-Oxley Act of 2002, investor relations, directors’ fees, directors’ and officers’ insurance, legal fees and registrar and transfer agent fees. Our financial statements reflect the impact of a portion of these increased expenses and affect the comparability of our financial statements with periods prior to our initial public offering.
Critical Accounting Policies and Estimates
We prepare our financial statements in conformity with U.S. 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 financial statements.
Inventories. Our inventories of crude oil and other feedstocks, unfinished products and refined products are priced at the lower of cost or market. Cost is determined using the LIFO inventory valuation method. Under the LIFO valuation method, the most recent acquisition costs are charged to cost of products sold, and inventories are valued at the earliest acquisition costs. We selected this method because we believe that it more accurately reflects the cost of our current sales. Ending inventory costs in excess of market value are written down to net realizable market values and charged to cost of products sold in the period recorded. In subsequent periods, a new lower of cost or market determination is made based upon current circumstances. We determine market value inventory adjustments by evaluating crude oil, refined products and other inventories on an aggregate basis. The current cost of our inventories exceeded LIFO costs by $82.5 million at December 31, 2006.
Maintenance Turnaround Expense. Our refinery units require regular major maintenance and repairs commonly referred to as “turnarounds.” The required frequency of the maintenance varies by unit but generally is every four years. We expense the cost of maintenance turnarounds when the expense is incurred. These costs are identified as a separate line item in our statement of operations.
Long-Lived Assets. We calculate depreciation and amortization on a straight-line basis over the estimated useful lives of the various classes of depreciable assets. When assets are placed in service, we make estimates of what we believe are their reasonable useful lives. We account for impairment of assets in accordance with Statement of Financial Accounting Standard, or SFAS, No. 144, Accounting for the
Impairment and Disposal of Long-Lived Assets. We review the carrying values of our long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets 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 dispositions.
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. Environmental costs are expensed if they relate to an existing condition caused by past operations with no future economic benefit. Estimates of projected environmental costs are made based upon internal and third-party assessments of contamination, available remediation technology and environmental regulations. Loss contingency accruals, including those for environmental remediation, are subject to revision as further information develops or circumstances change and such accruals can take into account the legal liability of other parties.
Financial Instruments and Fair Value. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138, requires that all derivatives be recognized as either assets or liabilities on the balance sheet and that those instruments be measured at fair value. We are exposed to various market risks, including changes in commodity prices. We use commodity futures and swap contracts to reduce price volatility, to fix margins for refined products and to protect against price declines associated with our crude oil inventories. These transactions do not qualify for hedge accounting in accordance with SFAS No. 133 and, accordingly, are marked to market each month. Any gains or losses associated with these transactions are recognized in gain (loss) from derivative activities.
Pension and Other Postretirement Obligations. Pension and other post-retirement plan expenses and liabilities are determined based on actuarial evaluations. Inherent in these valuations are key assumptions including discount rates, future compensation increases, expected return on plan assets, health care cost trends and demographic data. Changes in our actuarial assumptions are primarily influenced by factors outside of our control and can have a significant effect on our pension and other post-retirement liabilities and costs. For example, our discount rate assumption of 5.93% for the year ended December 31, 2006, based upon a certain pension liability index, was reduced from 6.50% for the year ended December 31, 2005. This change in our discount rate assumption for 2006 compared to 2005 increased our actuarial loss by approximately $3.0 million as of December 31, 2006. See Note 8, “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for more information on these plans and the current assumptions used.
In December 2006, we adopted SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment to FASB Statements No. 87, 88, 106 and 132R, or SFAS No. 158, which requires companies to fully recognize the obligations associated with single-employer defined benefit pension, retiree healthcare, and other postretirement plans in their financial statements. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements. Under SFAS No. 158, a defined benefit postretirement plan sponsor must (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for the plan’s underfunded status, (b) measure the plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as components of net periodic benefit cost.
Stock-based Compensation. Concurrent with our initial public offering of common stock on January 24, 2006, we adopted SFAS No. 123 (revised) Shared-Based Payment, or SFAS No. 123R to account for stock awards granted under our Long-Term Incentive Plan. Under SFAS No. 123R, the cost of employee services received in exchange for an award of equity instruments is measured based on the grant-date fair vale of the award (with some limited exceptions). The fair value of each share of restricted stock awarded was measured
based on the market price at closing as of the measurement date and is amortized on a straight-line basis over the respective vesting periods.
As of December 31, 2006, there had been 2,016,024 shares of restricted stock awarded. The compensation cost of nonvested awards not recognized as of December 31, 2006, was $20.5 million, which will be recognized over a weighted average period of approximately 1.4 years. Although ownership of the shares does not transfer to the recipients until the shares have vested, recipients have voting and nonforfeitable dividend rights on these shares from the date of grant.
New Accounting Pronouncements
We adopted Emerging Issues Task Force, or EITF, Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, on April 1, 2006. This Issue addresses accounting matters that arise when one company both sells inventory to and buys inventory from another company in the same line of business; specifically, when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The application of Issue No. 04-13 reduced our net sales and cost of products sold by $144.1 million during period between April 1 and December 31, 2006. If this Issue had been effective at January 1, 2006, our net sales and cost of products sold would have been reduced by $171.9 million for the full calendar year.
In February 2006, the Financial Accounting Standards Board, or FASB, issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments - an amendment to FASB Statements No. 133 and 140, which provides entities with relief from having to separately determine the fair value of an embedded derivative that would otherwise be required to be bifurcarted from its host contract in accordance with SFAS No. 133. SFAS No. 155 is effective for fiscal years beginning after September 15, 2006. We believe that SFAS No. 155 will not have a material effect on our financial position or results of operations.
In June 2006, the FASB released Interpretation No. 48, Accounting for Uncertainty in Income Taxes, or FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements of a company in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. Application of FIN 48 is effective for fiscal years beginning after December 15, 2006. We believe FIN 48 will not have a material effect in our financial position or results of operations.
In September 2006, the FASB published SFAS No. 157, Fair Value Measurements, to eliminate the diversity in practice that exists due to the different definitions of fair value and the limited guidance for applying those definitions in GAAP that are dispersed among the many accounting pronouncements that require fair value measurements. SFAS No. 157 retains the exchange price notion in earlier definition of fair value, but clarifies that the exchange price is the price in an orderly transaction between market participants to sell an asset or liability in the principal or most advantageous market for the asset or liability. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price), as opposed to the price that would be paid to acquire the asset or received to assume the liability at the measurement date (an entry price). SFAS No. 157 expands disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The guidance in this Statement applies for derivatives and other financial instruments measured at fair value under SFAS No. 133 at initial recognition and in all subsequent periods. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, although earlier application is encouraged. We are evaluating the impact, if any, that SFAS No. 157 will have in our financial position or results of operations.
In September 2005, the SEC staff published Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in the Current Year Financial Statements, or
SAB 108, which expresses the SEC staff’s views on the proper method for quantifying errors when there were uncorrected errors in the prior year. SAB 108 requires quantification of financial statement errors based on the effects of both the balance sheet (iron curtain method) and income statement (rollover method). SAB 108 is effective for fiscal years ending after November 15, 2006. We believe SAB 108 will not have an effect on our financial position or results of operations.
Operating Data
The following table sets forth the refining operating statistical information for our refinery for 2006, 2005 and 2004:
(1)
Includes sales of refined products sourced from our refinery production as well as refined products purchased from third parties.
(2)
Total refinery throughput includes crude oil, other feedstocks and blendstocks.
(3)
Refinery gross margin is a per barrel measurement calculated by dividing the difference between net sales and cost of products sold by our refinery’s total throughput volumes for the respective periods presented. We have experienced gains or losses from derivative activities. These derivatives are used to minimize fluctuations in earnings, but are not taken into account in calculating refinery gross margin. Cost of products sold does not include any depreciation or amortization. Refinery gross margin is a non-GAAP performance measure that we believe is important to investors in evaluating our refinery performance as a general indication of the amount above our cost of products that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of products sold) can be reconciled directly to our statement of operations. Our calculation of refinery gross margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. The following table reconciles gross profit to refinery gross margin for the periods presented:
(4)
Refinery direct operating expense per throughput barrel is calculated by dividing direct operating expenses by total throughput volumes for the respective periods presented. Direct operating expenses do not include any depreciation or amortization.
Results of Operations
Fiscal Year Ended December 31, 2006, Compared to Fiscal Year Ended December 31, 2005
Net Sales. Net sales consist primarily of gross sales of refined petroleum products, net of customer rebates or discount and excise taxes. Net sales for 2006 were $4,199.5 million, compared to $3,406.7 million for 2005, an increase of $792.8 million, or 23.3%. This increase primarily resulted from significantly higher refined product prices and, to a lesser extent, an increase in our sales volume. Our average sales price per barrel for 2006 increased by 17.8% to $80.86 from $68.62 for 2005, due to increased market prices. Our sales volume increased by 2.3 million barrels, or 4.6%, to 51.9 million barrels in 2006 from 49.6 million barrels in 2005. The increase in sales volume was due to increased refinery production resulting from the expansion of our crude oil refining capacity during 2006. Net sales for the year ended December 31, 2006 include the effects of the application of EITF Issue No. 04-13, which reduced our net sales by $144.1 million during the period between April 1 and December 31, 2007.
Cost of Products Sold (exclusive of depreciation and amortization). Cost of products sold includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Cost of products sold was $3,653.2 million for 2006, compared to $3,001.8 million for 2005, an increase of $651.4 million, or 21.7%. This increase was primarily a result of higher crude oil prices and, to a lesser extent, increased production volumes. Our average cost per barrel of crude oil for 2006 was $65.19, compared to $55.10 for 2005, an increase of 18.3%. Our sales volume increased 4.6% for 2006, compared to 2005. Total refinery throughput for 2006 was 46.4 million barrels compared to 42.5 million barrels for 2005, an increase of 9.1%. Refinery gross margin per barrel increased from $9.52 in 2005 to $11.78 in 2006, reflecting improved industry crack spreads and, to a lesser extent, improved asphalt margins. Gross profit per barrel, based on the closest comparable GAAP measure to refinery gross margin, was $11.48 and $9.37 for 2006 and 2005, respectively. Cost of products sold for the year ended December 31, 2006 include the effects of the application of EITF Issue No. 04-13, which reduced our cost of products sold by $144.1 million during the period between April 1 and December 31, 2007.
Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses include costs associated with the actual operations of our refinery, such as energy and utility costs, catalyst and chemical costs, routine maintenance, labor, insurance, property taxes and environmental compliance costs. Direct operating expenses were $173.9 million for 2006, compared to $131.2 million for 2005, an increase of $42.7 million, or 32.5%. This increase primarily resulted from higher energy costs ($12.4 million), increased personnel costs ($8.9 million), higher routine maintenance costs ($8.2 million), increased property tax accruals ($4.4 million), higher catalyst and chemical costs ($2.7 million), increased outside support services ($1.9 million) and increased
environmental compliance costs ($1.6 million). These increases reflect the impact of additional operating costs associated with the asphalt plant and terminals acquired in May 2006, costs related to our increased refinery throughput, and costs associated with operating our new ultra low sulfur diesel unit that came on line in 2006. Direct operating expenses per barrel were $3.75 for 2006, compared to $3.09 for 2005.
