FORM 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
For the fiscal year ended December 31, 2006
OR
For the transition period from to
Commission file number 1-13175
VALERO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Registrant’s telephone number, including area code: (210) 345-2000
Securities registered pursuant to Section 12(b) of the Act: Common stock, $0.01 par value per share, and
Preferred Share Purchase Rights, listed on the New York Stock Exchange.
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule12b-2 of the Exchange Act).
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x
The aggregate market value of the voting and non-voting common stock held by non-affiliates was approximately $40.5 billion based on the last sales price quoted as of June 30, 2006 on the New York Stock Exchange, the last business day of the registrant’s most recently completed second fiscal quarter.
As of January 31, 2007, 604,114,047 shares of the registrant’s common stock were issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
We intend to file with the Securities and Exchange Commission before March 31, 2007 a definitive Proxy Statement for our Annual Meeting of Stockholders scheduled for April 26, 2007, at which our directors will be elected. Portions of the 2007 Proxy Statement are incorporated by reference in Part III of this Form 10-K and are deemed to be a part of this report.
CROSS-REFERENCE SHEET
The following table indicates the headings in the 2007 Proxy Statement where certain information required in Part III of Form 10-K may be found.
Form 10-K Item No. and Caption
Heading in 2007 Proxy Statement
10. Directors, Executive Officers and Corporate Governance
11. Executive Compensation
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
13. Certain Relationships and Related Transactions, and Director Independence
14. Principal Accountant Fees and Services
Copies of all documents incorporated by reference, other than exhibits to such documents, will be provided without charge to each person who receives a copy of this Form 10-K upon written request to Jay D. Browning, Senior Vice President and Corporate Secretary, Valero Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-6000.
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CONTENTS
Business, Risk Factors and Properties
Recent Developments
Segments
Valero’s Operations
Risk Factors
Environmental Matters
Properties
Executive Officers of the Registrant
Unresolved Staff Comments
Legal Proceedings
Submission of Matters to a Vote of Security Holders
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
Exhibits and Financial Statement Schedules
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PART I
Unless otherwise indicated, the terms “Valero,” “we,” “our,” and “us” are used in this report to refer to Valero Energy Corporation, to one or more of our consolidated subsidiaries, or to all of them taken as a whole. In the following Items 1, 1A and 2, “Business, Risk Factors and Properties,” we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources, that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The words “forecasts,” “intends,” “believes,” “expects,” “plans,” “scheduled,” “goal,” “may,” “anticipates,” “estimates,” and similar expressions identify forward-looking statements. We do not undertake to update, revise, or correct any of the forward-looking information. Our forward-looking statements should be read in conjunction with our disclosures beginning on page 22 of this report under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.”
ITEMS 1., 1A. and 2. BUSINESS, RISK FACTORS AND PROPERTIES
Overview. We are a Fortune 500 company based in San Antonio, Texas. Our principal executive offices are at One Valero Way, San Antonio, Texas, 78249, and our telephone number is (210) 345-2000. Our common stock trades on the New York Stock Exchange under the symbol “VLO.” We were incorporated in Delaware in 1981 under the name Valero Refining and Marketing Company; our name was changed to Valero Energy Corporation on August 1, 1997. On January 31, 2007, we had 21,836 employees.
We own and operate 18 refineries located in the United States, Canada, and Aruba that produce premium, environmentally clean refined products such as RBOB1, gasoline meeting the specifications of the California Air Resources Board (CARB), CARB diesel fuel, low-sulfur and ultra-low-sulfur diesel fuel, and oxygenates (liquid hydrocarbon compounds containing oxygen). We also produce conventional gasolines, distillates, jet fuel, asphalt, petrochemicals, lubricants, and other refined products.
We market branded and unbranded refined products on a wholesale basis in the United States and Canada through an extensive bulk and rack marketing network. We also sell refined products through a network of approximately 5,800 retail and wholesale branded outlets in the United States, Canada, and Aruba.
Available Information. Our internet website address is http://www.valero.com. Information contained on our website is not part of this annual report on Form 10-K. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K filed with (or furnished to) the Securities and Exchange Commission (SEC) are available on our internet website (in the “Investor Relations” section), free of charge, as soon as reasonably practicable after we file or furnish such material. We also post our corporate governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers, and the charters of the committees of our board of directors in the same website location. Our governance documents are available in print to any stockholder that makes a written request to Jay D. Browning, Senior Vice President and Corporate Secretary, Valero Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-6000.
1
RBOB is a base unfinished reformulated gasoline mixture known as “reformulated gasoline blendstock for oxygenate blending” or “RBOB.”
RECENT DEVELOPMENTS
In 2006, we sold all of our ownership interest in Valero GP Holdings, LLC (NYSE: VEH), the general partner of Valero L.P. Valero L.P. is a publicly traded master limited partnership (NYSE: VLI) which owns and operates crude oil and refined product pipeline, terminalling, and storage tank assets. The sale of our interest in Valero GP Holdings, LLC is more fully described in Note 9 of Notes to Consolidated Financial Statements, and we hereby incorporate by reference into this Item our disclosures made in Note 9.
SEGMENTS
Our business is organized into two reportable segments: refining and retail. Our refining segment includes refining operations, wholesale marketing, product supply and distribution, and transportation operations. The refining segment is segregated geographically into the Gulf Coast, Mid-Continent, West Coast, and Northeast regions.
Our retail segment includes company-operated convenience stores, Canadian dealers/jobbers, truckstop facilities, cardlock facilities, and home heating oil operations. The retail segment is segregated into two geographic regions. Our retail operations in eastern Canada are referred to as Retail-Canada. Our retail operations in the United States are referred to as Retail-U.S. The financial information about our segments in Note 20 of Notes to Consolidated Financial Statements is incorporated herein by reference.
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VALERO’S OPERATIONS
REFINING
On December 31, 2006, our refining operations included 18 refineries in the United States, Canada, and Aruba with a combined total throughput capacity of approximately 3.3 million barrels per day (BPD). The following table presents the locations of these refineries and their feedstock throughput capacities. These capacities exclude any throughput enhancements completed after December 31, 2006.
As of December 31, 2006
Refinery
Location
Throughput Capacity (a)
(barrels per day)
Corpus Christi (b)
Port Arthur
Aruba
St. Charles
Texas City
Houston
Three Rivers
Krotz Springs
Benicia
Wilmington
Memphis
McKee
Lima
Ardmore
Quebec City
Delaware City
Paulsboro
Total
We process a wide slate of feedstocks, including sour crude oils, intermediates, and residual fuel oil (resid) which can typically be purchased at differentials below West Texas Intermediate, a benchmark crude oil. In 2006, sour crude oils, acidic sweet crude oils, and resid represented 55% of our throughput volumes, sweet crude oils represented 30%, and the remaining 15% was composed of blendstocks and other feedstocks. Our ability to process significant amounts of sour crude oils enhances our competitive position in the industry relative to refiners that process primarily sweet crude oils because sour crude oils typically can be purchased at differentials below sweet crude oils.
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In 2006, gasolines and blendstocks represented 48% of our refined product slate; distillates – such as home heating oil, diesel fuel, and jet fuel – represented 32%; petrochemicals represented 3%; and asphalt, lubricants, gas oils, No. 6 fuel oil, petroleum coke, and other products comprised the remaining 17%.
GULF COAST
The following table presents the percentages of principal charges and yields (on a combined basis) for the nine refineries in this region for the year ended December 31, 2006. Total throughput volumes for the Gulf Coast refining region averaged 1,532,000 BPD for the twelve months ended December 31, 2006.
Combined Gulf Coast Region Charges and Yields
Fiscal 2006 Actual
Charges:
sour crude oil
high-acid sweet crude oil
sweet crude oil
residual fuel oil
other feedstocks
blendstocks
Yields:
gasolines and blendstocks
distillates
petrochemicals
other products (includes vacuum gas oil, No. 6 fuel oil, petroleum coke, asphalt, and other)
Corpus Christi East and West Refineries. Our Corpus Christi East and West Refineries are located along the Corpus Christi Ship Channel on the Texas Gulf Coast. The West Refinery specializes in processing primarily lower-cost sour crude oil and resid into premium products such as RBOB. The East Refinery processes heavy, high-sulfur crude oil into conventional gasoline, diesel, jet fuel, asphalt, aromatics, and other light products. We have operated the East Refinery since 2001 and have substantially integrated the operations of the West and East Refineries, allowing for the transfer of various feedstocks and blending components between the two refineries and the sharing of resources. The refineries typically receive and deliver feedstocks and products by tanker and barge via deepwater docking facilities along the Corpus Christi Ship Channel. Three truck racks with a total of 16 bays service local markets for gasoline, diesel, jet fuels, LPG’s, and asphalt. The refineries distribute refined products using the Colonial, Explorer, Valley, and other major pipelines.
Port Arthur Refinery. Our Port Arthur Refinery is located on the Texas Gulf Coast approximately 90 miles east of Houston. The refinery processes primarily heavy sour crude oils and other feedstocks into conventional and premium gasoline and RBOB, as well as diesel, jet fuel, petrochemicals, petroleum coke, and sulfur. The refinery receives crude oil over marine docks and has access to the Sunoco and Oiltanking terminals at Nederland, Texas. Finished products are distributed into the Colonial, Explorer, and TEPPCO pipelines or across the refinery docks into ships or barges. The refinery also has convenient truck-rack access.
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Aruba Refinery. Our Aruba Refinery is located on the island of Aruba in the Caribbean Sea. It processes primarily heavy sour crude oil and produces primarily intermediate feedstocks and finished distillate products. Significant amounts of the refinery’s intermediate feedstock production are transported and further processed in our other refineries in the Gulf Coast, West Coast, and Northeast regions. The refinery receives crude oil by ship at its two deepwater marine docks which can berth ultra-large crude carriers. The refinery’s products are delivered by ship primarily into markets in the U.S. Gulf Coast, Florida, the New York Harbor, the Caribbean, and Europe.
St. Charles Refinery. Our St. Charles Refinery is located approximately 15 miles from New Orleans along the Mississippi River. The refinery processes sour crude oils and other feedstocks into gasoline, distillates, and other light products. The refinery receives crude oil over five marine docks and has access to the Louisiana Offshore Oil Port where it can receive crude oil through a 24-inch pipeline. Finished products can be shipped over these docks or by pipeline into either the Plantation or Colonial pipeline network for distribution to the eastern United States.
Texas City Refinery. Our Texas City Refinery is located southeast of Houston on the Texas City Ship Channel. The refinery processes primarily heavy sour crude oils into a wide slate of products. The refinery receives and delivers its feedstocks and products by tanker and barge via deepwater docking facilities along the Texas City Ship Channel and uses the Colonial, Explorer, and TEPPCO pipelines for distribution of its products.
Houston Refinery. Our Houston Refinery is located on the Houston Ship Channel. It processes primarily sour crude oils and low-sulfur resid into conventional gasoline and distillates. The refinery also produces roofing-grade asphalt. The refinery receives its feedstocks via tanker at deepwater docking facilities along the Houston Ship Channel and delivers its products through major refined-product pipelines, including the Colonial, Explorer, and TEPPCO pipelines.
Three Rivers Refinery. Our Three Rivers Refinery is located in South Texas between Corpus Christi and San Antonio. It processes primarily heavy sweet and sour crude oils into conventional gasoline and distillates. The refinery has access to crude oil from foreign sources delivered to the Texas Gulf Coast at Corpus Christi as well as crude oil from domestic sources through third-party pipelines. A 70-mile pipeline that can deliver 120,000 BPD of crude oil connects the Three Rivers Refinery to Corpus Christi. The refinery distributes its refined products primarily through pipelines owned by Valero L.P.
Krotz Springs Refinery. Our Krotz Springs Refinery is located between Baton Rouge and Lafayette, Louisiana on the Atchafalaya River. It processes light sweet crude oils (received by pipeline and barge) into conventional gasoline and distillates. The refinery’s location provides access to upriver markets on the Mississippi River, and its docking facilities along the Atchafalaya River are sufficiently deep to allow barge access. The facility also uses the Colonial pipeline to transport products to markets in the southeastern and northeastern United States.
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WEST COAST
The following table presents the percentages of principal charges and yields (on a combined basis) for the two refineries in this region for the year ended December 31, 2006. Total throughput volumes for the West Coast refining region averaged approximately 305,000 BPD for the twelve months ended December 31, 2006.
Combined West Coast Region Charges and Yields
Benicia Refinery. Our Benicia Refinery is located northeast of San Francisco on the Carquinez Straits of San Francisco Bay. It processes sour crude oils into premium products, primarily CARBOB gasoline. (CARBOB is a reformulated gasoline mixture that meets the specifications of the California Air Resources Board when blended with ethanol.) The refinery receives crude oil supplies via a deepwater dock that can berth large crude oil carriers and a 20-inch crude oil pipeline connected to a southern California crude oil delivery system. Most of the refinery’s products are distributed via the Kinder Morgan pipeline in California.
Wilmington Refinery. Our Wilmington Refinery is located near Los Angeles, California. The refinery processes a blend of lower-cost heavy and high-sulfur crude oils. The refinery can produce all of its gasoline as CARBOB gasoline and produces both ultra-low-sulfur diesel and CARB diesel. The refinery is connected by pipeline to marine terminals and associated dock facilities that can move and store crude oil and other feedstocks. Refined products are distributed via the Kinder Morgan pipeline system and various third-party terminals in southern California, Nevada, and Arizona.
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MID-CONTINENT
The following table presents the percentages of principal charges and yields (on a combined basis) for the four refineries in this region for the year ended December 31, 2006. Total throughput volumes for the Mid-Continent refining region averaged 559,000 BPD for the twelve months ended December 31, 2006.
Combined Mid-Continent Region Charges and Yields
Memphis Refinery. Our Memphis Refinery is located in Tennessee along the Mississippi River’s Lake McKellar. It processes primarily light sweet crude oils. Almost all of its production is light products, including regular and premium gasoline, diesel, jet fuels, and petrochemicals. Crude oil is supplied to the refinery via the Capline Pipeline and can also be received, along with other feedstocks, via barge. The refinery’s products are distributed via truck racks at our three product terminals, barges, and a pipeline directly to the Memphis airport.
McKee Refinery. Our McKee Refinery is located in the Texas Panhandle. It processes primarily sweet crude oils and produces conventional gasoline, RBOB, low-sulfur diesel, jet fuels, and asphalt. The refinery has access to crude oil from Texas, Oklahoma, Kansas, and Colorado through third-party pipelines. The refinery also has access at Wichita Falls, Texas to third-party pipelines that transport crude oil from the Texas Gulf Coast and West Texas to the Mid-Continent region. The refinery distributes its products primarily via Valero L.P.’s pipelines to markets in Texas, New Mexico, Arizona, Colorado, and Oklahoma.
Lima Refinery. Our Lima Refinery is located in Ohio between Toledo and Dayton. It currently processes primarily light sweet crude oils. The refinery produces conventional gasoline, RBOB, diesel, jet fuels, and petrochemicals. Crude oils are delivered to the refinery through the Mid-Valley and Marathon pipelines. The refinery’s products are distributed through the Buckeye and Inland pipeline systems and by rail and truck to markets in Ohio, Indiana, Illinois, Michigan, and western Pennsylvania.