Selling, General and Administrative Expenses. Selling, general and administrative expenses were $34.9 million for 2006, compared to $43.5 million for 2005, a decrease of $8.6 million, or 19.8%. The decrease primarily resulted from decreased compensation related to equity appreciation rights granted to certain of our employees in 2005 ($24.0 million) partially offset by increased stock-based compensation expense related to restricted stock grants in 2006 ($13.7 million) and increased personnel costs ($1.2 million).
Maintenance Turnaround Expense. Maintenance turnaround expense includes major maintenance and repairs generally done every four years, depending on the processing units involved. Maintenance turnaround expense was $22.2 million for the twelve months ended December 31, 2006, compared to $7.0 million in 2005, an increase of $15.2 million, or 217.1%. This increase primarily resulted from a planned major maintenance turnaround on our South Refinery during the first quarter of 2006, versus a partial turnaround performed during the first quarter of 2005.
Depreciation and Amortization. Depreciation and amortization for 2006 was $13.6 million, compared to $6.3 million for 2005. The increase was due to the completion of various capital projects throughout 2006, including our ultra low sulfur diesel project.
Operating Income. Operating income for 2006 was $301.7 million, compared to $216.9 million for 2005, an increase of $84.9 million, or 39.2%. This increase primarily resulted from higher refinery gross margins, an increase in sales volume of 4.6% and decreased deferred compensation expense ($24.0 million), somewhat offset by an increase in the cost of maintenance turnarounds ($15.2 million), increased stock-based compensation expense ($14.2 million), higher energy costs ($12.4 million), higher routine maintenance costs ($8.2 million) and higher other personnel costs ($7.2 million).
Interest Expense. Interest expense for the twelve months ended December 31, 2006, was $2.2 million, compared to $6.6 million for the same period in 2005. Our long-term debt was paid in full in January 2006 with a portion of the proceeds from our initial public offering. As a result, ongoing interest expense in 2006 relates primarily to letter of credit fees associated with our revolving line of credit.
Amortization of Loan Fees. Amortization of loan fees for 2006, was $0.5 million, compared to $2.1 million for 2005. The reduction was due to the write-off of unamortized loan fees relating to our new term loan paid off in January 2006.
Write-Off of Unamortized Loan Fees. In January 2006, we paid off our new term loan facility with proceeds from our initial public offering. Accordingly, we recorded an expense of $2.0 million related to the write-off of previously recorded deferred financing costs. In July 2005, we entered into the new term loan and revolving credit facility and recorded an expense of $3.3 million related to the write-off of previously recorded deferred financing costs.
Gain (Loss) from Derivative Activities. The net gain from derivative activities was $8.8 million for 2006, compared to a net loss of $8.1 million for 2005. The difference between the two periods was primarily attributable to fluctuations in market prices related to the derivative transactions that were either settled or marked to market during each respective period.
Income Tax Expense. With our change from a partnership to a corporate holding company structure on January 24, 2006, we began to reflect a provision for income taxes. Also in connection with this change, we recorded a one-time provision of $8.3 million during 2006 to reflect our estimated initial deferred tax liability. No income taxes were reflected prior to the change, as our taxes were the responsibility of the partners. We did, however, make distributions to our partners to cover their tax obligations prior to this change. Those prior distributions were reflected in our financing activities cash flow.
Net Income. We reported net income of $204.8 million for 2006, compared to net income of $201.1 million for 2005, representing $3.13 net income per share on a weighted average dilutive shares
outstanding of 65.8 million. Net income for 2006 includes an $8.3 million provision to record the estimated initial deferred tax liability upon our change to a corporate holding company structure. This one-time provision reduced diluted earnings per share by $0.13 for the twelve months ended December 31, 2006. Net income for the twelve months ended December 31, 2005, did not include a provision for income taxes for Western Refining LP because we were a partnership and those taxes were the responsibility of the partners. However, net income for the twelve months ended December 31, 2005 included a minor tax benefit of $18,000 related to the operations of Western Refining, Inc. for the period of September 16 (inception) to December 31, 2005.
Fiscal Year Ended December 31, 2005, Compared to Fiscal Year Ended December 31, 2004
Net Sales. Net sales consist primarily of gross sales of refined petroleum products, net of customer rebates or discounts and excise taxes. Net sales for 2005 were $3,406.7 million, compared to $2,215.2 million for 2004, an increase of $1,191.5 million, or 53.8%. This increase primarily resulted from significantly higher refined product prices and, to a lesser extent, an increase in our sales volume. Our average sales price per barrel for 2005 increased by 36.4% to $68.62 from $50.30 for 2004, due to increased market prices. Our sales volume increased by 5.6 million barrels, or 12.7%, to 49.6 million barrels for 2005, compared to 44.0 million barrels for 2004. The increased sales volume primarily resulted from higher production levels of refined products during 2005 versus 2004 because of various projects that improved refinery production and lower production levels in 2004 due to a refinery-wide maintenance turnaround performed during the first quarter of 2004 as well as increased sales of purchased products.
Cost of Products Sold (exclusive of depreciation and amortization). Cost of products sold includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Cost of products sold was $3,001.8 million for 2005, compared to $1,989.9 million for 2004, an increase of $1,011.9 million, or 50.9%. This increase was primarily a result of higher crude oil prices and, to a lesser extent, increased sales volumes. Our average cost per barrel of crude oil for 2005 was $55.10, compared to $42.10 for 2004, an increase of 30.9%. Our sales volume increased 12.7% for 2005, compared to 2004. Total refinery throughput for 2005 was 42.5 million barrels compared to 39.9 million barrels for 2004, an increase of 6.5%. Refinery gross margin per barrel increased from $5.64 in 2004 to $9.52 in 2005, reflecting improved industry crack spreads. Gross profit per barrel, based on the closest comparable GAAP measure to refinery gross margin, was $5.53 and $9.37 for 2004 and 2005, respectively.
Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses include costs associated with the actual operations of our refinery, such as energy and utility costs, catalyst and chemical costs, routine maintenance, labor, insurance, property taxes and environmental compliance costs. Direct operating expenses were $131.2 million for 2005, compared to $110.0 million for 2004, an increase of $21.2 million, or 19.3%. This increase primarily resulted from higher energy costs ($7.4 million), increased incentive compensation ($3.8 million), increased personnel costs excluding incentive compensation ($4.0 million), higher catalyst and chemical costs ($2.4 million), and higher routine maintenance costs ($3.9 million). Direct operating expenses per barrel were $3.09 for 2005, compared to $2.75 for 2004.
Selling, General and Administrative Expenses. Selling, general and administrative expenses consist primarily of corporate overhead and marketing expenses. Selling, general and administrative expenses were $43.5 million for 2005, compared to $17.2 million for 2004, an increase of $26.3 million, or 152.9%. The increase primarily resulted from increased deferred compensation expense related to equity appreciation rights granted to certain employees ($20.0 million) and increased incentive compensation ($5.2 million) related to our financial performance.
Maintenance Turnaround Expenses. Maintenance turnaround expenses include major maintenance and repairs generally done every four years, depending on the processing units involved. Maintenance turnaround expense was $7.0 million for 2005, compared to $14.3 million for 2004, a decrease of $7.3 million, or 51.0%. This decrease primarily resulted from a partial turnaround being performed during the first quarter of 2005 ($5.9 million) versus a refinery-wide turnaround during the first quarter of 2004. Turnaround expenses for 2005 also included $1.1 million incurred in the fourth quarter of 2005 for preliminary work done related to a major maintenance turnaround performed during the first quarter of 2006.
Depreciation and Amortization. Depreciation and amortization for 2005 was $6.3 million, compared to $4.5 million for 2004. The increase was due to the completion of various capital projects in late 2004 and throughout 2005.
Operating Income. Operating income for 2005 was $216.8 million, compared to $79.2 million for 2004, an increase of $137.6 million, or 173.7%. This increase primarily resulted from higher refinery gross margins, an increase in sales volume of 12.7% and a decrease in the cost of maintenance turnarounds ($7.3 million), somewhat offset by higher deferred compensation expense ($20.0 million), higher other employee costs ($13.0 million), and higher energy costs ($7.4 million).
Interest Expense. Interest expense for 2005 was $6.6 million, compared to $5.6 million for 2004, an increase of 17.9%. This increase was primarily related to increased letter of credit fees and the new term loan facility entered into on July 29, 2005, somewhat offset by capitalized interest ($1.3 million) in 2005.
Amortization of Loan Fees. Amortization of loan fees for 2005 was $2.1 million, compared to $2.9 million for 2004.
Write-Off of Unamortized Loan Fees. In July 2005, we entered into new term loan and revolving credit facilities. A portion of the proceeds from the new term loan facility was used to retire $50 million of outstanding debt under an August 29, 2003, term loan agreement. Accordingly, we recorded an expense of $3.3 million related to the write-off of previously recorded deferred financing costs.
Gain (Loss) from Derivative Activities. The net loss from derivative activities was $8.1 million for 2005, compared to a net loss of $4.0 million for 2004. These amounts relate to the use of commodity derivatives to manage our price exposure to inventory positions or to fix margins on certain future sales volumes. The difference between the two periods reflects the derivative transactions that were either settled or marked to market during each respective period. The increased loss for 2005, was primarily attributable to movements in market prices.
Other Income (Expense), Net. Other expense was $0.5 million for 2005, compared to $0.2 million for 2004.
Income Tax Expense. Prior to January 2006, Western Refining LP had not incurred income taxes because its operations were conducted by an operating partnership that was not subject to income taxes. Partnership capital distributions were periodically made to the partners to fund the tax obligations resulting from the partners’ being taxed on their proportionate share of the partnership’s taxable income. However, Western Refining, Inc. incurred a minor income tax benefit related to its operations from September 16 to December 31, 2005.
Net Income. Net income was $201.1 million for 2005, compared to $67.5 million for 2004, an increase of $133.6 million, or 197.9%. This increase was attributable to the various factors discussed above. Net income for the twelve months ended December 31, 2005, did not include a provision for income taxes for Western Refining LP because we were a partnership and those taxes were the responsibility of the partners. However, net income for the twelve months ended December 31, 2005 included a minor tax benefit of $18,000 related to the operations of Western Refining, Inc. for the period of September 16 to December 31, 2005.
Liquidity and Capital Resources
Cash Flows
The following table sets forth our cash flows for the years ended December 31, 2006, 2005 and 2004:
Cash Flows Provided By Operating Activities
Net cash provided by operating activities for 2006, was $245.0 million. The most significant provider of cash was our net income ($204.8 million). Also contributing to our cash flows from operating activities were adjustments to net income for non-cash items such as deferred income taxes ($25.3 million), depreciation and amortization ($13.6 million) and stock-based compensation ($14.2 million). These increases in cash were partially offset by a net cash outflow from the change in operating assets and liabilities ($13.9 million). Net cash provided by operating activities for 2005 was $261.0 million. The most significant provider of cash for 2005 was our net income ($201.1 million). The other significant provider of cash during 2005 was a net cash inflow from the change in operating assets and liabilities ($48.2 million). Net cash provided by operating activities for 2004 was $87.0 million. The most significant cash providers were our net income ($67.5 million) and a net cash inflow from the change in operating assets and liabilities ($12.1 million).
Cash Flows Used In Investing Activities
Net cash used in investing activities for 2006 was $149.6 million, consisting of $29.3 million of an escrow deposit and other costs related to the Giant acquisition, and capital expenditures of $120.2 million. Total capital spending for 2006 included the purchase of the asphalt plant and terminals ($20.0 million), capital improvements to our acid and sulfur gas facilities ($24.3 million), spending on our ultra low sulfur diesel project ($16.8 million) and a related hydrogen plant ($16.6 million), our crude oil capacity expansion project ($10.4 million) and a new flare gas recovery system on the South Refinery ($6.2 million), as well as other small improvement and regulatory projects. Excluding the potential acquisition of Giant, we expect to spend approximately $128 million in capital expenditures for 2007. Net cash used in investing activities for 2005 was $88.0 million, all relating to capital expenditures, primarily our ultra low sulfur diesel project and small improvement projects.
Cash Flows Used In Financing Activities
Net cash used in financing activities for 2006 was $13.1 million compared to $37.1 million of cash used in financing activities for 2005. Cash provided by financing activities for 2006 included $295.6 million of net proceeds from our initial public offering less stock issuance costs, which were used for the debt repayment of $149.5 million and capital distributions paid to the partners of $147.7 million immediately prior to the consummation of our initial public offering. Net cash used in financing activities for 2006 also included the payment of dividends of $8.2 million and repurchases of common stock of $5.1 million to cover payroll withholding taxes for certain employees pursuant to the vesting of restricted shares awarded under our Long-Term Incentive Plan. Net cash used in financing activities for 2005 was $37.1 million. Net cash used in financing activities for 2004 was $86.7 million. Cash provided by financing activities for 2005 included $150 million in loan proceeds from a term loan facility entered into in July 2005. The primary uses of cash for 2005 were for debt repayments of $55.5 million primarily related to the prior term loan, capital distributions of $126.8 million to the partners, primarily to cover their partnership tax obligations and as discretionary distributions, and debt issuance costs of $4.9 million related to the new term loan and revolving credit facilities.
Working Capital
Our primary sources of liquidity are cash generated from our operating activities, existing cash balances and existing revolving credit facility. We believe that our cash flows from operations and borrowings under our revolving credit facility will be sufficient to satisfy our expected cash needs associated with our existing operations over the next 12-month period. Our ability to generate sufficient cash flow from our operating activities will continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined products at margins sufficient to cover fixed and variable expenses. In addition, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. See Item 1A. “Risk Factors.”
Working capital at December 31, 2006, was $276.7 million, consisting of $620.7 million in current assets and $344.0 million in current liabilities. Working capital at December 31, 2005, was $182.7 million, consisting of $488.9 million in current assets and $306.2 million in current liabilities. In addition, we had available borrowing capacity under our revolving credit facility of $92.9 million at December 31, 2006.
Indebtedness
At December 31, 2006, we had $57.1 million of letters of credit outstanding under our revolving credit facility, which reduced availability under that facility. See “- Letters of Credit,” below.
Revolving Credit Facility. In July 2005, Western Refining LP entered into the revolving credit facility with a group of banks led by Bank of America, N.A., which was amended and restated in January 2006 in connection with the closing of our initial public offering to add Western Refining, Inc. as a co-borrower and to lower the interest rates and fees charged on the facility. The revolving credit facility matures on July 28, 2010. The revolving credit facility is a collateral-based facility with total borrowing capacity, subject to borrowing base amounts based upon eligible receivables and inventory, of up to $150 million (which can be expanded to $200 million), and provides for letters of credit and swing line loans. There was no debt outstanding under the revolving credit facility at Deceember 31, 2006, and as of that date, we had availability of $92.9 million due to outstanding letters of credit. See “- Letters of Credit.” The revolving credit facility, secured by certain cash, accounts receivable and inventory, can be used for working capital and capital expenditures, certain permitted distributions and general corporate purposes. The revolving credit facility, as amended and restated in January 2006, provides for an initial quarterly commitment fee of 0.25% per annum, subject to adjustment based upon our consolidated leverage ratio, and letter of credit fees of 1.375% per annum payable quarterly, subject to adjustment based upon our consolidated leverage ratio. Borrowing rates are initially based on LIBOR plus 1.375%, subject to adjustment based upon our consolidated leverage ratio. Availability under the revolving credit facility is subject to the accuracy of representations and warranties and absence of a default. The revolving credit facility contains customary restrictive covenants, including limitations on debt, investments and dividends and financial covenants relating to minimum net worth, minimum interest coverage and maximum leverage. We were in compliance with these covenants at December 31, 2006. In addition, the revolving credit facility contains an event of default provision that will be triggered if the combined voting equity interests of the prior owners of Western Refining LP fall below 30% of the voting interests in Western Refining, Inc., or if Western Refining LP ceases to be a wholly-owned subsidiary of Western Refining, Inc.
Term Loan Facility. In July 2005, we also entered into the delayed-draw term loan facility arranged by Banc of America Securities LLC. The term loan facility had a maturity date of July 27, 2012, but was paid in full and terminated in January 2006 with proceeds from our initial public offering. The term loan facility provided for loans of up to $200 million, which were available in $150 million and $50 million tranches. We borrowed $150.0 million under this facility on July 29, 2005, and subject to certain conditions, the remaining $50 million under the term loan facility could have been borrowed at any time until November 30, 2005. On October 28, 2005, we elected to terminate the remaining $50 million of availability under the term loan facility. In December 2005, we made a required principal payment of $0.5 million, thereby leaving an outstanding principal balance under the term loan facility of $149.5 million at December 31, 2005. The term loan facility, which was secured by our fixed assets, including our refinery, was used to refinance certain of our indebtedness and could have been used for working capital and capital expenditures, certain permitted distributions and general business purposes. The term loan facility provided for a commitment fee of 0.75% per annum on the $50 million tranche until it was terminated. Borrowing rates were initially based on LIBOR plus 2.5% or prime plus 1.5%, which decreased upon achievement of certain rating targets. The term loan facility contained customary restrictive covenants, including limitations on debt, investments and dividends and financial covenants relating to minimum equity, minimum interest coverage and maximum leverage. In addition, the term loan facility contained an event of default provision that would have been triggered if the current beneficial ownership of Western Refining LP fell below 30%.
Future indebtedness due to potential acquisition of Giant. On August 26, 2006, we entered into a definitive merger agreement with Giant, under which we would acquire all of the outstanding shares of Giant.
On November 12, 2006, the parties entered into an amendment to the merger agreement. If the transaction closes, we will acquire Giant’s common stock for $77.00 per share in cash. The transaction has been approved by the board of directors of both companies. On February 27, 2007, Giant’s shareholders voted to approve the transaction. The transaction will be funded through a combination of cash on hand and $1.9 billion commitment from Bank of America consisting of up to a $1.4 billion secured term loan and a $500 million secured revolving credit facility.
Following the closing of the merger, we will generate revenue from four different refineries as well as a diverse mix of complimentary retail and wholesale businesses. We expect the merger to be immediately accretive to our earnings per share excluding one-time transaction costs, and believe that our expected cash flows will be sufficient to fulfill the financing obligations incurred as a result of this transaction.
Letters of Credit
Our revolving credit facility provides for the issuance of letters of credit. We issue letters of credit and cancel or amend them on a monthly basis depending upon our need to secure crude oil purchases. At December 31, 2006, there were $57.1 million of irrevocable letters of credit outstanding, issued almost exclusively to crude oil suppliers.
Capital Spending
Capital expenditures totaled approximately $120.2 million for the year ended December 31, 2006, and included the purchase of the asphalt plant and terminals, spending on facilities to support the acid and sulfur gas facilities, our ultra low sulfur diesel project and a related hydrogen plant, our crude oil capacity expansion project and a new flare gas recovery system on the South Refinery, as well as other small improvement and regulatory projects.
Our capital expenditure budget for 2007 is $128 million (excluding Giant), which we plan to allocate between sustaining maintenance, discretionary and regulatory projects as follows:
Sustaining Maintenance. Sustaining maintenance capital expenditures are those related to minor replacement of assets, major repairs and maintenance of equipment and other recurring capital expenditures.
Discretionary Projects. Discretionary project capital expenditures are those driven primarily by the economic returns that such projects can generate for us. Our discretionary projects include crude unit debottlenecking and reliability projects as well as infrastructure needs supporting further souring up of the crude slate at the El Paso refinery and the completion of the acid and sulfur gas facilities by the end of 2007.
Regulatory Projects. Regulatory projects are undertaken to comply with various regulatory requirements. Our low sulfur fuel projects are regulatory investments, driven primarily by our need to meet low sulfur fuel regulations. As of December 31, 2006, we had invested approximately $62.1 million in our ultra low sulfur diesel project, which was completed during the second quarter of 2006. The estimated cost of complying with the low sulfur gasoline specifications is $187 million, of which $1.5 million was spent through December 31, 2006 with the rest expected to be incurred through 2009. Based on current negotiations and information, the Company has estimated the total capital expenditures that may be required pursuant to the Petroleum Refinery Enforcement Initiative from the EPA would be approximately $22 million. These capital expenditures would primarily be for installation of a flare gas recovery system on the south-side of our refinery and installation of nitrogen oxides, or NOx, emission controls. As of December 31, 2006, we had invested $6.2 million on the flare gas recovery system with the remaining $7.8 million budgeted to be spent in 2007. Estimated
expenditures for the NOx emission controls project of $8.0 million will occur from 2007 through 2013. See Item 1, “Business - Environmental Regulation.”
The estimated capital expenditures for regulatory projects described above for the next three years are summarized in the table below:
Contractual Obligations and Commercial Commitments
Information regarding our contractual obligations, excluding those that could arise with the approval of the merger agreements relating to the acquisition of Giant Industries, Inc., of the types described below as of December 31, 2006, is set forth in the following table (in thousands):
(1)
In June 2005, we entered into a sulfuric acid regeneration and sulfur gas processing agreement with E.I. du Pont de Nemours, or “DuPont”. Under the agreement, we have a long-term commitment to purchase services for use by our refinery. Upon completion of the project, which is expected to occur by the end of 2007, the annual commitment for these services will range from $10.0 million increasing to $16.0 million per year over the next 20 years. Prior to this agreement, we incurred direct operating expenses related to sulfuric acid regeneration under a short-term agreement. The future payments are not included in the table, as payments do not commence until completion of the project.