Ardmore Refinery. Our Ardmore Refinery is located in Ardmore, Oklahoma, approximately 90 miles from Oklahoma City. It processes medium sour and light sweet crude oils into conventional gasoline, low-sulfur diesel, and asphalt. Crude oil is delivered to the refinery through Valero L.P.’s crude oil gathering and trunkline systems, other third-party pipelines, and trucking operations. Refined products are transported via pipelines, railcars, and trucks.
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NORTHEAST
The following table presents the percentages of principal charges and yields (on a combined basis) for the three refineries in this region for the year ended December 31, 2006. Total throughput volumes for the Northeast refining region averaged 563,000 BPD for the twelve months ended December 31, 2006.
Combined Northeast Region Charges and Yields
Quebec City Refinery. Our Quebec City Refinery is located in Lévis, Canada (near Quebec City). It processes sweet crude oils and lower-quality, sweet acidic crude oils into conventional gasoline, low-sulfur diesel, jet fuels, heating oil, and propane. The refinery receives crude oil by ship at its deepwater dock on the St. Lawrence River. We charter large ice-strengthened, double-hulled crude oil tankers that can navigate the St. Lawrence River year-round. The refinery transports its products to its primary terminals in Quebec and Ontario primarily by train, and also uses ships and trucks extensively throughout eastern Canada.
Delaware City Refinery. Our Delaware City Refinery is located along the Delaware River near Wilmington, Delaware. The refinery processes primarily sour crude oils into a wide slate of products including conventional gasoline, RBOB, petroleum coke, sulfur, low-sulfur diesel, and home heating oil. Feedstocks and refined products are transported via pipeline, barge, and truck-rack facilities. The refinery’s production is sold primarily in the U.S. Northeast.
Paulsboro Refinery. Our Paulsboro Refinery is located in Paulsboro, New Jersey, approximately 15 miles south of Philadelphia on the Delaware River. The refinery processes primarily sour crude oils into a wide slate of products including gasoline, distillates, lube oil basestocks, asphalt, petroleum coke, sulfur, and fuel oil. Feedstocks and refined products are typically transported by tanker and barge via refinery-owned dock facilities along the Delaware River, Buckeye Partners’ product distribution system, an onsite truck rack owned by Valero L.P., railcars, and the Colonial pipeline, which allows products to be sold into the New York Harbor market.
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FEEDSTOCK SUPPLY
Approximately 65% of our current crude oil feedstock requirements are purchased through term contracts while the remaining requirements are generally purchased on the spot market. Our term supply agreements include arrangements to purchase feedstocks at market-related prices directly or indirectly from various foreign national oil companies (including feedstocks originating in Saudi Arabia, Mexico, Iraq, Kuwait, Venezuela, Colombia, and Africa) as well as international and domestic oil companies. About 75% of these crude oil feedstocks are imported from foreign sources and about 25% are domestic. In the event we become unable to purchase crude oil from any one of these sources, we believe that adequate alternative supplies of crude oil would be available.
The U.S. network of crude oil pipelines and terminals allows us to acquire crude oil from producing leases, domestic crude oil trading centers, and ships delivering cargoes of foreign and domestic crude oil. Our Quebec City and Aruba Refineries rely on foreign crude oil that is delivered to the refineries’ dock facilities by ship. We use the futures market to manage a portion of the price risk inherent in purchasing crude oil in advance of our delivery date and holding inventories of crude oils and refined products.
REFINING SEGMENT SALES
Our refining segment includes sales of refined products in both the wholesale rack and bulk markets. These sales include refined products that are manufactured in our refining operations as well as refined products purchased or received on exchange from third parties. Most of our refineries have access to deepwater transportation facilities and interconnect with common-carrier pipeline systems, allowing us to sell products in most major geographic regions of the United States and eastern Canada. No customer accounted for more than 10% of our total operating revenues in 2006.
Wholesale Marketing
We market branded and unbranded transportation fuels on a wholesale basis in about 40 states through an extensive rack marketing network. The principal purchasers of our transportation fuels from terminal truck racks are wholesalers, distributors, retailers, and truck-delivered end users throughout the United States.
The majority of our rack volumes are sold through unbranded channels. The remainder is sold to distributors and dealers that are members of the Valero-brand family that operate approximately 3,850 branded sites. These sites are independently owned and are supplied by us under multi-year contracts. For wholesale branded sites, we promote our Valero® and Beacon® brands in California. Elsewhere in the United States, we promote our Valero® and Shamrock® brands, and we are in the process of converting our Diamond Shamrock® branded sites to the Valero® brand.
We also sell a variety of other products produced at our refineries including asphalt, lube base oils, petroleum coke, and sulfur. These products are transported via pipelines, barges, trucks, and railcars. We produce approximately 60,000 BPD of asphalt which is sold to customers in the paving and roofing industries. We are the second largest producer of asphalt in the United States. We produce asphalt at seven refineries and market asphalt in 20 states through 15 terminal facilities. We also produce packaged roofing products at four manufacturing facilities, and modified paving asphalts at nine polymer modifying plants. We are the largest producer of petroleum coke in the United States, supplying primarily power generation customers and cement manufacturers. We are also one of the largest producers of sulfur in the United States with sales primarily to customers in the agricultural sector.
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We produce and market a variety of commodity petrochemicals including aromatic solvents (benzene, toluene, and xylene) and refinery- and chemical-grade propylene. Aromatic solvents and propylene are sold to customers in the chemical industry for further processing into such products as paints, plastics, and adhesives.
Bulk Sales and Trading
We sell a significant portion of our gasoline and distillate production through bulk sales channels. Our bulk sales are made to various oil companies and traders as well as certain bulk end-users such as railroads, airlines, and utilities. Our bulk sales are transported primarily by pipeline, barges, and tankers to major tank farms and trading hubs.
We also enter into refined product exchange and purchase agreements. These agreements help to minimize transportation costs, optimize refinery utilization, balance refined product availability, broaden geographic distribution, and make sales to markets not connected to our refined product pipeline systems. Exchange agreements provide for the delivery of refined products by us to unaffiliated companies at our and third parties’ terminals in exchange for delivery of a similar amount of refined products to us by these unaffiliated companies at specified locations. Purchase agreements involve our purchase of refined products from third parties with delivery occurring at specified locations.
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RETAIL
Our retail segment operations include the following:
sales of transportation fuels at retail stores and unattended self-service cardlocks,
sales of convenience store merchandise in retail stores, and
sales of home heating oil to residential customers.
We are one of the largest independent retailers of refined products in the central and southwest United States and eastern Canada. Our retail operations are supported by our proprietary credit card program which had approximately 700,000 accounts as of December 31, 2006. Our retail operations are segregated geographically into two groups: Retail-U.S. and Retail-Canada.
RETAIL-U.S.
Sales in Retail-U.S. represent sales of transportation fuels and convenience store merchandise through our company-operated retail sites. For the year ended December 31, 2006, total sales of refined products through Retail-U.S.’s retail sites averaged approximately 116,600 BPD. In addition to transportation fuels, our company-operated convenience stores sell snacks, candy, beer, fast foods, cigarettes, and fountain drinks. On December 31, 2006, we had 967 company-operated sites in Retail-U.S. (of which approximately 75% were owned and 25% were leased). Our company-operated stores are operated primarily under the brand names Corner Store® and Stop N Go®. Transportation fuels sold in our Retail-U.S. stores are sold primarily under the Valero® brand, with some sites selling under the Diamond Shamrock® brand pending their conversion to the Valero® brand.
RETAIL-CANADA
Sales in Retail-Canada include the following:
sales of refined products and convenience store merchandise through our company-operated retail sites and cardlocks,
sales of refined products through sites owned by independent dealers and jobbers, and
Retail-Canada includes retail operations in eastern Canada where we are a major supplier of refined products serving Quebec, Ontario, and the Atlantic Provinces of Newfoundland, Nova Scotia, New Brunswick, and Prince Edward Island. For the year ended December 31, 2006, total retail sales of refined products through Retail-Canada averaged approximately 75,600 BPD. Transportation fuels are sold under the Ultramar® brand through a network of 956 outlets throughout eastern Canada. On December 31, 2006, we owned or leased 446 retail stores in Retail-Canada and distributed gasoline to 510 dealers and independent jobbers. In addition, Retail-Canada operates 89 cardlocks, which are card- or key-activated, self-service, unattended stations that allow commercial, trucking, and governmental fleets to buy transportation fuel 24 hours a day. Retail-Canada operations also include a large home heating oil business that provides home heating oil to approximately 151,000 households in eastern Canada. Our home heating oil business tends to be seasonal to the extent of increased demand for home heating oil during the winter.
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RISK FACTORS
Our financial results are affected by volatile refining margins.
Our financial results are primarily affected by the relationship, or margin, between refined product prices and the prices for crude oil and other feedstocks. Our cost to acquire feedstocks and the price at which we can ultimately sell refined products depend upon numerous factors beyond our control, including regional and global supply of and demand for crude oil, gasoline, diesel, and other feedstocks and refined products. These in turn are dependent upon, among other things, the availability and quantity of imports, the production levels of domestic and foreign suppliers, levels of refined product inventories, U.S. relationships with foreign governments, political affairs, and the extent of governmental regulation.
Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Earnings on a diluted basis for 2004, 2005, and 2006 were $3.27 per share, $6.10 per share, and $8.64 per share, respectively. Refining margins were a significant contributing factor to the increase in our earnings between 2004 and 2006. The increase in our earnings for these periods is more fully described in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Compliance with and changes in environmental laws could adversely affect our performance.
The principal environmental risks associated with our operations are emissions into the air and releases into the soil, surface water, or groundwater. Our operations are subject to extensive federal, state, and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasoline and diesel fuels. If we violate or fail to comply with these laws and regulations, we could be fined or otherwise sanctioned. Because environmental laws and regulations are becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, such as those relating to greenhouse gas emissions and climate change (e.g., California’s AB-32 “Global Warming Solutions Act”), the level of expenditures required for environmental matters could increase in the future. Future legislative action and regulatory initiatives could result in changes to operating permits, additional remedial actions, or increased capital expenditures and operating costs that cannot be assessed with certainty at this time. In addition, any major upgrades in any of our refineries could require material additional expenditures to comply with environmental laws and regulations.
Disruption of our ability to obtain crude oil could adversely affect our operations.
A significant portion of our feedstock requirements is satisfied through supplies originating in Saudi Arabia, Mexico, Iraq, Kuwait, Venezuela, Colombia, and Africa. We are, therefore, subject to the political, geographic, and economic risks attendant to doing business with suppliers located in, and supplies originating from, those areas. If one or more of our supply contracts were terminated, or if political events disrupt our traditional crude oil supply, we believe that adequate alternative supplies of crude oil would be available, but it is possible that we would be unable to find alternative sources of supply. If we are unable to obtain adequate crude oil volumes or are able to obtain such volumes only at unfavorable prices, our results of operations could be materially adversely affected, including reduced sales volumes of refined products or reduced margins as a result of higher crude oil costs.
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Competitors that produce their own supply of feedstocks, have more extensive retail outlets, or have greater financial resources may have a competitive advantage.
The refining and marketing industry is highly competitive with respect to both feedstock supply and refined product markets. We compete with numerous other companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. We do not produce any of our crude oil feedstocks. Many of our competitors, however, obtain a significant portion of their feedstocks from company-owned production and some have more extensive retail outlets than we have. Competitors that have their own production or extensive retail outlets (and greater 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.
Some of our competitors also have materially greater financial and other resources than we have. Such competitors have a greater ability to bear the economic risks inherent in all phases of our industry. 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.
A significant interruption in one or more of our refineries could adversely affect our business.
Our refineries are our principal operating assets. As a result, our operations could be subject to significant interruption if one or more of our refineries were to experience a major accident, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs.
Our operations expose us to many operating risks, not all of which are insured.
Our refining and marketing operations are subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards, and uncontrollable flows of oil and gas. They are also subject to the additional hazards of loss from severe weather conditions. As protection against operating hazards, we maintain insurance coverage against some, but not all, such potential losses. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax liabilities, including federal, state, and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise, withholding, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Certain of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties.
13
ENVIRONMENTAL MATTERS
We hereby incorporate by reference into this Item the environmental disclosures contained in the following sections of this report:
Item 1 under the caption “Risk Factors – Compliance with and changes in environmental laws could adversely affect our performance,”
Item 3 “Legal Proceedings” under the caption “Environmental Enforcement Matters,” and
Item 8 “Financial Statements” in Note 24 of Notes to Consolidated Financial Statements.
Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2006, our capital expenditures attributable to compliance with environmental regulations were approximately $1.6 billion, and are currently estimated to be approximately $800 million for 2007 and approximately $450 million for 2008. (The estimates for 2007 and 2008 do not include amounts related to capital investments at our facilities that management has deemed to be strategic investments rather than expenditures relating to environmental regulatory compliance.) Of the foregoing amounts, our capital expenditures attributable to compliance with the Environmental Protection Agency’s Tier II gasoline and diesel standards were approximately $990 million in 2006, and are currently estimated to be approximately $380 million for 2007 and approximately $70 million for 2008.
PROPERTIES
Our principal properties are described above under the caption “Valero’s Operations,” and that information is incorporated herein by reference. We also own feedstock and refined product storage facilities in various locations. We believe that our properties and facilities are generally adequate for our operations and that our facilities are maintained in a good state of repair. As of December 31, 2006, we were the lessee under a number of cancelable and non-cancelable leases for certain properties. Our leases are discussed more fully in Note 23 of Notes to Consolidated Financial Statements.
Our patents relating to our refining operations are not material to us as a whole. The trademarks and tradenames under which we conduct our retail and branded wholesale business – including Valero®, Diamond Shamrock®, Shamrock®, Ultramar®, Beacon®, Corner Store®, and Stop N Go® – and other trademarks employed in the marketing of petroleum products are integral to our wholesale and retail marketing operations.
14
EXECUTIVE OFFICERS OF THE REGISTRANT
Name
Positions Held with Valero
William R. Klesse
Gregory C. King
Michael S. Ciskowski
S. Eugene Edwards
Joseph W. Gorder
Richard J. Marcogliese
Mr. Klesse was elected as Valero’s Chairman of the Board on January 18, 2007, and as Chief Executive Officer on December 31, 2005. He was Valero’s Vice-Chairman of the Board from October 31, 2005 to January 18, 2007. He previously served as Executive Vice President and Chief Operating Officer since January 2003. He served as an Executive Vice President of Valero since the closing of our acquisition of Ultramar Diamond Shamrock Corporation (UDS) on December 31, 2001.
Mr. King was elected President in January 2003. He previously served as Executive Vice President and General Counsel since September 2001, and prior to that served as Executive Vice President and Chief Operating Officer since January 2001. Mr. King was Senior Vice President and Chief Operating Officer from 1999 to January 2001.
Mr. Ciskowski was elected Chief Financial Officer in August 2003. Before that, he served as Executive Vice President - Corporate Development since April 2003, and Senior Vice President in charge of business and corporate development since 2001.
Mr. Edwards was elected Executive Vice President - Corporate Development and Strategic Planning in December 2005. Prior to that he had served as a Senior Vice President of Valero since December 2001 with responsibilities for product supply, trading, and wholesale marketing. He was first elected Vice President in 1998. He has held several positions in the company with responsibility for planning and economics, business development, risk management, and marketing.