(2)
In August 2005, we entered into a Throughput and Distribution Agreement and associated Storage Agreement with Magellan Pipeline Company, L.P. Under these agreements, we have a long-term commitment that began in February 2006 to provide for the transportation and storage of alkylate and other refined products from the Gulf Coast to our refinery via the Magellan South System. The minimum payment commitments are included in the table.
(3)
In May 2006, we entered into an asphalt storage and distribution services agreement with Tucson Electric Power, which will remain in effect until October 31, 2010. The monthly fees are included in this table.
(4)
We are obligated to make future expenditures related to our pension and post-retirement obligations. These payments are not fixed and cannot be reasonably determined beyond 2016; therefore, our obligations beyond 2016 related to these plans are not included in the table. Our pension and post-retirement obligations are discussed in Note 8 to the Notes to Consolidated Financial Statements.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosure About Market Risk
Changes in commodity prices and interest rates are our primary sources of market risk.
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 turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. We may utilize the commodity futures market to manage these anticipated inventory variances.
We maintain inventories of crude oil, other feedstocks and blendstocks, 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, 2006, we held approximately 3.9 million barrels of crude oil, refined product and other inventories valued under the LIFO valuation method with an average cost of $41.09 per barrel. As of December 31, 2005, we held approximately 3.8 million barrels of crude oil, refined product and other inventories at an average cost of $38.05 per barrel under LIFO. As of December 31, 2006 and 2005, current cost exceeded the carrying value of LIFO costs by $82.5 million and $80.0 million, respectively. We refer to this excess as our LIFO reserve.
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 other income (expense) section as gain (loss) from derivative activities.
We selectively utilize commodity derivatives to manage our price exposure to inventory positions or to fix margins on certain future sales volumes. The commodity derivative instruments may take the form of futures contracts or price swaps and are entered into with counterparties that we believe to be creditworthy. We have elected not to designate these instruments as cash flow hedges for financial accounting purposes. Therefore, changes in the fair value of these derivative instruments are included in income in the period of change. Net gains or losses are reflected in gain (loss) from derivative activities at the end of each period. For the year ended December 31, 2006 we had $8.8 million in net realized and unrealized gains accounted for using mark-to-market accounting. For the year ended December 31, 2005 we had $8.1 million in net realized and unrealized losses accounted for using mark-to-market accounting.
At December 31, 2006, we had open commodity derivative instruments consisting of price swaps on 425,000 barrels of refined products, primarily to fix margins on first quarter 2007 refined product sales. These open instruments had total unrealized net gains of approximately $1.4 million. At December 31, 2005, we had open commodity derivative instruments consisting of price swaps on 350,000 barrels of refined products, primarily to fix margins on first quarter 2006 refined products sales. These open instruments had total unrealized net gains of $0.2 million.
During 2006 and 2005, we did not have any derivative instruments that were designated and accounted for as hedges.
Interest Rate Risk
As of December 31, 2006, we did not have any outstanding debt; as such, we were not exposed to any variable interest rate risk.
Item 8.
Item 8.
Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors of Western Refining, Inc.
We have audited the accompanying consolidated balance sheets of Western Refining, Inc. and Subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and partners’ capital, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Western Refining, Inc. and Subsidiaries at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 8 to the consolidated financial statements, in December 2006, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”
/s/ Ernst & Young LLP
Dallas, Texas
March 2, 2007
WESTERN REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
WESTERN REFINING, 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.
WESTERN REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN
STOCKHOLDERS’ EQUITY AND PARTNERS’ CAPITAL
(In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
WESTERN REFINING COMPANY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31,
1.
Organization and Basis of Presentation
The “Company” may be used to refer to Western Refining, Inc. and, unless the context otherwise requires, its subsidiaries. Any references to the “Company” as of a date prior to September 16, 2005 (the date of Western Refining, Inc.’s formation) are to Western Refining Company, L.P. (“Western Refining LP”).
The Company, through its subsidiary, Western Refining LP, is engaged in the business of refining crude oil into gasoline, diesel fuels, asphalt, and other refined products, and selling its products, as well as refined products purchased from third parties, to various customers located in the Southwest region of the U.S. and Mexico. The Company operates as one business segment.
On January 24, 2006, the Company completed an initial public offering of 18,750,000 shares of its common stock, and selling stockholders sold an aggregate of 7,125,000 shares (including over-allotment) of common stock held by them. The initial public offering price was $17.00 per share. The net proceeds to the Company from the sale of 18,750,000 shares of its common stock were approximately $297.2 million, after deducting underwriting discounts and commissions. The Company also incurred approximately $1.7 million of other costs related to the initial public offering. The Company did not receive any of the net proceeds from sales of shares of common stock by any selling stockholders. The net proceeds from this offering were used as follows:
•
to repay Western Refining LP’s $149.5 million of outstanding term loan debt; and
•
to replenish cash that was used to fund a $147.7 million distribution to the partners of Western Refining LP immediately prior to the completion of the offering.
Associated with the repayment of the outstanding term loan debt discussed above, the Company recorded a write-off of unamortized loan fees of $2.0 million in the first quarter of 2006.
Also in connection with the initial public offering, pursuant to a contribution agreement, a reorganization of entities under common control was consummated whereby the Company became the indirect owner of Western Refining LP and all of its refinery assets. This reorganization was accomplished by the Company issuing 47,692,900 shares of its common stock to certain entities controlled by its majority stockholder in exchange for the membership and partner interests in the entities that owned Western Refining LP. Immediately following the completion of the offering, there were 66,443,000 shares of common stock outstanding, excluding any restricted shares issued. As of December 31, 2006, the Company had issued 2,016,024 shares of restricted stock. See Note 10, “Stock-Based Compensation,” for a further discussion of the restricted stock issued.
Historically, Western Refining LP had not incurred income taxes because its operations were conducted by an operating partnership that was not subject to income taxes. Partnership capital distributions were periodically made to the partners to fund the tax obligations resulting from the partners being taxed on their proportionate share of the partnership’s taxable income. As a consequence of the initial public offering and the change in structure noted above, the Company is required to recognize deferred tax assets and liabilities to reflect net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial and tax reporting purposes. See Note 6, “Income Taxes.”
Demand for gasoline is generally higher during the summer months than during the winter months. In addition, oxygenate is added to the gasoline in the Company’s service areas during the winter months, thereby increasing the supply of gasoline. This combination of decreased demand and increased supply during the winter months can lower prices in the winter months. As a result, the Company’s operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year.
WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
The accompanying consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for financial information and with the instructions to Form 10-K and Article 10 of Regulation S-X. The initial public offering and the resulting reorganization of entities under common control constituted a change in reporting entity. As such, these consolidated financial statements reflect the financial position, results of operations and cash flows as if Western Refining, Inc. and Western Refining LP were combined for all of 2006 and 2005. All intercompany balances and transactions have been eliminated for these periods. The financial information prior to 2005 has been derived from the audited financial statements of our predecessor, Western Refining LP. Operating results for the year ended December 31, 2006, are not necessarily indicative of the results that may be expected for the future.
The International Union of Operating Engineers represents the hourly workforce at the Company’s El Paso, Texas, refinery pursuant to an agreement that expires in April 2009. At December 31, 2006, there were 231 employees represented by the union and 416 total employees.
2.
Summary of Accounting Policies
Principles of Consolidation
Western Refining, Inc. (the “Company”) was formed on September 16, 2005, as a holding company in connection with its proposed initial public offering. In January 2006, the Company completed its initial public offering of its common stock. In connection with the offering, pursuant to a contribution agreement, a reorganization of entities under common control was consummated whereby the Company became the indirect owner of Western Refining Company, L.P. and all of its refinery assets. The accompanying consolidated financial statements reflect the financial position, results of operations and cash flows as if Western Refining, Inc. and Western Refining LP were combined for 2006 and 2005. All intercompany balances and transactions have been eliminated for these periods. The financial information prior to 2005 has been derived from the audited financial statements of our predecessor, Western Refining LP.
Cash Equivalents
Cash equivalents consist of investments in money market accounts. The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Accounts Receivable
Accounts receivable are due from a diverse customer base including companies in the petroleum industry, railroads, airlines and the federal government. Credit is extended based on an evaluation of the customer’s financial condition. Historically, the Company has not had any credit losses; therefore, it does not currently maintain an allowance for doubtful accounts.
Inventories
Crude oil, refined product and other feedstock and blendstock inventories are carried at the lower of cost or market. Cost is determined principally under the last-in, first-out (“LIFO”) valuation method to reflect a better matching of costs and revenues. Ending inventory costs in excess of market value are written down to net realizable market values and charged to cost of products sold in the period recorded. In subsequent periods, a new lower of cost or market determination is made based upon current circumstances.
Property, Plant, and Equipment
Property, plant, and equipment are stated at cost. The Company capitalizes interest on expenditures for capital projects in process greater than one year until such projects are ready for their intended use. No interest
WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
was capitalized in 2004, approximately $1.3 million of interest was capitalized in 2005 and less than $0.1 million was capitalized in 2006 since the Company retired its long-term debt in January 2006.
Depreciation is provided on the straight-line method at rates based upon the estimated useful lives of the various classes of depreciable assets. The lives used in computing depreciation for such assets are as follows: refinery and related equipment, 4 to 20 years; and computers, software and other depreciable assets, 3 to 5 years.
Other Assets
Other assets consist of loan origination fees, license agreements and other assets that are related to the various refinery process units and are stated at cost. Amortization is provided on a straight-line basis over the term of the note or over the life of the process units.
Also included in other assets are $29.3 million of escrow deposits and costs at December 31, 2006, relating to the proposed acquisition of Giant Industries, Inc. (“Giant”).
Revenue Recognition
Revenues for products sold are recorded upon delivery of the products to customers, which is the point at which title is transferred, the customer has the assumed risk of loss, and when payment has been received or collection is reasonably assured. Transportation, shipping and handling costs incurred are included in cost of products sold. Excise and other taxes collected from customers and remitted to governmental authorities are not included in revenue.
On April 1, 2006, the Company adopted Emerging Issues Task Force (“EITF”) Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. This Issue addresses accounting matters that arise when one company both sells inventory to and buys inventory from another company in the same line of business. Specifically, the Issue addresses when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The application of Issue No. 04-13 reduced net sales and cost of products sold by $144.1 million for the period from April 1 to December 31, 2006. If the Issue had been effective at January 1, 2006, our net sales and cost of products sold would have been reduced by $171.9 million for the full calendar year.
Cost Classifications
Cost of products sold includes cost of crude oil, other feedstocks, blendstocks, purchased finished products, transportation and distribution costs. Direct operating expenses include direct costs of labor, maintenance materials and services, chemicals and catalysts, natural gas, utilities, and other direct operating expenses.
Maintenance Turnaround Expense
Refinery process units require regular major maintenance and repairs which are commonly referred to as “turnarounds.” The required frequency of the maintenance varies by unit, but generally is every four years. Turnaround costs are expensed as incurred.
Deferred Compensation
Deferred compensation agreements executed in 2003 and 2004 between certain employees and its limited partner, as amended in November and December 2005, were historically deemed to be a non-cash capital
WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
contribution of the limited partner. Expense was recognized ratably over the vesting periods of the individual participants based upon the value of such agreements, as defined. Deferred compensation expense was recorded as selling, general and administrative expenses in the accompanying statements of operations. Deferred compensation expense was $24.0 million and $4.0 million for the year ended December 31, 2005 and 2004, respectively.
In November and December 2005, Western Refining LP, its then limited partner and Western Refining, Inc. amended the deferred compensation agreements executed in 2003 and 2004 between certain employees and its then limited partner. Pursuant to the amended agreements, the Company assumed the obligation of its then limited partner and the deferred compensation agreements were terminated in exchange for a cash payment of $28.0 million to the participants in such plan plus the granting of restricted stock, which will vest ratably over a two-year period. The $28.0 million cash payment was made in January 2006 following the sale of Western Refining, Inc.’s common stock in connection with its initial public offering. In addition, approximately 1.8 million shares of restricted stock having a value of $30.1 million at the date of grant were granted in January 2006 to the prior deferred compensation participants. The value of such restricted shares will be expensed over a two-year period.
Stock-based Compensation
Concurrent with the Company’s initial public offering of common stock on January 24, 2006, the Company adopted SFAS No. 123 (revised) Shared-Based Payment (“SFAS No. 123R”) to account for stock awards granted under its Long-Term Incentive Plan. Under SFAS No. 123R, the cost of employee services received in exchange for an award of equity instruments is measured based on the grant-date fair vale of the award (with some limited exceptions). The fair value of each share of restricted stock awarded was measured based on the market price at closing as of the measurement date and is amortized on a straight-line basis over the respective vesting periods.
As of December 31, 2006, there had been 2,016,024 shares of restricted stock awarded. Although ownership of the shares does not transfer to the recipients until the shares have vested, recipients have voting and nonforfeitable dividend rights on these shares from the date of grant. See Note 10 “Stock-Based Compensation.”
Financial Instruments and Fair Value
Financial instruments that potentially subject the Company to concentrations of credit risk primarily consist of accounts receivable. Those customers accounting for more than 10% of the Company’s revenues in 2006 were Chevron Corporation (“Chevron”), Phoenix Fuel Company (“Phoenix Fuel”), which is a wholly owned subsidiary of Giant, and PMI Trading Limited, an affiliate of PEMEX, (“PMI”), (see Note 15, “Concentration of Risk”). Credit risk is minimized as a result of the credit quality of the Company’s customer base. As a result, the Company has not had any credit losses associated with its accounts receivable.
The carrying amounts of cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their fair values due to their short-term maturities.
The Company enters into crude oil and refined product forward contracts to facilitate the supply of crude oil to the refinery and the sale of refined products. We believe that these contracts qualify for the normal purchases and normal sales exception under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, (“SFAS No. 133”) because deliveries under the contracts will be in quantities expected to be used or sold over a reasonable period of time in the normal course of business. These transactions are reflected in cost of products sold in the period in which delivery of the crude oil takes place.
WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
In addition, the Company maintains a refined products pricing strategy, which includes the use of forward and swap contracts, to minimize significant fluctuations in earnings caused by the volatility of refined products prices. The estimated fair values of forward and swap contracts are based on quoted market prices and generally have maturities of three months or less. These transactions historically have not qualified for hedge accounting in accordance with SFAS No. 133 and, accordingly, these instruments are marked to market at each period end and are included in other current assets or other current liabilities. Gains and losses related to these instruments are included in the statement of operations as gains (losses) from derivative activities.
The Company does not believe that there is a significant credit risk associated with the Company’s derivative instruments, which are transacted through counterparties meeting established collateral and credit criteria.
Pension and Other Post-Retirement Obligations
Pension and other post-retirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, and assumed discount rates and demographic data.
In December 2005, the Company adopted 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 on the accounting for, and disclosure of, the effects of the Medicare Prescription Act. The accompanying financial statements reflect the effects of the Act on the accumulated postretirement benefit obligation and net postretirement benefit cost.
In December 2006, the Company adopted SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment to FASB Statements No. 87, 88, 106 and 132R, (“SFAS No. 158”), which requires companies to fully recognize the obligations associated with single-employer defined benefit pension, retiree healthcare, and other postretirement plans in their financial statements. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements. Under SFAS No. 158, a defined benefit postretirement plan sponsor must (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for the plan’s underfunded status, (b) measure the plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as components of net periodic benefit cost. See Note 8, “Retirement Plans.”
Asset Retirement Obligations
The Company does not have any material asset retirement obligations for which it would be required to record the fair value of a liability as required under Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.
Environmental and Other Loss Contingencies
The Company records liabilities for loss contingencies, including environmental remediation costs, when such losses are probable and can be reasonably estimated. Environmental costs are expensed if they relate to an existing condition caused by past operations with no future economic benefit. Estimates of projected environmental costs are made based upon internal and third-party assessments of contamination, available remediation technology and environmental regulations. Loss contingency accruals, including those for environmental remediation, are subject to revision as further information develops or circumstances change and such
WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
accruals can take into account the legal liability of other parties. See Note 14, “Commitments and Contingencies.”
Income Taxes
Prior to January 2006, Western Refining LP had not incurred income taxes because its operations were conducted by an operating partnership that was not subject to income taxes. Partnership capital distributions were periodically made to the partners to fund the tax obligations resulting from the partners being taxed on their proportionate share of the partnership’s taxable income. However, Western Refining, Inc. incurred a minor income tax benefit related to its operations from September 16 (inception) to December 31, 2005. See Note 6, “Income Taxes.”
As a consequence of the initial public offering and change in corporate structure, in January 2006, the Company now recognizes deferred tax assets and liabilities to reflect net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial and tax reporting purposes. During 2006, the Company recorded income tax expense of $8.3 million for the cumulative effect of recording its estimated net deferred tax liability. Deferred amounts are measured using enacted tax rates assumed to be in effect when the temporary differences reverse.
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP 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 financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassifications
Certain amounts in the prior years’ financial statements have been reclassified to conform to the 2006 presentation.
New Accounting Pronouncements
In February 2006, the Financial Accounting Standards Board (“FASB”), issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments - an amendment to FASB Statements No. 133 and 140 (“SFAS No. 155”), which provides entities with relief from having to separately determine the fair value of an embedded derivative that would otherwise be required to be bifurcarted from its host contract in accordance with SFAS No. 133. SFAS No. 155 is effective for fiscal years beginning after September 15, 2006. We believe that SFAS No. 155 will not have a material effect on our financial position or results of operations.
In June 2006, the FASB released Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in the financial statements of a company in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. Application of FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company believes FIN 48 will not have a material effect in the Company’s financial position or results of operations.
In September 2006, the FASB published SFAS No. 157, Fair Value Measurements (“SFAS No. 157”), to eliminate the diversity in practice that exists due to the different definitions of fair value and the limited guidance for applying those definitions in GAAP that are dispersed among the many accounting
WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
pronouncements that require fair value measurements. SFAS No. 157 retains the exchange price notion in earlier definition of fair value, but clarifies that the exchange price is the price in an orderly transaction between market participants to sell an asset or liability in the principal or most advantageous market for the asset or liability. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price), as opposed to the price that would be paid to acquire the asset or received to assume the liability at the measurement date (an entry price). SFAS No. 157 expands disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The guidance in this Statement applies for derivatives and other financial instruments measured at fair value under SFAS No. 133 at initial recognition and in all subsequent periods. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, although earlier application is encouraged. The Company is evaluating the impact, if any, that SFAS No. 157 will have in the Company’s financial position or results of operations.
In September 2005, the SEC staff published Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in the Current Year Financial Statements (“SAB 108”), which expresses the SEC staff’s views on the proper method for quantifying errors when there were uncorrected errors in the prior year. SAB 108 requires quantification of financial statement errors based on the effects of both the balance sheet (iron curtain method) and income statement (rollover method). SAB 108 is effective for fiscal years ending after November 15, 2006. The Company believes SAB 108 will not have an effect on our financial position or results of operations.
3.
Inventories
Inventories were as follows:
The Company determines market value inventory adjustments by evaluating crude oil and refined products inventory on an aggregate basis. The excess of the current cost of inventories over LIFO cost was $82.5 million and $80.0 million at December 31, 2006 and 2005, respectively.
WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
4.
Property, Plant, and Equipment
Property, plant, and equipment were as follows:
The useful lives of depreciable assets used to determine depreciation expense were as follows:
5.
Other Assets, Net of Amortization
Other assets, net of amortization consisted of the following:
6.
Income Taxes
As discussed in Note 1, “Organization and Basis of Presentation,” as a consequence of the initial public offering and the change in corporate structure, the Company is required to recognize deferred tax assets and liabilities to reflect net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial and tax reporting purposes. In connection with the change to a corporate holding company structure immediately prior to the closing of the initial public offering, the Company recorded income tax expense of $8.3 million during 2006 for the cumulative effect of recording its estimated net deferred tax liability. The impact of recording the estimated net deferred tax liability decreased diluted earnings per share by $0.13 for the twelve months ended December 31, 2006. In addition, the Company began recording a current provision for income taxes during the first quarter of 2006.
WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
The following is an analysis of the Company’s consolidated income tax expense for the year ended December 31, 2006:
The following is a reconciliation of total income tax expense to income taxes computed by applying the statutory federal income tax rate (35%) to income before income tax expense for the year ended December 31, 2006:
In 2006, the effective tax rate was 35.4%, including the one-time charge of $8.3 million recognized upon the change to a corporate holding company structure and the resulting change to a taxable entity. This one-time charge increased the effective tax rate by 2.6% for 2006.
WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
The tax effects of significant temporary differences representing deferred income tax assets and liabilities as of December 31, 2006 were as follows:
The following table presents the computation of unaudited pro forma income tax expense and unaudited pro forma net income for the years ended December 31, 2005 and 2004:
The unaudited pro forma provision for income tax information presented in the table above, represents the tax effects that would have been reported had the Company and its subsidiaries been subject to federal and state income taxes as a corporation for all periods presented. The unaudited pro forma income tax expense reflects a blended statutory rate of 35.7%. This rate includes a federal rate of 35.0% and a state income tax rate of 0.7% (net of federal benefit). Actual rates and income tax expenses could have differed had the Company been subject to federal and state income taxes for all periods presented. Therefore, the unaudited pro forma amounts are for informational purposes only and are intended to be indicative of the results of operations had the Company been subject to federal and state income taxes for all periods presented.