Mr. Gorder was elected Executive Vice President – Marketing and Supply in December 2005. He had previously served as Senior Vice President – Corporate Development since August 2003. Prior to that he held several positions with Valero and UDS with responsibilities for corporate development and marketing. From October 2000 to May 2002, Mr. Gorder was Executive Vice President and Chief Financial Officer of Calling Solutions, Inc., a telecommunications and customer service provider.
Mr. Marcogliese was elected Executive Vice President - Operations in December 2005. He had previously served as Senior Vice President overseeing refining operations since July 2001. He joined Valero from Exxon Mobil Corporation in May 2000 as the Vice President and General Manager of our Benicia Refinery. He then transferred to our corporate office in June 2001 as head of Strategic Planning.
15
None.
Litigation
For the legal proceedings listed below, we hereby incorporate by reference into this Item our disclosures made in Part II, Item 8 of this report included in Note 25 of Notes to Consolidated Financial Statements under the caption “Litigation Matters.”
MTBE Litigation
Retail Fuel Temperature Litigation
Other Litigation
Environmental Enforcement Matters
While it is not possible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against Valero, we believe that there would be no material effect on our consolidated financial position or results of operations. We are reporting these proceedings to comply with SEC regulations, which require us to disclose proceedings arising under federal, state, or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.
United States Environmental Protection Agency (EPA) Region III, Notice of Non-Compliance/Request to Show Cause, CAA-III-05-008 (December 15, 2005) (Delaware City Refinery). The EPA issued a notice of non-compliance (NON) alleging failure to comply with EPA’s benzene waste NESHAP rule at the Delaware City Refinery for 2004 and 2005. The NON contains a proposed penalty of $130,000 (for which a prior owner of the refinery has agreed to indemnify us).
United States Environmental Protection Agency Region V, Notice of Violation and Finding of Violation EPA-5-05-OH-16 (June 28, 2005) (Lima Refinery). The EPA issued a notice and finding of violation (NOV) relating to an inspection that occurred at the Lima Refinery in October and November 2001. The NOV cites alleged violations under leak detection and repair regulations and tank floating roof regulations. The NOV does not specify any remedy sought by the EPA.
United States Environmental Protection Agency, Region VI, Notice of Violation (June 15, 2005) (Port Arthur Refinery). The EPA issued a notice and finding of violation concerning past flaring issues at the Port Arthur Refinery that occurred prior to our Premcor Acquisition. The EPA subsequently proposed a penalty of $8 million.
Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery). In 2005, the BAAQMD issued 27 violation notices (VNs) for various incidents at our Benicia Refinery and asphalt plant, including alleged excess emissions, recordkeeping discrepancies, and other matters. No penalties have been assessed for the VNs. We are negotiating a settlement with the BAAQMD for these matters. In 2006, the BAAQMD issued an additional 23 VNs for these facilities containing allegations similar to the 2005 VNs. We also plan to pursue settlement of the 2006 VNs.
16
Delaware Department of Natural Resources and Environmental Control (DDNREC) (Delaware City Refinery). Our Delaware City Refinery is subject to six outstanding notices of violation relating to alleged excess air emissions at the refinery. We have additionally self-reported other known noncompliance issues with air regulations at the refinery in connection with our attempt to settle all potential air-regulation violations with the DDNREC. The DDNREC’s initial penalty demand for these matters was $1.86 million, but we continue to negotiate the terms of a proposed settlement.
New Jersey Department of Environmental Protection (NJDEP) (Paulsboro Refinery). We are subject to 16 outstanding air-related Administrative Order and Notice of Civil Administrative Penalty Assessments (Notices) issued by the NJDEP relating to our Paulsboro Refinery. The Notices propose an aggregate penalty of $507,800. We have appealed certain of these Notices.
Ohio Environmental Protection Agency (Ohio EPA) (Lima Refinery). The Ohio EPA issued a proposed order to our Lima Refinery related to hydrogen sulfide levels in sewer gases routed to the refinery’s wastewater thermal oxidizer. The proposed order states a penalty of $350,000 for alleged New Source Performance Standards Subpart J violations. We are negotiating to settle this matter.
People of the State of Illinois, ex rel. v. The Premcor Refining Group Inc., et al., Third Judicial Circuit Court, Madison County (Case No. 03-CH-00459, filed May 29, 2003) (Hartford refinery and terminal). The Illinois Environmental Protection Agency (Illinois EPA) has issued several NOVs alleging violations of air and waste regulations at Premcor’s Hartford, Illinois terminal and now-closed refinery. We are negotiating the terms of a consent order for corrective action.
Texas Commission on Environmental Quality (TCEQ) (Port Arthur Refinery). In September 2005, we received two enforcement actions from the TCEQ relating to alleged Texas Clean Air Act violations at the Port Arthur Refinery dating back to 2002. The TCEQ has proposed penalties totaling $880,240 for these events. We have generally denied the allegations.
17
PART II
Our common stock is traded on the New York Stock Exchange under the symbol “VLO.”
As of January 31, 2007, there were 8,478 holders of record of our common stock.
The following table shows the high and low sales prices of and dividends declared on our common stock for each quarter of 2006 and 2005.
Sales Prices of the
Common Stock
Dividends
Per
Common Share
Quarter Ended
2006:
December 31
September 30
June 30
March 31
2005:
On January 18, 2007, our board of directors declared a regular quarterly cash dividend of $0.12 per common share payable March 14, 2007 to holders of record at the close of business on February 14, 2007.
Dividends are considered quarterly by the board of directors and may be paid only when approved by the board.
During 2005 and 2006, 19,819,963 shares of our common stock, together with cash in lieu of fractional shares, were issued upon conversion of 10,000,000 shares of our 2% mandatory convertible preferred stock as discussed in Note 14 of Notes to Consolidated Financial Statements. The issuances of such shares were exempt from registration under Section 3(a)(9) of the Securities Act of 1933, as amended.
18
The following table discloses purchases of shares of Valero’s common stock made by us or on our behalf during the fourth quarter of 2006.
Period
Number ofSharesPurchased
Total Number of
Shares Not
Purchased as Part of
Publicly AnnouncedPlans or Programs
(1)
Total Number ofShares Purchased asPart of Publicly
Announced Plans or
Programs
Maximum Number (orApproximate Dollar
Value) of Shares that
May Yet Be Purchased
Under the Plans orPrograms (2)
October 2006
November 2006
December 2006
19
The following Performance Graph is not “soliciting material,” is not deemed filed with the SEC, and is not to be incorporated by reference into any of Valero’s filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended, respectively.
The following line graph compares the cumulative total return* on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (selected by us) for the five-year period commencing December 31, 2001 and ending December 31, 2006. The peer group consists of the following ten companies that are engaged in the domestic energy industry: Chevron Corporation, ConocoPhillips, Exxon Mobil Corporation, Frontier Oil Corporation, Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Occidental Petroleum Corporation, Sunoco, Inc., and Tesoro Corporation.
Valero Common Stock
S&P 500
Peer Group
This Performance Graph and the related textual information are based on historical data and are not necessarily indicative of future performance.
20
The selected financial data for the five-year period ended December 31, 2006 was derived from our audited consolidated financial statements. The following table should be read together with the historical consolidated financial statements and accompanying notes included in Item 8, “Financial Statements and Supplementary Data,” and with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
The following summaries are in millions of dollars except for per share amounts:
Operating revenues (e)
Operating income
Net income
Earnings per common share - assuming dilution
Dividends per common share
Property, plant and equipment, net
Goodwill
Total assets
Long-term debt and capital lease obligations (less current portions)
Company-obligated preferred securities of subsidiary trusts
Stockholders’ equity
21
The following review of our results of operations and financial condition should be read in conjunction with Items 1, 1A and 2, “Business, Risk Factors and Properties,” and Item 8, “Financial Statements and Supplementary Data,” included in this report. In the discussions that follow, all per-share amounts assume dilution.
CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report, including without limitation our disclosures below under the heading “Results of Operations - Outlook,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “believe,” “expect,” “plan,” “intend,” “estimate,” “project,” “projection,” “predict,” “budget,” “forecast,” “goal,” “guidance,” “target,” “will,” “could,” “should,” “may,” and similar expressions.
These forward-looking statements include, among other things, statements regarding:
future refining margins, including gasoline and distillate margins;
future retail margins, including gasoline, diesel, home heating oil, and convenience store merchandise margins;
expectations regarding feedstock costs, including crude oil differentials, and operating expenses;
anticipated levels of crude oil and refined product inventories;
our anticipated level of capital investments, including deferred refinery turnaround and catalyst costs and capital expenditures for environmental and other purposes, and the effect of those capital investments on our results of operations;
anticipated trends in the supply of and demand for crude oil and other feedstocks and refined products in the United States, Canada, and elsewhere;
expectations regarding environmental, tax, and other regulatory initiatives; and
the effect of general economic and other conditions on refining and retail industry fundamentals.
We based our forward-looking statements on our current expectations, estimates, and projections about ourselves and our industry. We caution that these statements are not guarantees of future performance and involve risks, uncertainties, and assumptions that we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual results may differ materially from the future performance that we have expressed or forecast in the forward-looking statements. Differences between actual results and any future performance suggested in these forward-looking statements could result from a variety of factors, including the following:
acts of terrorism aimed at either our facilities or other facilities that could impair our ability to produce or transport refined products or receive feedstocks;
political and economic conditions in nations that consume refined products, including the United States, and in crude oil producing regions, including the Middle East and South America;
the domestic and foreign supplies of refined products such as gasoline, diesel fuel, jet fuel, home heating oil, and petrochemicals;
the domestic and foreign supplies of crude oil and other feedstocks;
the ability of the members of the Organization of Petroleum Exporting Countries (OPEC) to agree on and to maintain crude oil price and production controls;
the level of consumer demand, including seasonal fluctuations;
refinery overcapacity or undercapacity;
22
the actions taken by competitors, including both pricing and the expansion and retirement of refining capacity in response to market conditions;
environmental, tax, and other regulations at the municipal, state, and federal levels and in foreign countries;
the level of foreign imports of refined products;
accidents or other unscheduled shutdowns affecting our refineries, machinery, pipelines, or equipment, or those of our suppliers or customers;
changes in the cost or availability of transportation for feedstocks and refined products;
the price, availability, and acceptance of alternative fuels and alternative-fuel vehicles;
delay of, cancellation of, or failure to implement planned capital projects and realize the various assumptions and benefits projected for such projects or cost overruns in constructing such planned capital projects;
earthquakes, hurricanes, tornadoes, and irregular weather, which can unforeseeably affect the price or availability of natural gas, crude oil and other feedstocks, and refined products;
rulings, judgments, or settlements in litigation or other legal or regulatory matters, including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;
legislative or regulatory action, including the introduction or enactment of federal, state, municipal, or foreign legislation or rulemakings, which may adversely affect our business or operations;
changes in the credit ratings assigned to our debt securities and trade credit;
changes in currency exchange rates, including the value of the Canadian dollar relative to the U.S. dollar; and
overall economic conditions.
Any one of these factors, or a combination of these factors, could materially affect our future results of operations and whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.
All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
23
OVERVIEW
The strong industry fundamentals we experienced throughout 2005 continued during 2006, resulting in the highest net income in our history of $5.5 billion, 52% higher than the net income reported in 2005. Our profitability is substantially determined by the spread between the price of refined products and the price of crude oil, referred to as the “refined product margin.” Refined product margins for the year 2006, both for gasoline and distillates, were comparable to the strong margins realized in 2005. Heavy industry-wide turnaround activity, the implementation of more restrictive sulfur regulations on gasoline and diesel, increased use of ethanol and decreased use of MTBE in the reformulated gasoline pool, and limited capacity expansions due to the high cost of compliance with environmental regulations resulted in tighter supplies of refined products and strong margins during most of 2006. Since approximately 60% of our total crude oil throughput represents sour crude oil and acidic sweet crude oil feedstocks that are purchased at prices less than sweet crude oil, our profitability is also significantly affected by the spread between sweet crude oil and sour crude oil prices, referred to as the “sour crude oil differential.” Sour crude oil differentials for 2006 were also about as wide as the very favorable differentials experienced in 2005. In addition to these continuing strong industry fundamentals, we benefited significantly from the addition of the four former Premcor refineries, which generated $2.5 billion of operating income, or 31% of our total operating income of $8.0 billion, with average throughput volumes of 792,000 barrels per day during 2006.
In addition to the operating income effects discussed above, we monetized our entire ownership interest in Valero L.P. by selling all of our units in Valero GP Holdings, LLC during 2006, generating proceeds of $880 million and recognizing a pre-tax gain of $328 million. This sale, along with our favorable operating results, resulted in a strong balance sheet as of December 31, 2006. We reduced debt by $245 million during 2006 and increased our cash balance to $1.6 billion at year-end, while at the same time purchasing $2.0 billion, or approximately 5%, of our outstanding shares.
24
RESULTS OF OPERATIONS
2006 Compared to 2005
Financial Highlights
(millions of dollars, except per share amounts)
Operating revenues (c)
Costs and expenses:
Cost of sales (a) (c)
Refining operating expenses
Retail selling expenses
General and administrative expenses
Depreciation and amortization expense:
Refining
Retail
Corporate
Total costs and expenses
Equity in earnings of Valero L.P.
Other income, net
Interest and debt expense:
Incurred
Capitalized
Minority interest in net income of Valero GP Holdings, LLC
Income before income tax expense
Income tax expense
Preferred stock dividends
Net income applicable to common stock
Earnings per common share – assuming dilution
25
Operating Highlights
(millions of dollars, except per barrel and per gallon amounts)
Refining:
Operating income (a)
Throughput margin per barrel (d)
Operating costs per barrel:
Depreciation and amortization
Total operating costs per barrel
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude
Medium/light sour crude
Acidic sweet crude
Sweet crude
Residuals
Other feedstocks
Total feedstocks
Blendstocks and other
Total throughput volumes
Yields (thousand barrels per day):
Gasolines and blendstocks
Distillates
Petrochemicals
Other products (e)
Total yields
Retail – U.S.:
Company-operated fuel sites (average)
Fuel volumes (gallons per day per site)
Fuel margin per gallon
Merchandise sales
Merchandise margin (percentage of sales)
Margin on miscellaneous sales
Depreciation and amortization expense
Retail – Canada:
Fuel volumes (thousand gallons per day)
See the footnote references on pages 28 and 29.
26
Refining Operating Highlights by Region (f)
(millions of dollars, except per barrel amounts)
Gulf Coast:
Throughput volumes (thousand barrels per day) (g)
Mid-Continent (h):
Northeast:
West Coast:
Throughput volumes (thousand barrels per day)
Operating income for regions above
LIFO charge (a)
Total refining operating income
27
Average Market Reference Prices and Differentials (i)
(dollars per barrel)
West Texas Intermediate (WTI) crude oil
WTI less sour crude oil at U.S. Gulf Coast (j)
WTI less Alaska North Slope (ANS) crude oil
WTI less Maya crude oil
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI
No. 2 fuel oil less WTI
Propylene less WTI
U.S. Mid-Continent:
Low-sulfur diesel less WTI
U.S. Northeast:
Lube oils less WTI
U.S. West Coast:
CARBOB 87 gasoline less ANS
CARB diesel less ANS
28
General
Operating revenues increased 12% for the year ended December 31, 2006 compared to the year ended December 31, 2005 primarily as a result of higher refined product prices combined with additional throughput volumes from the former Premcor refinery operations. Operating income and net income for the year ended December 31, 2006 increased significantly compared to the year ended December 31, 2005. Operating income increased $2.6 billion, or 47%, from 2005 to 2006 due to a $2.6 billion increase in the refining segment and a $28 million increase in the retail segment, partially offset by a $47 million increase in general and administrative expenses (including corporate depreciation and amortization expense).
Operating income for our refining segment increased from $5.9 billion for the year ended December 31, 2005 to $8.5 billion for the year ended December 31, 2006 resulting from a 19% increase in throughput volumes and an increase in refining throughput margin of $1.15 per barrel, or 10%, partially offset by increased refining operating expenses (including depreciation and amortization expense) of $1.2 billion. In addition, the increase in the 2006 results was partially attributable to the unfavorable impact in 2005 of a $621 million pre-tax LIFO charge related to the difference between the fair market value recorded for the inventories acquired in the Premcor Acquisition under purchase accounting and the amounts required to be recorded in applying Valero’s LIFO accounting policy.
The change in refining throughput margin for 2006 compared to 2005 was impacted by the following factors:
Throughput volumes increased 472,000 barrels per day during 2006 compared to 2005 due to 545,000 barrels per day of incremental throughput from the four former Premcor refineries, offset to some extent by the sale of the Denver Refinery in 2005 and significant planned and unplanned downtime at several of our refineries in 2006.
Overall, gasoline and distillate margins increased in 2006 compared to 2005 due to significantly improved margins in the first half of 2006 attributable to increased foreign and U.S. demand, limited capacity additions, major industry turnaround activity, and continuing outages from last season’s hurricanes. However, the 2006 increase in gasoline and distillate margins was somewhat diminished in the second half of 2006 due to excess refined product supply and the higher margins experienced in September and October of 2005 due to the impact of Hurricanes Katrina and Rita.
Differentials on sour crude oil feedstocks during 2006 were essentially unchanged from the strong differentials in 2005, and remained wide due to continued ample supplies of sour crude oils and heavy sour residual fuel oils on the world market. Differentials on sour crude oil feedstocks also continued to benefit from increased demand for sweet crude oil resulting from lower sulfur specifications for gasoline and diesel and a global increase in refined product demand, particularly in Asia, which has resulted in higher utilization rates by refineries that require sweet crude oil as feedstock.
Throughput margin improved in 2006 due to the negative impact in 2005 of pre-tax losses of approximately $525 million on hedges related to forward sales of distillates and associated forward purchases of crude oil.
29
Margins on other refined products such as petroleum coke and sulfur were lower in 2006 due to an increase in the price of crude oil from 2005 to 2006.
Refining operating expenses, excluding depreciation and amortization expense, were 32% higher for the year ended December 31, 2006 compared to the year ended December 31, 2005, due primarily to the Premcor Acquisition on September 1, 2005. Excluding the effect of the Premcor Acquisition, operating expenses increased 5% due mainly to increases in maintenance expense, employee compensation and related benefits, outside services, and catalyst and chemicals, partially offset by reduced energy costs. Refining depreciation and amortization expense increased 42% from 2005 to 2006 primarily due to the Premcor Acquisition, the implementation of new capital projects, and increased turnaround and catalyst amortization.
Retail operating income was $182 million for the year ended December 31, 2006 compared to $154 million for the year ended December 31, 2005. This 18% increase in operating income was primarily attributable to improved retail fuel margins and increased in-store sales in the U.S. system, partially offset by higher selling expenses due mainly to an increase in credit card processing fees.
Corporate Expenses and Other
General and administrative expenses, including corporate depreciation and amortization expense, increased $47 million for the year ended December 31, 2006 compared to the year ended December 31, 2005. The increase was primarily due to increases in employee compensation and benefits, stock-based compensation expense, environmental expenses, and charitable contributions as well as the favorable resolution of a California excise tax dispute in 2005. These increases were partially offset by a decrease in variable compensation expense and 2005 nonrecurring expenses attributable to Premcor headquarters personnel.
“Other income, net” for the year ended December 31, 2006 includes a pre-tax gain of $328 million related to the sale of our ownership interest in Valero GP Holdings, LLC in 2006, as discussed in Note 9 of Notes to Consolidated Financial Statements.
Interest and debt expense incurred increased from 2005 to 2006 due to the effect of a full year of interest incurred in 2006 on the debt assumed in the Premcor Acquisition, partially offset by a reduction in other debt outstanding. Capitalized interest increased due to an increase in capital projects, including projects at the four former Premcor refineries.
Income tax expense increased $1.0 billion from 2005 to 2006 mainly as a result of a 55% increase in income before income tax expense. Our effective tax rate for the year ended December 31, 2006 increased from the year ended December 31, 2005 as a lower percentage of our pre-tax income was contributed by the Aruba Refinery, the profits of which are non-taxable in Aruba through December 31, 2010. This increase in the effective tax rate was partially offset by the effects of new tax legislation in both Texas and Canada in 2006.
30
2005 Compared to 2004
Operating revenues (d)
Cost of sales (a) (d)
Other income (expense), net
See the footnote references on pages 34 and 35.
31
Throughput margin per barrel (e)
Throughput volumes (thousand barrels per day) (f):
Other products (g)
32
Refining Operating Highlights by Region (h)
Throughput volumes (thousand barrels per day) (f) (i)
Mid-Continent (j):
Throughput volumes (thousand barrels per day) (i)
33
Average Market Reference Prices and Differentials (k)
WTI crude oil
WTI less sour crude oil at U.S. Gulf Coast (l)
WTI less ANS crude oil
The following notes relate to references on pages 31 through 34.
The regions reflected herein contain the following refineries subsequent to the Premcor Acquisition: the Gulf Coast refining region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, Krotz Springs, St. Charles, Aruba, and Port Arthur Refineries; the Mid-Continent refining region includes the McKee, Ardmore, Memphis, and Lima
34
Refineries; the Northeast refining region includes the Quebec City, Paulsboro, and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.
Operating revenues increased 50% for the year ended December 31, 2005 compared to the year ended December 31, 2004 primarily as a result of significantly higher refined product prices combined with additional throughput volumes from refinery operations. Operating income and net income for the year ended December 31, 2005 increased significantly compared to the year ended December 31, 2004. Operating income increased $2.5 billion, or 83%, from 2004 to 2005 due primarily to a $2.6 billion increase in the refining segment, partially offset by a $30 million decrease in the retail segment and a $123 million increase in general and administrative expenses (including corporate depreciation and amortization expense).
Operating income for our refining segment increased from $3.3 billion for the year ended December 31, 2004 to $5.9 billion for the year ended December 31, 2005, resulting mainly from an increase in refining throughput margin of $3.70 per barrel, or 50%, and a 15% increase in throughput volumes, partially offset by an increase in refining operating expenses (including depreciation and amortization expense) of $977 million and the 2005 LIFO charge discussed in the “2006 Compared to 2005 Results of Operations.”
Refining throughput margin for 2005 increased primarily due to the following factors:
Distillate margins increased significantly in all of our refining regions during 2005 compared to 2004, with margins in the Gulf Coast region almost triple the margins in 2004 and margins in the Mid-Continent and Northeast regions more than double 2004 margins. The improvement in distillate margins was due to increased foreign and U.S. demand, resulting from improved U.S. and global economies and higher demand for on-road diesel and jet fuel. In addition, both gasoline and distillate margins increased significantly in September and October of 2005 due to the impact of Hurricanes Katrina and Rita, which reduced the supply of refined products as refineries along the Gulf Coast reduced or shut down their operations because of the hurricanes.
Differentials on our sour crude oil feedstocks improved during 2005 compared to 2004 due to ample supplies of sour crude oils and heavy sour residual fuel oils on the world market. In addition, differentials on sour crude oil feedstocks benefited from increased demand for sweet crude oil resulting from several factors, including (i) the global movement to cleaner fuels, which has required most refineries to lower the sulfur content of the gasoline they produce, and (ii) a global increase in refined product demand, particularly in Asia, which has resulted in higher utilization rates by refineries that require sweet crude oil as feedstock.
35
Throughput volumes increased 326,000 barrels per day in 2005 compared to 2004 due mainly to throughput of 247,000 barrels per day at the four refineries acquired from Premcor on September 1, 2005, incremental throughput of 40,000 barrels per day at the Aruba Refinery, which was acquired in March 2004, and lower volumes in 2004 due to turnarounds at the St. Charles, Benicia, and Wilmington Refineries.
The above increases in throughput margin for 2005 were partially offset by the effects of:
lower margins on other refined products such as petroleum coke, sulfur, No. 6 fuel oil, asphalt, and propylene due to a significant increase in the price of crude oil from 2004 to 2005, and
increased pre-tax losses of approximately $295 million on hedges related to forward sales of distillates and associated forward purchases of crude oil.
Refining operating expenses, excluding depreciation and amortization expense, were 37% higher for the year ended December 31, 2005 compared to the year ended December 31, 2004 due mainly to $420 million of expenses related to the refineries acquired in the Premcor Acquisition, a full year of operations of the Aruba Refinery, and increases in energy costs, employee compensation expense, and maintenance expense. Refining depreciation and amortization expense increased 39% from 2004 to 2005 due mainly to depreciation expense resulting from the Premcor Acquisition on September 1, 2005, implementation of new capital projects, increased turnaround and catalyst amortization, a $15 million gain in 2004 on the sale of certain property discussed in Note 6 of Notes to Consolidated Financial Statements, and the write-off of costs in 2005 resulting from the decision to convert wholesale sites marketing under the Diamond Shamrock brand to the Valero brand.
Retail operating income was $154 million for the year ended December 31, 2005 compared to $184 million for the year ended December 31, 2004, a decrease of 16% between the periods. The decrease was primarily attributable to increased selling expenses in the U.S. and Canada as higher retail fuel prices resulted in higher credit card processing fees. In addition, Canada’s selling expenses increased $15 million due to an increase in the Canadian dollar exchange rate.
General and administrative expenses, including corporate depreciation and amortization expense, increased $123 million for the year ended December 31, 2005 compared to the year ended December 31, 2004, primarily due to increases in employee compensation and benefits, the recognition of increased variable compensation expense, resulting in large part from a significant increase in our common stock price during 2005, and expenses attributable to Premcor headquarters personnel. These increases were partially offset by the successful resolution in the first quarter of 2005 of a California excise tax dispute.
“Other income (expense), net” improved $101 million for the year ended December 31, 2005 compared to the year ended December 31, 2004 primarily due to the combined effect of a $55 million gain realized on the sale of our equity interests in Javelina Company and Javelina Pipeline Company in November 2005 and a 2004 impairment charge of $57 million to write off the carrying amount of our equity investment in Clear Lake Methanol Partners, L.P. This combined effect, as well as an increase in bank interest income due to higher cash balances, was partially offset by our 50% interest in certain debt refinancing costs incurred in 2005 by the Cameron Highway Oil Pipeline joint venture and increased costs related to our accounts receivable sales program.
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Interest and debt expense incurred increased from 2004 to 2005 due to interest incurred in 2005 on the debt resulting from the Premcor Acquisition. Capitalized interest increased due to an increase in capital projects, including projects at the four former Premcor refineries.
Income tax expense increased $791 million from 2004 to 2005 mainly as a result of a 95% increase in income before income tax expense. Our effective tax rate for the year ended December 31, 2005, however, decreased from the year ended December 31, 2004 primarily as a result of a change in permanent book-to-tax differences, which included a deduction from income in 2005 for qualified domestic manufacturing activities, as allowed under the American Jobs Creation Act of 2004.
OUTLOOK
In January 2007, we saw industry fundamentals for refined products remain consistent with what we experienced at the end of 2006. The Gulf Coast gasoline margin for January 2007 was $4.62 per barrel, while the West Coast gasoline margin averaged $20.34 per barrel. Regarding distillates, the Gulf Coast on-road diesel margin was $13.00 per barrel and the West Coast on-road diesel margin was $28.94 per barrel.
Our outlook for gasoline margins is positive. Gasoline supplies are expected to tighten as spring maintenance activity gets underway. In addition, the industry will soon be making the transition from winter-grade gasoline specifications to summer-grade specifications, which generally leads to declines in inventories and higher margins as we head toward the summer driving season. While these factors are expected to reduce supplies, gasoline demand is expected to remain positive this year as a result of lower pump prices and a continuing strong economy. This positive demand trend combined with the expected pressure on supplies should create a tightening of the supply/demand balance.
The outlook for low-sulfur distillate margins is also favorable as on-road diesel demand continues to be strong. Currently, approximately 80% of our U.S. on-road distillate production is ultra-low-sulfur diesel (ULSD) and we are on schedule to meet the EPA’s phase-in requirements for ULSD by the end of the transition period in June 2007. In addition, specifications requiring a reduction in the amount of sulfur in off-road diesel (excluding marine and railroad uses) go into effect in June of this year, which may further tighten supplies. As a result, we expect the favorable spread between on-road and off-road diesel prices to continue.
Sour crude oil differentials are expected to remain favorable for the foreseeable future. Persistently weak residual fuel oil prices support wider differentials for sour crude oil since complex refiners can substitute residual fuel oil for a portion of their sour crude oil purchases if residual fuel oil becomes more economic to process than crude oil. In addition, the flexibility of many of our refineries to process alternative sour crude oils allows us to continue to find attractively priced feedstocks.
Operationally during 2007, we expect to benefit from our recently completed Port Arthur crude unit expansion which allows us to process up to 325,000 barrels per day of sour crude oil at that refinery.
On February 16, 2007, our McKee Refinery experienced a fire in its propane deasphalting unit. As of the filing of this annual report, the entire McKee Refinery remains shut down while efforts are underway to determine the cause of the accident, assess damages, and establish a plan for making repairs. Full scale efforts to assess damages, make repairs, and restart the refinery are underway though we do not yet have a firm estimated date for commencement of operations. Although we are in the preliminary stages of assessing the extent of damages, we do not believe that this incident will have a material adverse effect on our results of operations for the first quarter of 2007.
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Overall, we believe that we are well-positioned to capitalize on the expected continuing positive industry fundamentals during 2007.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows for the Year Ended December 31, 2006
Net cash provided by operating activities for the year ended December 31, 2006 was $6.3 billion compared to $5.9 billion for the year ended December 31, 2005. The increase in cash generated from operating activities was due primarily to the significant increase in operating income discussed above under “Results of Operations,” partially offset by a $1.2 billion decrease from an unfavorable change in working capital between the years and a $1.0 billion increase in current income tax expense. Changes in cash provided by or used for working capital during the years ended December 31, 2006 and 2005 are shown in Note 16 of Notes to Consolidated Financial Statements. The primary difference in the working capital changes between the two years resulted from a favorable working capital change in 2005 attributable to the factors discussed below in “Cash Flows for the Year Ended December 31, 2005.” Both receivables and accounts payable increased in 2006 due mainly to price increases for gasoline and crude oil.