In May 2006, the State of Texas enacted a new business tax that is imposed on our gross margin to replace the State’s current franchise tax regime. The new legislation’s effective date is January 1, 2008, which means that our first Texas Margins Tax (“TMT”) return will not become due until May 15, 2008, and will be based on our 2007 operations. Although the new TMT is imposed on an entity’s gross margin rather than on its net income, certain aspects of the tax make it similar to an income tax. The impact of the TMT is expected to increase the Company’s effective tax rate by up to 1%. In accordance with the guidance provided in
WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
SFAS No. 109, Accounting for Income Taxes, the Company has properly considered and will continue to account for the impact of the newly-enacted legislation in the determination of its state income tax liability.
7.
Long-Term Debt
Long-term debt at December 31, 2006 and 2005 consisted of the following:
In July 2005, the Company entered into the delayed-draw term loan facility (“New Term Loan”) arranged by Banc of America Securities LLC. The New Term Loan had a maturity date of July 27, 2012. The New Term Loan provided for loans of up to $200 million, which were available in $150 million and $50 million tranches. The Company borrowed $150.0 million under this facility on July 29, 2005, and subject to certain conditions, the remaining $50 million under the New Term Loan could have been borrowed at any time until November 30, 2005. On October 28, 2005, the Company elected to terminate the remaining $50 million of availability under the New Term Loan. The outstanding principal balance was $149.5 million at December 31, 2005. The New Term Loan, which was secured by the Company’s fixed assets, including its refinery, was used to refinance certain of the Company’s indebtedness and could have been used for working capital and capital expenditures, certain permitted distributions and general business purposes. The New Term Loan provided for a commitment fee of 0.75% per annum on the $50 million tranche until it was terminated. Borrowing rates were initially based on LIBOR plus 2.5% or prime plus 1.5%, which decreased upon achievement of certain rating targets. The New Term Loan contained customary restrictive covenants, including limitations on debt, investments and dividends and financial covenants relating to minimum equity, minimum interest coverage and maximum leverage. The Company was in compliance with these covenants at December 31, 2005. In addition, the New Term Loan contained an event of default provision that would have been triggered if the current beneficial ownership of the Company fell below 30%. The New Term Loan was paid in full on January 24, 2006, with proceeds from the Company’s initial public offering, and the facility was terminated.
On August 29, 2003, the Company and Kaston Pipeline Company, L.P. (“Kaston”), an affiliate of the Company until August 31, 2004, entered into a loan agreement with a bank syndicate for a term loan (“Old Term Loan”) in the amount of $125 million, of which $109.9 million was allocated to the Company based on the asset cost as defined in the purchase and sale agreement related to the acquisition of the North Refinery assets in 2003. The Old Term Loan was paid in full on July 29, 2005, with a portion of the proceeds from the New Term Loan.
In July 2005, the Company entered into the revolving credit facility (“New Revolver”) with a group of banks led by Bank of America, N.A., which was amended and restated on January 24, 2006, in connection with Western Refining, Inc.’s initial public offering to add Western Refining, Inc. as a co-borrower. The New Revolver matures on July 28, 2010. The New Revolver is a collateral-based facility with total borrowing capacity, subject to borrowing base amounts based upon eligible receivables and inventory, of up to $150 million (which can be expanded to $200 million), and provides for letters of credit and swing line loans. There was no debt outstanding under the New Revolver at December 31, 2006, and as of that date, the Company had availability of $92.9 million due to $57.1 million of outstanding letters of credit. The New Revolver, secured by certain cash, accounts receivable and inventory, can be used for working capital and capital expenditures, certain permitted distributions and general corporate purposes. The New Revolver provides for a quarterly commitment fee of 0.25% per annum,
WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
letter of credit fees of 1.375% per annum payable quarterly, and borrowing rates initially based on LIBOR plus 1.375%, each of which are subject to adjustment based upon Western Refining, Inc.’s consolidated leverage ratio. Availability under the New Revolver is subject to the accuracy of representations and warranties and absence of a default. The New Revolver contains customary restrictive covenants, including limitations on debt, investments and dividends and financial covenants relating to minimum net worth, minimum interest coverage and maximum leverage. The Company was in compliance with these covenants at December 31, 2006. In addition, the New Revolver contains an event of default provision that will be triggered if the current voting equity interests of the prior owners of Western Refining LP fall below 30% of the voting interests in Western Refining, Inc., or if Western Refining LP ceases to be a wholly owned subsidiary of Western Refining, Inc.
In connection with the July 2005 transactions, the Company incurred $4.9 million in new deferred financing costs that will be amortized over the life of the related facilities. In addition, the Company recorded an expense of $3.3 million related to the write-off of previously recorded deferred financing costs in July 2005. In connection with the repayment of the New Term Loan in January 2006, the Company recorded a write-off of unamortized loan fees of $2.0 million.
8.
Retirement Plans
In December 2006, the Company adopted SFAS No. 158, which requires companies to fully recognize the obligations associated with single-employer defined benefit pension, retiree healthcare, and other postretirement plans in their financial statements. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements. Under SFAS No. 158, a defined benefit postretirement plan sponsor must (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for the plan’s underfunded status, (b) measure the plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as components of net periodic benefit cost pursuant to SFAS No. 87, Employers’ Accounting for Pensions, or SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions. SFAS No. 158 also requires an employer to disclose in the notes to financial statements additional information on how delayed recognition of certain changes in the funded status of a defined benefit postretirement plan affects net periodic benefit cost for the next fiscal year.
Pensions
Effective September 1, 2003, and as part of the North Refinery asset acquisition, the Company adopted a new defined benefit pension plan covering certain previous employees of Chevron. Benefits under this plan are based primarily on years of service and compensation levels. The Company will make contributions to the plan sufficient to meet the minimum funding requirements of applicable laws and regulations. The plan assets are invested in equity securities and debt securities and are managed by professional investment managers.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
The following tables set forth significant information about the pension plan, the reconciliation of the benefit obligation, plan assets, funded status and significant assumptions and are based upon an annual measurement date of December 31:
(1)
Based upon historical long-term rates of return and the current returns of similarly invested portfolios.
The accumulated benefit obligation for the pension plan was $10.0 million and $4.7 million for 2006 and 2005, respectively. The Company expects to recognize in other comprehensive income approximately $0.8 million of net periodic benefit cost related to the amortization of actuarial loss during 2007.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
The table below provides information on the incremental effect of applying SFAS No. 158 on individual line items in the Company’s consolidated balance sheet as of December 31, 2006:
The primary investment strategy is the security and long-term stability of plan assets, combined with moderate growth that corresponds to participants’ anticipated retirement dates. Investments should also provide for sufficient liquid assets to allow the plan to make distributions on short notice to participants who have died or become disabled and are entitled to benefits. Pension plan assets at December 31, 2006, were held in equity securities (64.5%) and debt securities (35.5%). The Company contributed $3.9 million to the plan in January 2007 and does not intend to make any more contributions for the rest of 2007.
Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The assumed return on plan assets is based on management’s expectation of the long-term return on the portfolio of plan assets. The discount rate used to compute the present value of plan liabilities was 5.93%, based on rates of high grade corporate bonds with maturities similar to the average period over which benefits will be paid.
The following benefit payments, which reflect future service, are expected to be paid in the year indicated:
Post-Retirement Obligations
Concurrent with the North Refinery asset acquisition, the Company adopted a retiree medical plan covering certain previous employees of Chevron. Unlike the pension plan, the Company is not required to fund the retiree medical plan on an annual basis. Based on an annual measurement date of December 31, 2006 and a discount rate of 6.00%, the Company has accrued $1.6 million and expensed approximately $0.2 million for the twelve months ended December 31, 2006 under this plan.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
The components of the post-retirement obligation at December 31, 2006, are:
No benefits were paid for 2006. The following benefits payments are expected to be paid in the year indicated:
The health care cost trend rate for 2006 and future years is 4.0%. A 1%-point change in the assumed health care cost trend rate will have the following effect:
(1)
The 1-percentage point increase is not applicable because the maximum Company-provided contribution cannot increase by more than 4%.
Defined Contribution Plan
The Company sponsors a 401(k) defined contribution plan that covers substantially all employees. Under this plan, participants can contribute a percentage of their base pay. If the participant contributes a minimum of 2% of base pay, the Company will provide a match of 8% of the participant’s base pay, provided they have a minimum of one year of service with the Company. The Company expensed $3.2 million, $2.3 million and $1.8 million for the years ended December 31, 2006, 2005 and 2004, respectively, in connection with this plan.
9.
Crude Oil and Refined Product Risk Management
The Company enters into crude oil and refined product forward contracts to facilitate the supply of crude oil to the refinery and sale of refined products. For the year ended December 31, 2006, the Company entered into net forward, fixed-price contracts to purchase and sell crude oil and refined products which qualify as
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
normal purchases and normal sales and that are exempt from SFAS No. 133. At December 31, 2006, the Company had forward, fixed-price contracts to purchase crude oil of $0.4 million and sell crude oil of $0.1 million. At December 31, 2005, the Company had forward, fixed-price contracts to purchase crude oil for $1.8 million and to sell crude oil of $1.9 million.
The Company also uses crude oil and refined products futures or swap contracts to mitigate the change in value of volumes subject to market prices. Under a refined products swap contract, the Company agrees to buy or sell an amount equal to a fixed price times a set number of barrels, and to buy or sell in return an amount equal to a specified variable price times the same amount of barrels. The physical volumes are not exchanged, and no other cash payments are made. The contract fair value is reflected on the balance sheet and related net gain or loss is recorded as a gain (loss) from derivative activities in the statements of operations. Various third-party sources are used to determine fair values for the purpose of marking to market the derivative instruments at each period end. The fair value of the outstanding contracts at December 31, 2006, was a net unrealized gain of $1.4 million, of which $2.1 million was in current assets and $0.7 million in current liabilities. The Company realized a $7.5 million net gain from derivative activities on matured contracts during 2006. The fair value of the outstanding contracts at December 31, 2005 was a net unrealized gain of $0.2 million, of which $0.7 million was in current assets and $0.5 million in current liabilities. The Company realized an $8.3 million net loss from derivative activities on matured contracts during 2005. The fair value of the outstanding contracts at December 31, 2004, was a net unrealized gain of $2.0 million included in current assets. The Company realized a $6.0 million net loss from derivative activities on matured contracts during 2004.
10.
Stock-Based Compensation
In January 2006, 1,772,041 shares of restricted stock having an aggregate fair value of $30.1 million at the measurement date were granted to the prior deferred compensation participants of Western Refining LP. The vesting of such restricted shares will occur over a two-year period. In addition, there were 243,983 shares of restricted stock having an aggregate fair value of $4.6 million at the date of grant that were granted during 2006 to other employees and outside directors with vesting primarily over a three-year period. Although ownership of the shares does not transfer to the recipients until the shares have vested, recipients have voting and nonforfeitable dividend rights on these shares from the date of grant. The fair value of each share of restricted stock awarded was measured based on the market price as of the measurement date and will be amortized on a straight-line basis over the respective vesting periods.