The net cash generated from operating activities during the year ended December 31, 2006, combined with $880 million of proceeds from the sale of our ownership interest in Valero GP Holdings, LLC, a $206 million benefit from tax deductions in excess of recognized stock-based compensation cost, and $122 million of proceeds from the issuance of common stock related to our employee benefit plans, were used mainly to:
fund $3.8 billion of capital expenditures and deferred turnaround and catalyst costs;
purchase 34.6 million shares of treasury stock at a cost of $2.0 billion;
make long-term note repayments of $249 million;
fund $101 million of contingent earn-out payments in connection with the acquisition of Basis Petroleum, Inc., the St. Charles Refinery, and the Delaware City Refinery;
terminate our interest rate swap contracts for $54 million;
pay common and preferred stock dividends of $184 million; and
increase available cash on hand by $1.2 billion.
Cash Flows for the Year Ended December 31, 2005
Net cash provided by operating activities for the year ended December 31, 2005 was $5.9 billion compared to $3.0 billion for the year ended December 31, 2004, an increase of $2.9 billion. The increase in cash generated from operating activities was due primarily to the significant increase in operating income discussed above under “Results of Operations” and an $879 million increase from favorable working capital changes between the years, as reflected in Note 16 of Notes to Consolidated Financial Statements. For the year ended December 31, 2005, working capital was positively impacted by a $400 million increase in the amount of receivables sold under our accounts receivable sales program and a decrease in restricted cash of approximately $200 million due to the repayment of certain debt assumed in the Premcor Acquisition using funds restricted for that purpose. Both receivables and accounts payable increased significantly due to commodity price increases from December 31, 2004 to December 31, 2005.
The net cash generated from operating activities during 2005, combined with $428 million of available cash on hand, $182 million of proceeds from the issuance of common stock related to our employee benefit plans, $78 million of proceeds from the sale of our investment in the Javelina joint venture, $45 million of proceeds from the sale of the Denver Refinery, and a $38 million net return of investment from the Cameron Highway Oil Pipeline joint venture resulting mainly from the refinancing of the joint venture’s debt in June 2005, were used mainly to:
fund $2.6 billion of capital expenditures and deferred turnaround and catalyst costs;
make long-term note repayments of $874 million;
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fund $2.3 billion of the Premcor Acquisition, net of cash acquired;
purchase 13 million shares of treasury stock at a cost of $571 million;
fund contingent earn-out payments of $85 million in connection with prior acquisitions;
fund certain minor acquisitions for $62 million;
make a general partner contribution to Valero L.P. of $29 million; and
pay common and preferred stock dividends of $106 million.
Capital Investments
During the year ended December 31, 2006, we expended $3.2 billion for capital expenditures and $569 million for deferred turnaround and catalyst costs. Capital expenditures for the year ended December 31, 2006 included approximately $1.6 billion of costs related to environmental projects. In addition, we expended $101 million for amounts due under contingent earn-out agreements.
In connection with our acquisitions of Basis Petroleum, Inc. in 1997 and the St. Charles Refinery in 2003, the sellers are entitled to receive payments in any of the ten years and seven years, respectively, following these acquisitions if certain average refining margins during any of those years exceed a specified level (see the discussion in Note 23 of Notes to Consolidated Financial Statements). In connection with the Premcor Acquisition, we assumed Premcor’s obligation under a contingent earn-out agreement related to Premcor’s acquisition of the Delaware City Refinery from Motiva Enterprises LLC (Motiva). Under this agreement, Motiva was entitled to receive two separate annual earn-out contingency payments depending on (a) the amount of crude oil processed at the refinery and the level of refining margins through May 2007, and (b) the achievement of certain performance criteria at the gasification facility through May 2006. The earn-out contingency related to the gasification facility expired in 2006 with no payment required. Payments due under all of these earn-out arrangements are limited based on annual and aggregate limits. During 2006, we made earn-out payments of $26 million (the maximum remaining payment based on the aggregate limitation under the agreement) related to the acquisition of Basis Petroleum, Inc., $50 million related to the acquisition of the St. Charles Refinery, and $25 million related to the acquisition of the Delaware City Refinery. In January 2007, we made an earn-out payment of $50 million related to the St. Charles Refinery. Based on estimated margin levels through April 2007, earn-out payments of $25 million (the maximum remaining payment based on the aggregate limitation under the agreement) related to the acquisition of the Delaware City Refinery would be due in the second quarter of 2007.
For 2007, we expect to incur approximately $3.5 billion for capital investments, including approximately $3.1 billion for capital expenditures (approximately $800 million of which is for environmental projects) and approximately $400 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes anticipated expenditures related to the contingent earn-out agreements discussed above and strategic acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.
Contractual Obligations
Our contractual obligations as of December 31, 2006 are summarized below (in millions).
Long-term debt
Capital lease obligations
Operating lease obligations
Purchase obligations
Other long-term liabilities
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Long-Term Debt
Payments for long-term debt are at stated values.
During March 2006, we made a scheduled debt repayment of $220 million related to our 7.375% notes. In addition, during 2006, we made debt payments of $29 million related to various notes as discussed in Note 12 of Notes to Consolidated Financial Statements.
As of December 31, 2006, “current portion of long-term debt and capital lease obligations” as reflected in the consolidated balance sheet included mainly $230 million of notes which become due in April 2007 and $50 million of notes which become due in November 2007, as well as $175 million of notes with a maturity date of February 2010 which were redeemed in February 2007, as discussed in Note 12 of Notes to Consolidated Financial Statements.
Our agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt to below investment grade ratings by Moody’s Investors Service and Standard & Poor’s Ratings Services, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. As of December 31, 2006, all of our ratings on our senior unsecured debt are at or above “investment grade” level as follows:
Rating Agency
Rating
Standard & Poor’s Ratings Services
Moody’s Investors Service
Fitch Ratings
Operating Lease Obligations
Our operating lease obligations include leases for land, office facilities and equipment, retail facilities and equipment, dock facilities, transportation equipment, and various facilities and equipment used in the storage, transportation, production, and sale of refinery feedstocks and refined products. Operating lease obligations include all operating leases that have initial or remaining noncancelable terms in excess of one year, and are not reduced by minimum rentals to be received by us under subleases.
Purchase Obligations
A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum, or variable price provisions, and (iii) the approximate timing of the transaction. We have various purchase obligations including industrial gas and chemical supply arrangements (such as hydrogen supply arrangements), crude oil and other feedstock supply arrangements, and various throughput and terminalling agreements. We enter into these contracts to ensure an adequate supply of utilities, feedstock, and storage to operate our refineries. Substantially all of our purchase obligations are based on market prices or adjustments based on market indices. Certain of these purchase obligations include fixed or minimum volume requirements, while others are based on our usage requirements. The purchase obligation amounts included in the table above include both short-term and long-term obligations and are based on (a) fixed or minimum quantities to be purchased and (b) fixed or estimated prices to be paid based on current market conditions. As of December 31, 2006, our short-term and long-term purchase obligations decreased by approximately $2.0 billion from the amount reported as of December 31, 2005. The decrease is primarily attributable to a decrease in obligations under crude oil supply contracts, partially offset by new contracts in 2006. We have not made in the past, nor do we expect to make in the future, payments for feedstock or services that we have not received or will not receive, nor paid prices in excess of then prevailing market conditions.
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Other Long-term Liabilities
Our “other long-term liabilities” are described in Note 13 of Notes to Consolidated Financial Statements. For most of these liabilities, the timing of the payment of such liabilities is not fixed and therefore cannot be determined as of December 31, 2006. However, certain expected payments related to our anticipated pension contribution in 2007 and our other postretirement benefit obligations are discussed in Note 21 of Notes to Consolidated Financial Statements. For purposes of reflecting amounts for other long-term liabilities in the table above, we have made our best estimate of expected payments for each type of liability based on information available as of December 31, 2006.
Other Commercial Commitments
As of December 31, 2006, our committed lines of credit were as follows:
Borrowing
Capacity
Revolving credit facility
Canadian revolving credit facility
As of December 31, 2006, we had $343 million of letters of credit outstanding under uncommitted short-term bank credit facilities, Cdn. $85 million of letters of credit outstanding under our Canadian committed revolving credit facility, and $245 million of letters of credit outstanding under our committed revolving credit facility. These letters of credit expire during 2007, 2008, and 2009.
Stock Purchase Programs
Our board of directors has approved our purchase of treasury stock in open market transactions to satisfy employee benefit plan requirements as well as purchases under our publicly announced stock purchase programs. Under these authorizations, we purchased approximately 5% of our outstanding shares during 2006. We purchased 28.9 million shares for $1.6 billion related to our employee benefit plans and 5.7 million shares for $361 million under our former stock purchase program.
On October 19, 2006, our board of directors approved a new $2 billion common stock purchase program. This new authorization is in addition to our existing authorization for employee benefit plan requirements. Stock purchases under this program will be made from time to time at prevailing prices as permitted by securities laws and other legal requirements, and are subject to market conditions and other factors. The program does not have a scheduled expiration date. During 2006, we purchased no shares under our new $2 billion stock purchase program.
Sale of Investment in Valero GP Holdings, LLC
On July 19, 2006, Valero GP Holdings, LLC consummated an initial public offering (IPO) of 17,250,000 of its units representing limited liability company interests to the public at $22.00 per unit, before an underwriters’ discount of $1.265 per unit. On December 22, 2006, Valero GP Holdings, LLC completed a secondary public offering of 20,550,000 units representing limited liability company interests at a price of $21.62 per unit, before an underwriters’ discount of $0.8648 per unit. In addition, 4,700,000 unregistered units of Valero GP Holdings, LLC were sold to its chairman of the board of directors (who was at that time also chairman of Valero’s board of directors) at $21.62 per unit. All such units were sold by our subsidiaries that held various ownership interests in Valero GP Holdings, LLC. As a result, Valero GP Holdings, LLC did not receive any proceeds from these offerings, and our indirect ownership interest in Valero GP Holdings, LLC was reduced to zero.
Proceeds to our selling subsidiaries from the IPO totaled approximately $355 million, net of the underwriters’ discount and other offering expenses, which resulted in a pre-tax gain to us of $132 million on the sale of the units. Proceeds to our selling subsidiaries from the secondary offering and private sale of units totaled
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approximately $525 million, net of the underwriters’ discount and other offering expenses, which resulted in an additional pre-tax gain to us of $196 million. The total pre-tax gain of $328 million is included in “other income (expense), net” in the consolidated statement of income for the year ended December 31, 2006. The funds received from these offerings are being used for general corporate purposes.
Pension Plan Funded Status
During 2006, we contributed $343 million to our qualified pension plans. Based on a 5.75% discount rate and fair values of plan assets as of December 31, 2006, the fair value of the assets in our qualified pension plans was equal to approximately 104% of the projected benefit obligation under those plans as of the end of 2006.
Although we have no expected minimum required contribution to our qualified pension plans during 2007 under the Employee Retirement Income Security Act, we expect to contribute approximately $100 million to our qualified plans during 2007.
We are subject to extensive federal, state, and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our refineries could require material additional expenditures to comply with environmental laws and regulations. For additional information regarding our environmental matters, see Note 24 of Notes to Consolidated Financial Statements.
Tax Matters
We are subject to extensive tax liabilities, including federal, state, and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise, withholding, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. For example, effective January 1, 2007, the Government of Aruba (GOA) enacted a turnover tax on revenues from the sale of goods produced and services rendered in Aruba. The turnover tax, which is 3% for on-island sales and services and 1% on export sales, is being assessed by the GOA on sales by our Aruba Refinery. However, due to a previous tax holiday that was granted to our Aruba Refinery by the GOA through December 31, 2010, we believe that sales by our Aruba Refinery should not be subject to this turnover tax. We have filed a request for arbitration with the Netherlands Arbitration Institute pursuant to which we will seek to enforce our rights under this tax holiday.
Other
During the third quarter of 2005, certain of our refineries experienced property damage and business interruption losses associated with Hurricanes Katrina and Rita. As a result of these losses, we submitted claims to our insurance carriers under our insurance policies. As of December 31, 2006, we have recorded a receivable related to our property damage claims, which was recorded as a reduction of repair and maintenance expense. No amounts related to the potential business interruption insurance recoveries were accrued in our consolidated financial statements as of and for the year ended December 31, 2005 as we had not reached a final settlement with the insurance carriers. During 2006, we reached a final business interruption settlement with our insurance carriers, the proceeds from which were recorded as a reduction to “cost of sales.” Amounts received or to be received for these matters are immaterial to our results of operations and financial position.
On February 1, 2007, we announced our plan to explore strategic alternatives for our Lima Refinery, which we acquired in the Premcor Acquisition.
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Our refining and marketing operations have a concentration of customers in the refining industry and customers who are refined product wholesalers and retailers. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively, in that these customers may be similarly affected by changes in economic or other conditions. However, we believe that our portfolio of accounts receivable is sufficiently diversified to the extent necessary to minimize potential credit risk. Historically, we have not had any significant problems collecting our accounts receivable.
We believe that we have sufficient funds from operations and, to the extent necessary, from the public and private capital markets and bank markets, to fund our ongoing operating requirements. We expect that, to the extent necessary, we can raise additional funds from time to time through equity or debt financings. However, there can be no assurances regarding the availability of any future financings or whether such financings can be made available on terms that are acceptable to us.
OFF-BALANCE SHEET ARRANGEMENTS
Accounts Receivable Sales Facility
As of December 31, 2006, we had an accounts receivable sales facility with a group of third-party financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables, which matures in August 2008. We use this program as a source of working capital funding. Under this program, one of our wholly owned subsidiaries sells an undivided percentage ownership interest in the eligible receivables, without recourse, to the third-party financial institutions. We remain responsible for servicing the transferred receivables and pay certain fees related to our sale of receivables under the program. As of December 31, 2006, the amount of eligible receivables sold to the third-party financial institutions was $1 billion. Note 4 of Notes to Consolidated Financial Statements includes additional discussion of the activity related to this program.
Termination of this program would require us to obtain alternate working capital funding, which would result in an increase in accounts receivable and either increased debt or reduced cash on our consolidated balance sheet. However, as of December 31, 2006, the termination of this program would not have had a material effect on our liquidity and would not have affected our ability to comply with restrictive covenants in our credit facilities. We are not aware of any existing circumstances that are reasonably likely to result in the termination or material reduction in the availability of this program prior to its maturity.
NEW ACCOUNTING PRONOUNCEMENTS
As discussed in Note 1 of Notes to Consolidated Financial Statements, certain new financial accounting pronouncements have been issued which either have already been reflected in the accompanying consolidated financial statements, or will become effective for our financial statements at various dates in the future. The adoption of these pronouncements has not had, nor is expected to have, a material effect on our consolidated financial statements.
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CRITICAL ACCOUNTING POLICIES INVOLVING CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The following summary provides further information about our critical accounting policies that involve critical accounting estimates, and should be read in conjunction with Note 1 of Notes to Consolidated Financial Statements, which summarizes our significant accounting policies. The following accounting policies involve estimates that are considered critical due to the level of sensitivity and judgment involved, as well as the impact on our consolidated financial position and results of operations. We believe that all of our estimates are reasonable.
Impairment of Assets
Long-lived assets (excluding goodwill, intangible assets with indefinite lives, equity method investments, and deferred tax assets) are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. An impairment loss should be recognized only if the carrying amount of the asset is not recoverable and exceeds its fair value. Goodwill and intangible assets that have indefinite useful lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. An impairment loss should be recognized if the carrying amount of the asset exceeds its fair value. We evaluate our equity method investments for impairment when there is evidence that we may not be able to recover the carrying amount of our investments or the investee is unable to sustain an earnings capacity that justifies the carrying amount. A loss in the value of an investment that is other than a temporary decline is recognized currently in earnings, and is based on the difference between the estimated current fair value of the investment and its carrying amount.
In order to test for recoverability, management must make estimates of projected cash flows related to the asset being evaluated which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment. Due to the significant subjectivity of the assumptions used to test for recoverability and to determine fair value, changes in market conditions could result in significant impairment charges in the future, thus affecting our earnings. Our impairment evaluations are based on assumptions that are consistent with our business plans. However, providing sensitivity analysis if other assumptions were used in performing the impairment evaluations is not practicable due to the significant number of assumptions involved in the estimates. We recognized an impairment charge of $57 million in 2004 related to our equity investment in Clear Lake Methanol Partners, L.P. as discussed in Note 10 of Notes to Consolidated Financial Statements.
Environmental Liabilities
Our operations are subject to extensive environmental regulation by federal, state, and local authorities relating primarily to discharge of materials into the environment, waste management, and pollution prevention measures. Future legislative action and regulatory initiatives could result in changes to required operating permits, additional remedial actions, or increased capital expenditures and operating costs that cannot be assessed with certainty at this time.
Accruals for environmental liabilities are based on best estimates of probable undiscounted future costs assuming currently available remediation technology and applying current regulations, as well as our own internal environmental policies. However, environmental liabilities are difficult to assess and estimate due to uncertainties related to the magnitude of possible remediation, the timing of such remediation, and the
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determination of our obligation in proportion to other parties. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts, and potential improvements in remediation technologies. An estimate of the sensitivity to earnings for changes in those factors is not practicable due to the number of contingencies that must be assessed, the number of underlying assumptions, and the wide range of possible outcomes.
The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2006, 2005, and 2004 is included in Note 24 of Notes to Consolidated Financial Statements. We believe that we have adequately accrued for our environmental exposures.
Pension and Other Postretirement Benefit Obligations
We have significant pension and other postretirement benefit liabilities and costs that are developed from actuarial valuations. Inherent in these valuations are key assumptions including discount rates, expected return on plan assets, future compensation increases, and health care cost trend rates. Changes in these assumptions are primarily influenced by factors outside our control. For example, the discount rate assumption is based on a review of long-term bonds that receive one of the two highest ratings given by a recognized rating agency as of the end of each year, while the expected return on plan assets is based on a compounded return calculated for us by an outside consultant using historical market index data with an asset allocation of 65% equities and 35% bonds, which is representative of the asset mix in our qualified pension plans. These assumptions can have a significant effect on the amounts reported in our consolidated financial statements. For example, a 0.25% decrease in the assumptions related to the discount rate or expected return on plan assets or a 0.25% increase in the assumptions related to the health care cost trend rate or rate of compensation increase would have the following effects on the projected benefit obligation as of December 31, 2006 and net periodic benefit cost for the year ending December 31, 2007 (in millions):
Pension
Benefits
Postretirement
Increase in projected benefit obligation resulting from:
Discount rate decrease
Compensation rate increase
Health care cost trend rate increase
Increase in expense resulting from:
Expected return on plan assets decrease
Tax Liabilities
Our operations are subject to extensive tax liabilities, including federal, state, and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise, withholding, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed, and the implementation of future legislative and regulatory tax initiatives could result in increased tax liabilities that cannot be predicted at this time. In addition, we have received claims from various jurisdictions related to certain tax matters. Tax liabilities include potential assessments of penalty and interest amounts.
We record tax liabilities based on our assessment of existing tax laws and regulations. A contingent loss related to a transactional tax claim is recorded if the loss is both probable and estimable. The recording of our tax
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liabilities requires significant judgments and estimates. Actual tax liabilities can vary from our estimates for a variety of reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due. In addition, in determining our income tax provision, we must assess the likelihood that our deferred tax assets, primarily consisting of net operating loss and tax credit carryforwards, will be recovered through future taxable income. Significant judgment is required in estimating the amount of valuation allowance, if any, that should be recorded against those deferred income tax assets. If our actual results of operations differ from such estimates or our estimates of future taxable income change, the valuation allowance may need to be revised. However, an estimate of the sensitivity to earnings that would result from changes in the assumptions and estimates used in determining our tax liabilities is not practicable due to the number of assumptions and tax laws involved, the various potential interpretations of the tax laws, and the wide range of possible outcomes.
Legal Liabilities
A variety of claims have been made against us in various lawsuits. Although we have been successful in defending litigation in the past, we cannot be assured of similar success in future litigation due to the inherent uncertainty of litigation and the individual fact circumstances in each case. We record a liability related to a loss contingency attributable to such legal matters if we determine the loss to be both probable and estimable. The recording of such liabilities requires judgments and estimates, the results of which can vary significantly from actual litigation results due to differing interpretations of relevant law and differing opinions regarding the degree of potential liability and the assessment of reasonable damages. However, an estimate of the sensitivity to earnings if other assumptions were used in recording our legal liabilities is not practicable due to the number of contingencies that must be assessed and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss.
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 refining operations. In order to reduce the risks of these price fluctuations, we use derivative commodity instruments to hedge a portion of our refinery feedstock and refined product inventories and a portion of our unrecognized firm commitments to purchase these inventories (fair value hedges). The carrying amount of our refinery feedstock and refined product inventories was $4.2 billion and $3.8 billion as of December 31, 2006 and 2005, respectively, and the fair value of such inventories was $7.1 billion as of both December 31, 2006 and 2005. From time to time, we use derivative commodity instruments to hedge the price risk of forecasted transactions such as forecasted feedstock and product purchases, refined product sales, and natural gas purchases (cash flow hedges). We also use derivative commodity instruments that do not receive hedge accounting treatment to manage our exposure to price volatility on a portion of our refinery feedstock and refined product inventories and on certain forecasted feedstock and product purchases, refined product sales, and natural gas purchases. These derivative instruments are considered economic hedges for which changes in their fair value are recorded currently in cost of sales. Finally, we enter into derivative commodity instruments based on our fundamental and technical analysis of market conditions that we mark to market for accounting purposes. See “Derivative Instruments” in Note 1 of Notes to Consolidated Financial Statements for a discussion of our accounting for the various types of derivative transactions.
The types of instruments used in our hedging and trading activities described above include swaps, futures, and options. Our positions in derivative commodity instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy which has been approved by our board of directors.
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The following tables provide information about our derivative commodity instruments as of December 31, 2006 and 2005 (dollars in millions, except for the weighted-average pay and receive prices as described below), including:
fair value hedges which are used to hedge our recognized refining inventories and unrecognized firm commitments (i.e., binding agreements to purchase inventories in the future);
cash flow hedges which are used to hedge our forecasted feedstock and product purchases, refined product sales, and natural gas purchases;
economic hedges (hedges not designated as fair value or cash flow hedges) which are used to:
derivative commodity instruments held or issued for trading purposes.
The gain or loss on a derivative instrument designated and qualifying as a fair value hedge and the offsetting loss or gain on the hedged item are recognized currently in income in the same period. The effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is initially reported as a component of “other comprehensive income” and is then recorded in income in the period or periods during which the hedged forecasted transaction affects income. The ineffective portion of the gain or loss on the cash flow derivative instrument, if any, is recognized in income as incurred. For our economic hedges and for derivative instruments entered into by us for trading purposes, the derivative instrument is recorded at fair value and changes in the fair value of the derivative instrument are recognized currently in income.
The following tables include only open positions at the end of the indicated reporting period, and therefore do not include amounts related to closed cash flow hedges for which the gain or loss remains in “accumulated other comprehensive income” pending consummation of the forecasted transactions.
Contract volumes are presented in thousands of barrels (for crude oil and refined products) or in billions of British thermal units (for natural gas). The weighted-average pay and receive prices represent amounts per barrel (for crude oil and refined products) or amounts per million British thermal units (for natural gas). Volumes shown for swaps represent notional volumes, which are used to calculate amounts due under the agreements. For futures, the contract value represents the contract price of either the long or short position multiplied by the derivative contract volume, while the market value amount represents the period-end market price of the commodity being hedged multiplied by the derivative contract volume. The pre-tax fair value for futures, swaps, and options represents the fair value of the derivative contract. The pre-tax fair value for swaps represents the excess of the receive price over the pay price multiplied by the notional contract volumes. For futures and options, the pre-tax fair value represents (i) the excess of the market value amount over the contract amount for long positions, or (ii) the excess of the contract amount over the market value amount for short positions. Additionally, for futures and options, the weighted-average pay price represents the contract price for long positions and the weighted-average receive price represents the contract price for short positions. The weighted-average pay price and weighted-average receive price for options represents their strike price.
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Contract
Volumes
Wtd Avg
Pay
Price
Receive
Value
Market
Pre-tax
Fair
Futures – long:
2007 (crude oil and refined products)
Futures – short:
Swaps – long:
Swaps – short:
2007 (natural gas)
Options – long:
Options – short:
Total pre-tax fair value of open positions
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Fair Value Hedges:
2006 (crude oil and refined products)
Cash Flow Hedges:
Economic Hedges:
2006 (natural gas)
Trading Activities:
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INTEREST RATE RISK
Our primary market risk exposure for changes in interest rates relates to our long-term debt obligations. We manage our exposure to changing interest rates through the use of a combination of fixed and floating rate debt. In addition, we sometimes utilize interest rate swap agreements to manage a portion of our exposure to changing interest rates by converting certain fixed-rate debt to floating rate. These interest rate swap agreements are generally accounted for as fair value hedges. The gain or loss on the derivative instrument and the gain or loss on the debt that is being hedged is recorded in interest expense. The recorded amounts of the derivative instrument and long-term debt balances are adjusted accordingly.
The following table provides information about our long-term debt and interest rate derivative instruments (dollars in millions), all of which are sensitive to changes in interest rates. For long-term debt, principal cash flows and related weighted-average interest rates by expected maturity dates are presented. For interest rate swaps, the table presents notional amounts and weighted-average interest rates by expected (contractual) maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the contract. Weighted-average floating rates are based on implied forward rates in the yield curve at the reporting date.
There-
after
Long-term Debt:
Fixed rate
Average interest rate
Interest Rate Swaps Fixed to Floating:
Notional amount
Average pay rate
Average receive rate
On May 1, 2006, we terminated the $875 million of interest rate swap contracts outstanding at that date for a payment of $54 million. Substantially all of this payment was deferred and is being amortized to interest expense over the remaining lives of the debt instruments that were being hedged.
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FOREIGN CURRENCY RISK
We enter into foreign currency exchange and purchase contracts to manage our exposure to exchange rate fluctuations on transactions related to our Canadian operations. Changes in the fair value of these contracts are recognized currently in income and are intended to offset the income effect of translating the foreign currency denominated transactions that they are intended to hedge.
As of December 31, 2006, we had commitments to purchase $290 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before January 19, 2007, resulting in a 2007 gain of $4 million.
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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate “internal control over financial reporting” (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) for Valero. Our management evaluated the effectiveness of Valero’s internal control over financial reporting as of December 31, 2006. In its evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Management believes that as of December 31, 2006, our internal control over financial reporting was effective based on those criteria.
Our independent registered public accounting firm has issued an attestation report on management’s assessment of our internal control over financial reporting, which begins on page 54 of this report.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
of Valero Energy Corporation and subsidiaries:
We have audited the accompanying consolidated balance sheets of Valero Energy Corporation and subsidiaries (the Company) as of December 31, 2006 and 2005, and the related consolidated statements of income, stockholders’ equity, cash flows and comprehensive income for each of the years in the three-year period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) (the PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Valero Energy Corporation and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, the Company adopted the provisions of Emerging Issues Task Force Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, and Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment, effective January 1, 2006.
We also have audited, in accordance with the standards of the PCAOB, the effectiveness of Valero Energy Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 23, 2007, expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
/s/ KPMG LLP
San Antonio, Texas
February 23, 2007
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We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Valero Energy Corporation and subsidiaries (the Company) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) (the PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that Valero Energy Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by COSO. Also, in our opinion, Valero Energy Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the PCAOB, the consolidated balance sheets of Valero Energy Corporation and subsidiaries as of December 31, 2006 and 2005, and the related consolidated
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statements of income, stockholders’ equity, cash flows and comprehensive income for each of the years in the three-year period ended December 31, 2006, and our report dated February 23, 2007 expressed an unqualified opinion on those consolidated financial statements.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)
ASSETS
Current assets:
Cash and temporary cash investments
Restricted cash
Receivables, net
Inventories
Income taxes receivable
Deferred income taxes
Prepaid expenses and other
Total current assets
Property, plant and equipment, at cost
Accumulated depreciation
Intangible assets, net
Investment in Valero L.P.
Deferred charges and other assets, net
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt and capital lease obligations
Accounts payable
Accrued expenses
Taxes other than income taxes
Income taxes payable
Total current liabilities
Long-term debt, less current portion
Capital lease obligations, less current portion
Commitments and contingencies (Note 23)
Stockholders’ equity:
Preferred stock, $0.01 par value; 20,000,000 shares authorized;0 and 3,164,151 shares issued and outstanding
Common stock, $0.01 par value; 1,200,000,000 shares authorized;627,501,593 and 621,230,266 shares issued
Additional paid-in capital
Treasury stock, at cost; 23,738,162 and 3,807,976 common shares
Retained earnings
Accumulated other comprehensive income
Total stockholders’ equity
Total liabilities and stockholders’ equity
See Notes to Consolidated Financial Statements.
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CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, Except per Share Amounts and Supplemental Information)
Operating revenues (1) (2)
Cost of sales (1)
Earnings per common share
Weighted-average common shares outstanding (in millions)
Weighted-average common equivalent shares outstanding (in millions)
Supplemental information (billions of dollars):
(1) Includes amounts related to crude oil buy/sell arrangements:
Operating revenues
Cost of sales
(2) Includes excise taxes on sales by our U.S. retail system
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CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Millions of Dollars)
Preferred
Stock
Common
Additional
Paid-in
Capital
Treasury
Retained
Earnings
Accumulated
Comprehensive
Income (Loss)
Dividends on common stock
Dividends on and accretion of preferred stock
Sale of common stock
Stock-based compensation expense
Shares repurchased, net of shares issued, in connection with employee stock plans and other
Other comprehensive income
Balance as of December 31, 2004
Conversion of preferred stock
Issuance of common stock in connection with the Premcor Acquisition
Fair value of replacement stock options issued in connection with the Premcor Acquisition
Shares issued, net of shares repurchased, in connection with employee stock plans and other
Balance as of December 31, 2005
Credits from subsidiary stock sales, net of tax
Adjustment to initially apply FASB Statement No. 158, net of tax
Balance as of December 31, 2006
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CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flows from operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of Valero GP Holdings, LLC
Gain on sale of investment in Javelina joint venture
Impairment of investment in Clear Lake Methanol Partners, L.P.