Using a forfeiture rate of 0%, the Company recorded compensation expense of $14.2 million for the year ended December 31, 2006, of which $0.5 million was included in direct operating expenses and $13.7 million was included in selling, general and administrative expenses. No expense was capitalized in either period. The aggregate fair value at grant date of the shares vested during 2006 was $11.3 million. The related aggregate intrinsic value of these shares at the date of vesting was $15.7 million. The tax benefit related to the shares that vested during the year ended December 31, 2006 was $5.6 million.
As of December 31, 2006, there were 1,349,009 shares of restricted stock outstanding with an aggregate fair value at grant date of $23.4 million and an aggregate intrinsic value of $34.3 million. The compensation cost of nonvested awards not recognized as of December 31, 2006, was $20.5 million, which will be
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
recognized over a weighted average period of approximately 1.4 years. The following table summarizes the Company’s restricted stock activity for 2006:
The Company’s Board of Directors authorized the issuance of up to 5,000,000 shares of common stock under the Western Refining Long-Term Incentive Plan. As of December 31, 2006, there were 2,986,266 shares of common stock reserved for future grants under this plan.
11.
Stockholders’ Equity
On January 24, 2006, the Company completed an initial public offering of 18,750,000 shares of its common stock at an aggregate offering price of $318.8 million. The Company received approximately $297.2 million in net proceeds from the initial public offering. See Note 1, “Organization and Basis of Presentation”.
During the twelve months ended December 31, 2006, the Company repurchased 211,169 shares of its common stock at an aggregate cost of $5.1 million. These repurchases, which were recorded as treasury stock, were made to cover payroll withholding taxes for certain employees pursuant to the vesting of restricted shares awarded under the Company’s Long-Term Incentive Plan.
The Company paid $8.2 million in dividends for the first three quarters of 2006. On November 13, 2006, the Company announced its regular quarterly cash dividend of $0.04 per share on its common stock for the fourth quarter of 2006. The dividend was paid on January 25, 2007, to stockholders of record at the close of business on January 2, 2007. The total cash required for the dividend declared was $2.7 million and was reflected as “Dividends Payable” on the balance sheet as of December 31, 2006.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
Prior to 2006, the Company’s operations consisted of its subsidiary, Western Refining LP, an operating partnership. The following table presents the partnership capital accounts from December 31, 2003, through December 31, 2005:
12.
Earnings Per Share
On January 24, 2006, the Company completed the initial public offering of 18,750,000 shares of its common stock. Also in connection with the initial public offering, pursuant to a contribution agreement, a reorganization of entities under common control was consummated whereby the Company became the indirect owner of Western Refining LP and all of its refinery assets. This reorganization was accomplished by the Company issuing 47,692,900 shares of its common stock to certain entities controlled by its majority stockholder in exchange for the membership and partner interests in the entities that owned Western Refining LP. Immediately following the completion of the offering, there were 66,443,000 shares of common stock outstanding, excluding any restricted shares issued. See Note 1, “Organization and Basis of Presentation.”
The Company uses the treasury stock method to determine the amount of fully diluted shares outstanding. The computation of basic and diluted earnings per share for the year ended December 31, 2006, is presented below:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
13.
Related Party Transactions
On October 3, 2006, the Company entered into a new non-exclusive aircraft lease with an entity controlled by the Company’s major stockholder. The lease may be terminated at any time. The hourly rental payment will be $1,775 per flight hour and the Company is responsible for all operating and maintenance costs of the aircraft. Personal use of the aircraft by certain officers of the Company will be reimbursed to the Company at the highest rate allowed by the Federal Aviation Administration for a non-charter operator. In addition, the Company has a policy requiring that the officers deposit in advance of any personal use of the aircraft an amount equal to three months of anticipated expenses for the use of the aircraft. The Company believes that it leases the aircraft on terms no less favorable to it than would be obtained from an unaffiliated third party.
On December 13, 2004, the Company entered into a non-exclusive aircraft lease agreement with a related party controlled by the Company’s major stockholder. Pursuant to the lease agreement, the aircraft was leased by the Company at a rate of $600 per flight hour. In addition, the Company was responsible for all operating and maintenance costs associated with its use of the aircraft. The Company has a policy requiring that certain officers of the Company deposit in advance of any personal use of the aircraft an amount equal to three months of anticipated expenses for personal use of the aircraft. The officers reimburse the Company for personal use of the aircraft pursuant to a time sharing agreement. The aircraft was sold on December 4, 2006, and the lease agreement was terminated. The Company believes that it leased the aircraft on terms no less favorable to it than would be obtained from an unaffiliated third party. The following table summarizes the total costs incurred for the lease of both aircrafts for 2006 and 2005:
The Company had a promissory note due from Ascarate Group LLC (“Ascarate”), which was controlled by the Company’s major stockholder. Up to $2.0 million could have been advanced under the terms of the note. The note was secured by deeds of trust for certain properties located near the refinery. Principal plus accrued interest was due in full on June 1, 2010. Interest was payable quarterly at the prevailing prime rate, subject to a maximum of 12% per annum. The principal and accrued interest due as of December 31, 2005, was approximately $0.1 million. On January 31, 2006, the Company acquired the ownership interests in Ascarate for a nominal amount. Accordingly, Ascarate became a wholly-owned subsidiary of the Company and is no longer a related party.
The Company sells refined products to Transmountain Oil Company, L.C. (“Transmountain”), which is a distributor in the El Paso area. An entity controlled by the Company’s major stockholder acquired a 61.1% interest in Transmountain on June 30, 2004. Sales to Transmountain, at market-based rates, totaled $72.4 million and $75.2 million for the twelve months ended December 31, 2006 and 2005, respectively. From June 30, 2004 through December 31, 2004, the Company sold approximately $26.5 million of refined products to Transmountain. Total accounts receivable due from Transmountain were $1.4 million and $3.2 million as of December 31, 2006 and 2005, respectively.
The Company has entered into a lease agreement with Transmountain, whereby Transmountain leases certain office space from the Company at a market-based rate. The lease commenced on December 1, 2005,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
for a period of ten years and contains two five-year renewal options. The monthly base rental starts at $6,800, subject to adjustment at the end of the first five-year period based upon the change in the Consumer Price Index. Rental payments received from Transmountain were $81,606 for the twelve months ended December 31, 2006.
Western Refining LP recorded expenses related to deferred compensation agreements executed in 2003 and 2004 between certain employees and its limited partner, as amended in November and December 2005, which were historically deemed to be a non-cash capital contribution of the limited partner. Expense had been recognized ratably over the vesting periods of the individual participants based upon the value of such agreements, as defined. Through December 31, 2005, deferred compensation expense was recorded as selling, general and administrative expenses in the statements of operations. Deferred compensation expense of $24.0 million and $4.0 million was recorded for the twelve months ended December 31, 2005 and 2004, respectively.
In November and December 2005, Western Refining LP, its then limited partner and Western Refining, Inc. amended the deferred compensation agreements executed in fiscal 2003 and fiscal 2004 between certain employees and its then limited partner. Pursuant to the amended agreements, the Company assumed the obligation of its then limited partner, and the deferred compensation agreements were terminated in exchange for a cash payment of $28.0 million to the participants in such plan plus the granting of restricted stock, which would vest ratably each quarter for two years. The $28.0 million cash payment was made in January 2006 following the sale of the Company’s common stock in connection with its initial public offering. In addition, approximately 1.8 million shares of restricted stock having a value of $30.1 million at the date of grant were granted in January 2006 to the prior deferred compensation participants. The value of such restricted shares will be expensed over a two-year period. See Note 10, “Stock-Based Compensation”.
14.
Contingencies
Environmental matters
Like other petroleum refiners, the Company’s operations are subject to extensive and rapidly changing federal and state environmental regulations governing air emissions, waste water discharges, and solid and hazardous waste management activities. The Company’s policy is to accrue environmental and clean-up related costs of a non-capital nature when it is probable that a liability has been incurred and the amount can be reasonably estimated. Such estimates may be subject to revision in the future as regulations and other conditions change.
In May 2000, the Company entered into an Agreed Order with the Texas Natural Resources Conservation Commission for remediation of the Company’s property. On August 7, 2000, the Company purchased a Pollution and Legal Liability and Clean-Up Cost Cap Insurance policy at a cost of $10.3 million, which the Company expensed in fiscal 2000. The policy is non-cancelable and covers environmental clean-up costs related to contamination which occurred prior to December 31, 1999, including the costs of the Agreed Order activities. The insurance provider assumes responsibility for all environmental clean-up costs related to the Agreed Order up to $20 million. Under the policy, environmental costs outside the scope of the Agreed Order require payment by the Company of a deductible as well as any costs that exceed the covered limits of the insurance policy. At the current time, management is not aware of any additional environmental costs and, therefore, cannot reasonably estimate a liability, if any, for any type of deductible. In addition, under a settlement agreement with the Company, a subsidiary of Chevron Corporation (“Chevron”) is obligated to pay 60% of any Agreed Order environmental clean-up costs that would otherwise have been covered under the policy but which exceed the $20 million threshold.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
The U.S. Environmental Protection Agency (“EPA”) has embarked on a Petroleum Refinery Enforcement Initiative (“Initiative”), whereby it is investigating industry-wide noncompliance with certain Clean Air Act rules. The Initiative has resulted in many refiners entering into consent decrees typically requiring substantial capital expenditures for additional air pollution control equipment and penalties. Since December 2003, the Company has been voluntarily discussing with the EPA a settlement pursuant to the Initiative. Negotiations with the EPA regarding this Initiative have focused exclusively on air emission programs. The Company does not expect these negotiations to result in any soil or groundwater remediation or clean-up requirements. While at this time it is not known precisely how the Initiative or any resulting settlement may affect the Company, the Company expects to be required to pay penalties and to install additional pollution controls, and, as a result, its operating costs and capital expenditures may increase. Based on current negotiations and information, the Company has estimated the total capital expenditures that may be required pursuant to the Initiative would be approximately $22 million. These capital expenditures would primarily be for installation of a flare gas recovery system on the south-side of the refinery and installation of nitrogen oxides, or NOx, emission controls. As of December 31, 2006, the Company had invested $6.2 million on the flare gas recovery system with the remaining $7.8 million budgeted to be spent in 2007. Estimated expenditures for the NOx emission controls project of $8.0 million will occur from 2007 through 2013. These amounts have been included in the Company’s estimated capital expenditures for regulatory projects. Based on current information, the Company does not expect any settlement pursuant to the Initiative to have a material adverse effect on its business, financial condition or results of operations or that any penalties or increased operating costs related to the Initiative will be material.
Periodically, the Company receives communications from various federal, state and local governmental authorities asserting violation(s) of environmental laws and/or regulations. These governmental entities may also propose or assess fines or require corrective action for these asserted violations. The Company intends to respond in a timely manner to all such communications and to take appropriate corrective action. The Company does not anticipate that any such matters currently asserted will have a material adverse impact on its financial condition, results of operations or cash flows.