Noncash interest expense and other income, net
Deferred income tax expense
Changes in current assets and current liabilities
Changes in deferred charges and credits and other, net
Net cash provided by operating activities
Cash flows from investing activities:
Capital expenditures
Deferred turnaround and catalyst costs
Premcor Acquisition, net of cash acquired
Proceeds from sale of Valero GP Holdings, LLC
Aruba Acquisition, net of cash acquired
Proceeds from sale of the Denver Refinery
Proceeds from sale of investment in Javelina joint venture
General partner contribution to Valero L.P.
Contingent payments in connection with acquisitions
(Investment) return of investment in Cameron Highway Oil Pipeline Project, net
Distributions in excess of equity in earnings of Valero L.P.
Proceeds from dispositions of property, plant and equipment
Buyout of assets under structured lease arrangements
Minor acquisitions and other investing activities, net
Net cash used in investing activities
Cash flows from financing activities:
Long-term notes:
Borrowings
Repayments
Bank credit agreements:
Termination of interest rate swaps
Purchase of treasury stock
Proceeds from the sale of common stock, net of issuance costs
Issuance of common stock in connection with employee benefit plans
Benefit from tax deduction in excess of recognized stock-based compensation cost
Common and preferred stock dividends
Cash distributions to minority interest in Valero GP Holdings, LLC
Net cash provided by (used in) financing activities
Effect of foreign exchange rate changes on cash
Net increase (decrease) in cash and temporary cash investments
Cash and temporary cash investments at beginning of year
Cash and temporary cash investments at end of year
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Other comprehensive income (loss):
Foreign currency translation adjustment
Pension liability adjustment
Net gain (loss) on derivative instruments designated and qualifying as cash flow hedges:
Net gain (loss) arising during the year, net of income tax (expense) benefit of $(38), $117, and $90
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $15, $(146), and $(62)
Net gain (loss) on cash flow hedges
Comprehensive income
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation
As used in this report, the terms “Valero,” “we,” “us,” or “our” may refer to Valero Energy Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole. We are an independent refining and marketing company and own and operate 18 refineries (seven in Texas, two each in California and Louisiana, and one each in Delaware, Ohio, Oklahoma, New Jersey, Tennessee, Aruba, and Quebec, Canada) with a combined total throughput capacity as of December 31, 2006 of approximately 3.3 million barrels per day. We market our refined products through an extensive bulk and rack marketing network and approximately 5,800 retail and wholesale branded outlets in the United States and eastern Canada under various brand names including primarily Valero®, Diamond Shamrock®, Shamrock®, Ultramar®, and Beacon®. Our operations are affected by:
company-specific factors, primarily refinery utilization rates and refinery maintenance turnarounds;
seasonal factors, such as the demand for refined products during the summer driving season and heating oil during the winter season; and
industry factors, such as movements in and the level of crude oil prices including the effect of quality differential between grades of crude oil, the demand for and prices of refined products, industry supply capacity, and competitor refinery maintenance turnarounds.
These consolidated financial statements include the accounts of Valero and subsidiaries in which Valero has a controlling interest. Intercompany balances and transactions have been eliminated in consolidation. Investments in non-controlled entities are accounted for using the equity method of accounting.
On July 19, 2006, Valero sold a 40.6% interest in Valero GP Holdings, LLC, which, through certain of its subsidiaries, owns the general partner interest, incentive distribution rights, and a 21.4% limited partner interest in Valero L.P. On December 22, 2006, Valero sold its remaining interest in Valero GP Holdings, LLC. These financial statements consolidate Valero GP Holdings, LLC through December 21, 2006, with net income attributable to the 40.6% interest held by public unitholders from July 19, 2006 through December 21, 2006 presented as a minority interest in the consolidated statement of income. See Note 9 under “Valero GP Holdings, LLC” for a discussion of the sale of Valero GP Holdings, LLC.
The term UDS Acquisition refers to the merger of Ultramar Diamond Shamrock Corporation (UDS) into Valero effective December 31, 2001.
Use of Estimates
The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires our management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, management reviews its estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cash and Temporary Cash Investments
Our temporary cash investments are highly liquid, low-risk debt instruments which have a maturity of three months or less when acquired. Cash and temporary cash investments exclude cash that is not available to us due to restrictions related to its use. Such amounts are segregated in the consolidated balance sheets in “restricted cash” (see Note 3).
Inventories are carried at the lower of cost or market. The cost of refinery feedstocks purchased for processing and refined products are determined under the last-in, first-out (LIFO) method using the dollar-value LIFO method, with any increments valued based on average purchase prices during the year. The cost of feedstocks and products purchased for resale and the cost of materials, supplies, and convenience store merchandise are determined principally under the weighted-average cost method.
Effective January 1, 2006, we adopted the provisions of Statement No. 151, “Inventory Costs,” which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material and requires that those items be recognized as current-period charges. Statement No. 151 also requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. We adopted Statement No. 151 on January 1, 2006 with no effect on our financial position or results of operations.
Property, Plant and Equipment
Additions to property, plant and equipment, including capitalized interest and certain costs allocable to construction and property purchases, are recorded at cost.
The costs of minor property units (or components of property units), net of salvage value, retired or abandoned are charged or credited to accumulated depreciation under the composite method of depreciation. Gains or losses on sales or other dispositions of major units of property are recorded in income and are reported in “depreciation and amortization expense” in the consolidated statements of income.
Depreciation of property, plant and equipment is recorded on a straight-line basis over the estimated useful lives of the related facilities primarily using the composite method of depreciation. Leasehold improvements and assets acquired under capital leases are amortized using the straight-line method over the shorter of the lease term or the estimated useful life of the related asset.
Goodwill and Intangible Assets
Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over 1 to 40 years. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. We use October 1 of each year as our valuation date for annual impairment testing purposes.
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Deferred Charges and Other Assets
“Deferred charges and other assets, net” include the following:
refinery turnaround costs, which are incurred in connection with planned major maintenance activities at our refineries and which are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs;
fixed-bed catalyst costs, representing the cost of catalyst that is changed out at periodic intervals when the quality of the catalyst has deteriorated beyond its prescribed function, which are deferred when incurred and amortized on a straight-line basis over the estimated useful life of the specific catalyst;
investments in certain entities we do not control, which are accounted for using the equity method of accounting; and
other noncurrent assets such as long-term investments, convenience store dealer incentive programs, pension plan assets, debt issuance costs, and various other costs.
We evaluate our equity method investments for impairment when there is evidence that we may not be able to recover the carrying amount of our investments or the investee is unable to sustain an earnings capacity that justifies the carrying amount. A loss in the value of an investment that is other than a temporary decline is recognized currently in earnings, and is based on the difference between the estimated current fair value of the investment and its carrying amount. We believe that the carrying amounts of our equity method investments as of December 31, 2006 are recoverable.
Effective January 1, 2006, we adopted Emerging Issues Task Force (EITF) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (EITF No. 04-5), which requires the general partner in a limited partnership to determine whether the limited partnership is controlled by, and therefore should be consolidated by, the general partner. The adoption of EITF No. 04-5 had no impact on the accounting for our investment in Valero L.P.
Impairment and Disposal of Long-Lived Assets
Long-lived assets (excluding goodwill, intangible assets with indefinite lives, equity method investments, and deferred tax assets) are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its fair value, with fair value determined based on discounted estimated net cash flows. We believe that the carrying amounts of our long-lived assets as of December 31, 2006 are recoverable.
Taxes Other than Income Taxes
“Taxes other than income taxes” includes primarily liabilities for ad valorem, excise, sales and use, and payroll taxes.
Income Taxes
Income taxes are accounted for under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred amounts are measured using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled.
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In December 2004, the Financial Accounting Standards Board (FASB) issued Staff Position No. FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Repatriation Provision within the American Jobs Creation Act of 2004,” which allowed an enterprise time beyond the end of the financial reporting period covering the date of enactment to evaluate the effect of the American Jobs Creation Act of 2004 (the 2004 Act) on its plan for reinvestment or repatriation of foreign earnings for purposes of applying Statement No. 109. As we have not repatriated and currently have no plans to repatriate funds under the provisions of the 2004 Act, there has been no impact on our consolidated financial statements as a result of adoption of Staff Position No. FAS 109-2.
See “New Accounting Pronouncements” below for a discussion of FASB Interpretation No. 48, which, beginning in 2007, prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in tax returns.
Asset Retirement Obligations
We record a liability, which is referred to as an asset retirement obligation, at fair value for the estimated cost to retire a tangible long-lived asset at the time we incur that liability, which is generally when the asset is purchased, constructed, or leased. We record the liability when we have a legal obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the liability’s fair value.
We have asset retirement obligations with respect to certain of our refinery assets due to various legal obligations to clean and/or dispose of various component parts of each refinery at the time they are retired. However, these component parts can be used for extended and indeterminate periods of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain our refinery assets and continue making improvements to those assets based on technological advances. As a result, we believe that our refineries have indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we would retire refinery assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of any component part of a refinery, we estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using established present value techniques.
We also have asset retirement obligations for the removal of underground storage tanks (USTs) for refined products at owned and leased retail locations. There is no legal obligation to remove USTs while they remain in service. However, environmental laws require that unused USTs be removed within certain periods of time after the USTs no longer remain in service, usually one to two years depending on the jurisdiction in which the USTs are located. We have estimated that USTs at our owned retail locations will not remain in service after 25 years of use and that we will have an obligation to remove those USTs at that time. For our leased retail locations, our lease agreements generally require that we remove certain improvements, primarily USTs and signage, upon termination of the lease. While our lease agreements typically contain options for multiple renewal periods, we have not assumed that such leases will be renewed for purposes of estimating our obligation to remove USTs and signage.
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Effective December 31, 2005, we adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations,” represents a legal obligation to perform an asset retirement activity for which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset retirement obligation should be recognized if its fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of its settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under FASB Statement No. 143. The adoption of FIN 47 did not affect our financial position or results of operations.
Foreign Currency Translation
The functional currencies of our Canadian and Aruban operations are the Canadian dollar and the Aruban florin, respectively. The translation into U.S. dollars is computed for balance sheet accounts using exchange rates in effect as of the balance sheet date and for revenue and expense accounts using the weighted-average exchange rates during the year. Adjustments resulting from this translation are reported in “accumulated other comprehensive income.”
Revenue Recognition
Revenues for products sold by both the refining and retail segments are recorded upon delivery of the products to our customers, which is the point at which title to the products is transferred, and when payment has either been received or collection is reasonably assured. Revenues for services are recorded when the services have been provided. We present excise taxes on sales by our U.S. retail system on a gross basis with supplemental information regarding the amount of such taxes included in revenues provided in a footnote on the face of the income statement. All other excise taxes are presented on a net basis in the income statement.
Through December 31, 2005, our operating revenues included sales related to certain buy/sell arrangements. In September 2005, the FASB ratified its consensus on EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF No. 04-13), which requires that inventory purchase and sales transactions with the same counterparty that are entered into in contemplation of one another should be combined. The guidance in EITF No. 04-13 was effective for transactions completed in reporting periods beginning after March 15, 2006, with early application permitted. We adopted EITF No. 04-13 on January 1, 2006.
One issue addressed by EITF No. 04-13 details factors to consider in evaluating whether certain individual transactions to purchase and sell inventory are made in contemplation of one another and should therefore be viewed as one transaction when applying the principles of AICPA Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions.” When applying these factors, certain of our buy/sell arrangements are deemed to be made in contemplation of one another. Accordingly, commencing January 1, 2006, revenues and cost of sales ceased to be recognized in connection with these arrangements. This adoption resulted in a reduction in our operating revenues in our consolidated statement of income and a corresponding reduction in cost of sales with no material impact on operating income, net income or net income applicable to common stock. If we had applied EITF No. 04-13 for the years ended December 31, 2005 and 2004, operating revenues and cost of sales would have been reduced by the amounts reflected in the supplemental information on the face of the consolidated statements of income.
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We also enter into refined product exchange transactions to fulfill sales contracts with our customers by accessing refined products in markets where we do not operate our own refinery. These refined product exchanges are accounted for as exchanges of non-monetary assets, and no revenues are recorded on these transactions.
Product Shipping and Handling Costs
Costs incurred for shipping and handling of products are included in “cost of sales” in the consolidated statements of income.
Liabilities for future remediation costs are recorded when environmental assessments and/or remedial efforts are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Environmental liabilities are based on best estimates of probable undiscounted future costs over a 20-year time period using currently available technology and applying current regulations, as well as our own internal environmental policies. Amounts recorded for environmental liabilities have not been reduced by possible recoveries from third parties.
Derivative Instruments
All derivative instruments are recorded in the balance sheet as either assets or liabilities measured at their fair value. When we enter into a derivative instrument, it is designated as a fair value hedge, a cash flow hedge, an economic hedge, or a trading instrument. For our economic hedging relationships (hedges not designated as fair value or cash flow hedges) and for derivative instruments entered into by us for trading purposes, the derivative instrument is recorded at fair value and changes in the fair value of the derivative instrument are recognized currently in income. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting loss or gain on the hedged item attributable to the hedged risk, are recognized currently in income in the same period. The effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is initially reported as a component of “other comprehensive income” and is then recorded in income in the period or periods during which the hedged forecasted transaction affects income. The ineffective portion of the gain or loss on the cash flow derivative instrument, if any, is recognized in income as incurred. Income effects of commodity derivative instruments are recorded in “cost of sales” while income effects of interest rate swaps are recorded in “interest and debt expense.”
Financial Instruments
Our financial instruments include cash and temporary cash investments, restricted cash, receivables, payables, debt, capital lease obligations, interest rate swaps, commodity derivative contracts, and foreign currency derivative contracts. The estimated fair values of these financial instruments approximate their carrying amounts as reflected in the consolidated balance sheets, except for certain long-term debt as discussed in Note 12. The fair value of our debt, interest rate swaps, commodity derivative contracts, and foreign currency derivative contracts was estimated primarily based on year-end quoted market prices.
Earnings per Common Share
Earnings per common share is computed by dividing net income applicable to common stock by the weighted-average number of common shares outstanding for the year. Earnings per common share – assuming dilution reflects the potential dilution of our outstanding stock options and nonvested shares granted to employees in
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connection with our stock compensation plans, as well as the 2% mandatory convertible preferred stock prior to its conversion as discussed in Note 14.
Comprehensive Income
Comprehensive income consists of net income and other gains and losses affecting stockholders’ equity that, under GAAP, are excluded from net income, including foreign currency translation adjustments, gains and losses related to certain derivative contracts, and gains or losses, prior service costs or credits, and transition assets or obligations associated with pension or other postretirement benefits that have not been recognized as components of net periodic benefit cost.
Defined Benefit Pension and Other Postretirement Plans
In September 2006, the FASB issued Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which amends Statement No. 87, “Employers’ Accounting for Pensions,” Statement No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” Statement No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” and other related accounting literature.
Statement No. 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or a liability in the statement of financial position and to recognize changes in that funded status through comprehensive income in the year the changes occur. This statement also requires an employer to measure the funded status of a plan as of the date of the employer’s year-end statement of financial position. We adopted the funded status recognition and related disclosure requirements of Statement No. 158 as of December 31, 2006, and measured the funded status of our defined benefit plans as of that date. The adoption of Statement No. 158 has not materially affected our financial position or results of operations.