Pursuant to the purchase agreement relating to the North Refinery asset acquisition, Chevron retained responsibility for, and control of, certain remediation activities. The Company is not presently aware of any additional environmental costs that it would be responsible for relating to the assets acquired; therefore, it cannot reasonably estimate a liability, if any.
In April 2003, the Company received a payment of reparations in the amount of $6.8 million from a pipeline company as ordered by the Federal Energy Regulatory Commission (“FERC”). While the Company and the pipeline company have sought judicial review of the FERC order, as well as a series of other orders, the pipeline company has recently made a compliance filing in which it asserts it overpaid reparations to the Company in a total amount of $882,000 including accrued interest through April 30, 2006, and that interest should continue to accrue. In the event the Company does not prevail on any issues of which it seeks review, and the pipeline company prevails in whole or in part on the issue for which it seeks judicial review, the reparations owed to the Company may be found to be less than the amount paid to the Company in April 2003. In such case, the Company may be required to repay a portion of the payment received in April 2003 in an amount up to $882,000 plus additional accrued interest. The Company does not believe that the judicial review will result in a repayment by the Company of an amount that would have a material adverse effect on its financial condition, results of operations or cash flows.
The Company has been named as a defendant, along with many other companies, including other refiners, in a lawsuit filed in New Mexico by the New Mexico Attorney General and several private law firms. The Company understands that the case has been transferred to the Southern District of New York by the Judicial Panel on Multidistrict Litigation and that an amended complaint has been filed. The Company has not been
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
served with a summons and complaint, nor has the Company made an appearance in this litigation. The State of New Mexico alleges that leakage of methyl tertiary butyl ether (“MTBE”) has impacted certain of the state’s water supplies. No specific water supplies which are alleged to have been impacted have been identified at this time. If the Company is served with a summons and made an active defendant in this matter, the Company will vigorously defend itself. At this time, the Company is investigating this matter and does not have enough information to determine if any liability is probable. The Company believes that any potential liability would not have a material adverse impact on its financial condition, results of operations or cash flows.
Other Matters
The Company is party to various other claims and legal actions arising in the normal course of business. The Company believes that the resolution of these matters will not have a material adverse effect on its financial condition, results of operations or cash flows.
15.
Concentration of Risk
Significant customers
The Company sells a variety of refined products to a diverse customer base. Those customers accounting for more than 10% of total revenues for 2006 were Chevron, Phoenix Fuel and PMI. The following table summarizes sales percentages for these customers for 2006, 2005 and 2004:
Trade accounts receivable as of December 31, 2006, include $23.9 million from Chevron, $27.5 million from Phoenix Fuel and $37.6 million from PMI.
Sales by product
All sales were domestic sales, except for sales of gasoline and diesel fuel for export into Mexico. The sales for export were to PMI and accounted for approximately 10.5%, 9.9% and 5.5% of total sales in 2006, 2005 and 2004, respectively. The following table summarizes the percentages of all refined product sales to total sales for 2006, 2005 and 2004:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
16.
Operating Leases and Other Commitments
The Company has commitments under long-term operating leases for certain buildings and railcars expiring at various dates over the next 5 years. Total rental expense was $1.3 million, $0.1 million and $0.1 million for the years ended December 31, 2006, 2005 and 2004, respectively. At December 31, 2006, minimum lease payments on operating leases were as follows:
In the normal course of business, the Company has long-term commitments to purchase services, such as natural gas, electricity, water and transportation services for use by its refinery at market-based rates. The Company is also party to various refined product and crude oil supply and exchange agreements.
In June 2005, the Company entered into a sulfuric acid regeneration and sulfur gas processing agreement with E.I. du Pont de Nemours (“DuPont”). Under the agreement, the Company will have a long-term commitment to purchase services for use by its refinery. Upon completion of the project, which is expected to occur by the end of 2007, the annual commitment for these services will range from $10.0 million to $16.0 million per year over the next 20 years. Prior to the completion of this project, the Company will incur direct operating expenses related to sulfuric acid regeneration under a short-term agreement.
In August 2005, the Company entered into a Throughput and Distribution Agreement and associated Storage Agreement with Magellan Pipeline Company, L.P. Under these agreements, the Company has a long-term commitment beginning in February 2006 to provide for the transportation and storage of alkylate and other refined products from the Gulf Coast to the Company’s refinery via the Magellan South System pipeline. For the first six months of these agreements, the Company is committed to pay $1.6 million per quarter. For the next 41/2 years of these agreements, the Company is committed to pay $2.8 million per quarter.
17.
Pending Acquisition of Giant Industries, Inc.
On August 26, 2006, the Company entered into a definitive merger agreement with Giant Industries, Inc. (“Giant”) under which the Company would acquire all of the outstanding shares of Giant. On November 12, 2006, the parties entered into an amendment to the merger agreement. If the transaction closes, the Company will acquire Giant’s common stock for $77.00 per share in cash. The transaction has been approved by the board of directors of both companies. On February 27, 2007, Giant’s shareholders voted to approve the transaction. The closing of the transaction is subject to various conditions, including compliance with the pre-merger notification requirements of the Hart-Scott-Rodino Antitrust Improvements Act (“HSR Act”). The transaction is valued at approximately $1.4 billion, including approximately $280 million of Giant’s outstanding debt, and is not subject to any financing conditions.
The Company and Giant filed pre-merger notifications with the U.S. antitrust authorities pursuant to the HSR Act on September 7, 2006. The Company and Giant subsequently entered into an agreement with the Federal Trade Commission (“FTC”) on February 20, 2007, in which both companies agreed (i) to respond to additional information requests; (ii) not to certify substantial compliance with the information requests until
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
March 13, 2007; and (iii) not to close our merger with Giant until 30 days after the Company and Giant certify substantial compliance.
Additionally, on November 22, 2006, Timothy Bisset filed a class action complaint in Arizona state court against Giant, its directors and the Company in connection with the merger. Mr. Bisset alleges that Giant and its directors breached their fiduciary duty in voting to amend the definitive merger agreement to provide for, among other things, a lower acquisition price of $77.00 per share. Mr. Bisset also alleges that the Company aided and abetted this breach of Giant’s fiduciary duty. He also alleges that he and other public stockholders of Giant’s common stock are entitled to enjoin the proposed amended transaction or, alternatively, to recover damages in the event the transaction is completed.
The Company expects to complete the merger with Giant during the second quarter of 2007. The Company cannot specify when, or assure that, the Company and Giant will satisfy or waive all conditions to the merger. Further, there can be no assurance that the FTC, state antitrust authorities, or Mr. Bisset, will not seek injunctive relief to prevent the merger from taking place.
After completing the transaction, Western will have a total crude oil throughput capacity of approximately 223,000 barrels per day (bpd). In addition to Western’s 124,000 bpd refinery in El Paso, Texas, Western will gain an East Coast presence with a 62,000 bpd refinery in Yorktown, Virginia and will gain two refineries in the Four Corners region of Northern New Mexico with a current combined capacity of 37,000 bpd. Western’s primary operating areas will encompass the Mid-Atlantic region, far West Texas, Phoenix and Tucson, Arizona, Northern Mexico, Albuquerque, New Mexico and the Four Corners region of Utah, Colorado, Arizona and New Mexico. In addition to the four refineries, Western’s asset portfolio will include refined products terminals in Flagstaff, Arizona and Albuquerque, as well as asphalt terminals in Phoenix, Tucson, Albuquerque and El Paso. Western’s asset base will also include 155 retail service stations and convenience stores in Arizona, Colorado and New Mexico, a fleet of crude oil and finished product truck transports, and three wholesale petroleum products distributors - Phoenix Fuel Co., Inc. primarily in Arizona, Dial Oil Co. primarily in New Mexico, and Empire Oil Co., primarily in California.
Following the closing of the transaction, Paul Foster will remain President and Chief Executive Officer of Western, and Fred Holliger, Giant’s current Chairman and Chief Executive Officer, will serve as a special advisor to Western’s Board of Directors. The combined company will be headquartered in El Paso, Texas and will maintain offices in Scottsdale, Arizona.
The transaction will be funded through a combination of cash on hand and a $1.9 billion commitment from Bank of America, consisting of up to a $1.4 billion senior secured term loan and a $500 million senior secured revolving credit facility. On August 28, 2006, we deposited $12.5 million into an escrow account. The deposit was subsequently increased to $25.0 million, since the closing of the transaction did not occur on or before November 30, 2006.
If the merger has not been consummated by April 30, 2007, either Giant or Western may terminate the transaction unless their breach was the cause of the merger not being consummated by such date. If the merger is terminated after this date and the HSR waiting period has not expired or been waived, Western will forfeit this $25 million deposit to Giant.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
18.
Quarterly Financial Information (Unaudited)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2006
(1)
Prior to January 2006, Western Refining LP had not incurred income taxes because its operations were conducted by an operating partnership that was not subject to income taxes. However, Western Refining, Inc. incurred a minor income tax benefit related to its operations from September 16 (inception) to December 31, 2005.
Item 9.
Item 9.
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.
Controls and Procedures
Evaluation of disclosure controls and procedures.
The Company, under the supervision and with the participation of its management, including the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as of December 31, 2006. Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2006.
There were no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2006, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B.
Item 9B.
Other Information
None.
PART III
Certain information required in this Part III is incorporated by reference to Western Refining, Inc.’s Definitive Proxy Statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A within 120 days after the end of the fiscal year covered by this report.
Item 10.
Item 10.
Directors and Executive Officers of the Registrant
The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s 2007 Definitive Proxy Statement under the heading “Election of Directors, Executive Compensation and Other Information.”
Item 11.
Item 11.
Executive Compensation
The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s 2007 Definitive Proxy Statement under the heading “Executive Compensation and Other Information.”
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Security Ownership of Certain Beneficial Owners and Management
The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s 2007 Definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management.”
Securities Authorized for Issuance Under Equity Compensation Plans
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s 2007 Definitive Proxy Statement under the heading “Certain Relationships and Related Transactions.”
Item 14.
Item 14.
Principal Accountant Fees and Services
The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s 2007 Definitive Proxy Statement under the heading “Proposal 2: Ratification of Independent Auditor.”
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules
(a) Financial Statements:
See Index to Financial Statements included in Item 8.
(b) The following exhibits are filed herewith (or incorporated by reference herein):
*
Filed herewith.

Management contract or compensatory plan or arrangement.
(c) All financial statement schedules are omitted because the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto.
The Company’s 2006 Annual Report is available upon request. Stockholders of the Company may obtain a copy of any exhibits to this Form 10-K at a charge of $0.10 per page. Requests should be made to: Investor Relations, Western Refining, Inc., 6500 Trowbridge Drive, El Paso, Texas 79905.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
WESTERN REFINING, INC.
By:
/s/ Paul L. Foster
Name: Paul L. Foster
Title:
President and Chief Executive Officer
Date: March 7, 2007
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Index to Exhibits
*
Filed herewith.

Management contract or compensatory plan or arrangement.