The effect of applying Statement No. 158 on individual lines in the consolidated balance sheet as of December 31, 2006 was as follows (in millions):
Before
Application of
Statement No. 158
After
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The pre-tax effects on accumulated other comprehensive income (loss) attributable to our pension plans and other postretirement benefit plans (OPEB) for the year ended December 31, 2006 were as follows (in millions):
Plans
Benefit Plans
Balance as of January 1, 2006
Adjustment before adopting Statement No. 158
Statement No. 158 effect
Stock-Based Compensation
Through December 31, 2005, we accounted for our employee stock compensation plans using the intrinsic value method of accounting set forth in APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as permitted by FASB Statement No. 123, “Accounting for Stock-Based Compensation.”
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Because we accounted for our employee stock compensation plans using the intrinsic value method, compensation cost was not recognized in the consolidated statements of income for our fixed stock option plans as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. Had compensation cost for our fixed stock option plans been determined based on the grant-date fair value of awards consistent with the alternative method set forth in Statement No. 123, our net income applicable to common stock, net income, and earnings per common share, both with and without dilution, for the years ended December 31, 2005 and 2004 would have been reduced to the pro forma amounts indicated in the following table (in millions, except per share amounts):
Year Ended
December 31,
Net income applicable to common stock, as reported
Deduct: Compensation expense on stock options determined under fair value method for all awards, net of related tax effects
Pro forma net income applicable to common stock
Earnings per common share:
As reported
Pro forma
Net income, as reported
Pro forma net income
Earnings per common share – assuming dilution:
Stock-based compensation expense recognized for the years ended December 31, 2005 and 2004 was $52 million and $23 million, respectively, net of tax benefits of $28 million and $12 million, respectively.
Effective January 1, 2006, we adopted Statement No. 123 (revised 2004), “Share-Based Payment” (Statement No. 123R), which requires the expensing of the fair value of stock options. The specific impact of our adoption of Statement No. 123R will depend on levels of share-based incentive awards granted in the future. Had we adopted Statement No. 123R in prior periods, the impact of that standard would have approximated the impact of Statement No. 123 as described in the disclosure of the pro forma financial information above.
We adopted the fair value recognition provisions of Statement No. 123R using the modified prospective application. Accordingly, we are recognizing compensation expense for all newly granted stock options and
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stock options modified, repurchased, or cancelled on or after January 1, 2006. In addition, compensation cost for the unvested portion of stock options and other awards that were outstanding as of January 1, 2006 is being recognized over the remaining vesting period based on the fair value at date of grant and the attribution approach utilized in determining the pro forma information reflected above. Subsequent to the adoption of Statement No. 123R, our total stock-based compensation expense recognized for the year ended December 31, 2006 was $70 million, net of tax benefits of $38 million.
Under our employee stock compensation plans, certain awards of stock options and restricted stock provide that employees vest in the award when they retire or will continue to vest in the award after retirement over the nominal vesting period established in the award. We previously accounted for such awards by recognizing compensation cost, if any, under APB Opinion No. 25 and pro forma compensation cost under Statement No. 123 over the nominal vesting period. Upon the adoption of Statement No. 123R, compensation expense for stock options granted on or after January 1, 2006 is being recognized on a straight-line basis, and we changed our method of recognizing compensation cost for new grants that have retirement-eligibility provisions from the nominal vesting approach to the non-substantive vesting period approach. Under the non-substantive vesting period approach, compensation cost is recognized immediately for awards granted to retirement-eligible employees or over the period from the grant date to the date retirement eligibility is achieved if that date is expected to occur during the nominal vesting period. If the non-substantive vesting period approach had been used by us for awards granted prior to January 1, 2006, pro forma net income applicable to common stock and pro forma net income amounts for the years ended December 31, 2005 and 2004 would have decreased by $8 million and $1 million, respectively, and net income applicable to common stock and net income for the year ended December 31, 2006 would have increased by $4 million.
Statement No. 123R also requires the benefits of tax deductions in excess of recognized stock-based compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as previously required. This requirement reduces cash flows from operating activities and increases cash flows from financing activities beginning in 2006. While we cannot estimate the specific magnitude of this change on future cash flows because it depends on, among other things, when employees exercise stock options, the cash flows recognized in financing activities for such excess tax deductions were $206 million for the year ended December 31, 2006.
Sales of Subsidiary Stock
Securities and Exchange Commission (SEC) Staff Accounting Bulletin No. 51, “Accounting for Sales of Stock by a Subsidiary” (SAB 51), provides guidance on accounting for the effect of issuances of a subsidiary’s stock on the parent’s investment in that subsidiary. SAB 51 allows registrants to elect an accounting policy of recording such increases or decreases in a parent’s investment (SAB 51 credits or charges, respectively) either in income or in stockholders’ equity. In accordance with the election provided in SAB 51, we adopted a policy of recording such SAB 51 credits or charges directly to “additional paid-in capital” in stockholders’ equity. As further discussed in Note 9, we recognized in 2006 certain SAB 51 credits related to our investment in Valero L.P. under our adopted policy.
Exchanges of Nonmonetary Assets
In December 2004, the FASB issued Statement No. 153, “Exchanges of Nonmonetary Assets,” which addresses the measurement of exchanges of nonmonetary assets. Statement No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets, which was previously
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provided by APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. Statement No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement No. 153 was effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The adoption of Statement No. 153 did not affect our financial position or results of operations.
New Accounting Pronouncements
FASB Statement No. 155
In February 2006, the FASB issued Statement No. 155, “Accounting for Certain Hybrid Financial Instruments,” which amends Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This statement improves the financial reporting of certain hybrid financial instruments and simplifies the accounting for these instruments. In particular, Statement No. 155 (i) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, (ii) clarifies which interest-only and principal-only strips are not subject to the requirements of Statement No. 133, (iii) establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, (iv) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives, and (v) amends Statement No. 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. The adoption of Statement No. 155 effective January 1, 2007 has not affected our financial position or results of operations.
FASB Statement No. 156
In March 2006, the FASB issued Statement No. 156, “Accounting for Servicing of Financial Assets,” which amends Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” Statement No. 156 requires the initial recognition at fair value of a servicing asset or servicing liability when an obligation to service a financial asset is undertaken by entering into a servicing contract. The adoption of Statement No. 156 effective January 1, 2007 has not affected our financial position or results of operations.
FASB Interpretation No. 48
In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes,” by prescribing 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. If a tax position is more likely than not to be sustained upon examination, then an enterprise would be required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The adoption of FIN 48 effective January 1, 2007 is not expected to materially affect our financial position or results of operations.
EITF Issue No. 06-3
In June 2006, the FASB ratified its consensus on EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross
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versus Net Presentation)” (EITF No. 06-3). The scope of EITF No. 06-3 includes any tax assessed by a governmental authority that is imposed concurrent with or subsequent to a revenue-producing transaction between a seller and a customer. For taxes within the scope of this issue that are significant in amount, the consensus requires the following disclosures: (i) the accounting policy elected for these taxes and (ii) the amount of the taxes reflected gross in the income statement on an interim and annual basis for all periods presented. The disclosure of those taxes can be done on an aggregate basis. The consensus is effective for interim and annual periods beginning after December 15, 2006. As discussed above under “Revenue Recognition,” we currently present excise taxes on sales by our U.S. retail system on a gross basis with supplemental information regarding the amount of such taxes included in revenues provided in a footnote on the face of the income statement. All other excise taxes are presented on a net basis in the income statement. We plan to continue to present our excise taxes in this manner subsequent to the adoption of EITF No. 06-3.
FASB Statement No. 157
In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements.” Statement No. 157 defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measures. Statement No. 157 is effective for fiscal years beginning after November 15, 2007, with early adoption encouraged. The provisions of Statement No. 157 are to be applied on a prospective basis, with the exception of certain financial instruments for which retrospective application is required. The adoption of Statement No. 157 is not expected to materially affect our financial position or results of operations.
FASB Statement No. 159
In February 2007, the FASB issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” Statement No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Statement No. 159 is effective for fiscal years beginning after November 15, 2007, with early adoption permitted provided the entity also elects to apply the provisions of Statement No. 157. We are currently evaluating the impact, if any, of Statement No. 159 on our financial position and results of operations.
Reclassifications
Certain previously reported amounts have been reclassified to conform to the 2006 presentation, including reflecting in our consolidated statements of cash flows for 2005 and 2004 gross borrowings and repayments under our committed and uncommitted bank credit facilities and presenting those amounts separate from borrowings and repayments related to our long-term notes. The reclassifications also included amounts previously reported in our consolidated statements of income in 2005 and 2004 for refining operating expenses, retail selling expenses, general and administrative expenses, and depreciation and amortization expense which were reclassified due to the following changes that took effect on January 1, 2006: (i) information services costs that were previously allocated to the operating units are now being reported as general and administrative expenses to better reflect the area responsible for such costs and (ii) Statement No. 123R (discussed above) was implemented, which resulted in amounts previously reported as amortization expense now being reported as operating, selling, or general and administrative expenses. These reclassified income statement amounts were as follows (in millions):
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Previously
Reported
Currently
2. ACQUISITIONS AND DISPOSITIONS
Premcor Acquisition
On September 1, 2005, we completed our merger with Premcor Inc. (Premcor). As used in this report, Premcor Acquisition refers to the merger of Premcor with and into Valero. Premcor was an independent petroleum refiner and supplier of unbranded transportation fuels, heating oil, petrochemical feedstocks, petroleum coke, and other petroleum products with all of its operations in the United States. Premcor owned and operated refineries in Port Arthur, Texas; Lima, Ohio; Memphis, Tennessee; and Delaware City, Delaware with a combined crude oil throughput capacity of approximately 800,000 barrels per day.
Under the terms of the merger agreement, each outstanding share of Premcor common stock was converted into the right to receive cash or our common stock at the shareholder’s election, subject to proration per the terms of the merger agreement, so that 50% of the total Premcor shares (based on the number of Premcor shares outstanding at completion of the merger on a diluted basis under the treasury stock method) was acquired for cash, with the balance acquired for our common stock. Based on the election results, Premcor’s shareholders electing Valero common stock received 0.48233 of a share of our common stock and $37.31 in cash for each share of Premcor common stock. Premcor shareholders electing cash and non-electing shareholders received $72.76 in cash for each share of Premcor common stock. As a result, we issued 85 million shares of our common stock and paid $3.4 billion of cash to Premcor shareholders.
For accounting purposes, the stock portion of the purchase price was valued using a price of $37.41 per share, representing our average common stock price from two days before to two days after the announcement of the Premcor Acquisition on April 25, 2005. We incurred $27 million of transaction costs to consummate the Premcor Acquisition. In addition, we issued 14 million stock options in exchange for the 7 million Premcor stock options outstanding as of September 1, 2005. The stock options issued by us had a fair value of $595 million on the date of the merger, which was estimated using the Black-Scholes option-pricing model with the following assumptions: (i) a risk-free interest rate of 3.8%, (ii) expected volatility of 41.4%, (iii) expected dividend yield of 0.4%, and (iv) an average expected life of six months.
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We paid the cash portion of the merger consideration from available cash and proceeds from a $1.5 billion five-year bank term loan due in August 2010 (see Note 12 for additional details related to the $1.5 billion term loan). In addition, we assumed Premcor’s existing debt, which had a fair value of $1.9 billion as of September 1, 2005.
During 2006, an independent appraisal of the assets acquired in the Premcor Acquisition and certain other evaluations related to the Premcor Acquisition purchase price allocation were completed. The purchase price of the Premcor Acquisition was allocated based on the fair values of the assets acquired and the liabilities assumed at the date of acquisition resulting from this final appraisal and other evaluations. The primary adjustments to the preliminary purchase price allocation reflected in our Annual Report on Form 10-K for the year ended December 31, 2005 included an $898 million increase in property, plant and equipment, a $646 million decrease in goodwill, and a $349 million increase in deferred income taxes resulting from the final appraisal and other evaluations. The purchase price and the final purchase price allocation were as follows (in millions):
Cash paid
Transaction costs
Less unrestricted cash acquired
Common stock and stock options issued
Total purchase price, excluding unrestricted cash acquired
Current assets, net of unrestricted cash acquired
Property, plant and equipment
Intangible assets
Deferred charges and other assets
Current liabilities, less current portion of long-term debt and capital lease obligations
Long-term debt assumed, including current portion
Capital lease obligation, including current portion
Purchase price, excluding unrestricted cash acquired
Aruba Acquisition
On March 5, 2004, we completed the purchase of El Paso Corporation’s refinery located on the island of Aruba in the Caribbean Sea (Aruba Refinery), and related marine, bunkering, and marketing operations (collectively, Aruba Acquisition). The purchase price for the Aruba Acquisition was $465 million plus $168 million for working capital. The working capital amount excludes amounts related to certain refined product inventories owned by a third-party marketing firm under an agreement in existence on the date of acquisition, pursuant to which we paid $68 million upon termination of the agreement on May 4, 2004. The Aruba Acquisition was funded with $200 million in existing cash, $27 million in borrowings under our bank credit facilities, and $406 million in net proceeds from the sale of 31 million shares of our common stock through a public offering discussed in Note 14 under “Common Stock Offerings.” The amount paid to the
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third-party marketing firm described above was funded through borrowings under our bank credit facilities. The profits from the Aruba Refinery’s operations are non-taxable in Aruba through December 31, 2010.
During 2005, an independent appraisal was completed and the resulting final purchase price allocation for the Aruba Acquisition is summarized below (in millions):
Current assets
Current liabilities
Capital lease obligation
Total purchase price
Less cash acquired
Purchase price, excluding cash acquired
Unaudited Pro Forma Financial Information
The consolidated statements of income include the results of operations of the Aruba Acquisition and the Premcor Acquisition commencing on March 5, 2004 and September 1, 2005, respectively. As a result, information for the year ended December 31, 2006 presented below represents actual results of operations.
The unaudited pro forma financial information included in the table below assumes that the Premcor Acquisition occurred on January 1, 2005 and 2004 and the Aruba Acquisition occurred on January 1, 2004 for the applicable years presented. This pro forma information assumes:
85 million shares of common stock were issued, $1.5 billion of debt was incurred, and $1.9 billion of available cash was utilized to fund the Premcor Acquisition on January 1, 2005 and 2004; and
31 million shares of common stock were sold and $36 million of debt was incurred in connection with the Aruba Acquisition on January 1, 2004.
The unaudited pro forma financial information is not necessarily indicative of the results of future operations (in millions, except per share amounts):
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Sale of Denver Refinery
On May 31, 2005, we sold our Denver Refinery and related assets and liabilities to Suncor Energy (U.S.A.) Inc. for $30 million plus $15 million for working capital, including feedstock and refined product inventories. In connection with this sale, we recognized a pre-tax gain of $3 million, net of a reduction of $4 million for associated goodwill.
Sale of Equity Interest in Javelina Joint Venture
On November 1, 2005, we sold our 20% equity interests in Javelina Company and Javelina Pipeline Company to MarkWest Energy Partners, L.P. for $78 million, recognizing a gain of $55 million. Javelina Company processes refinery off-gas at a plant in Corpus Christi, Texas.
3. RESTRICTED CASH
Restricted cash as of December 31, 2006 and 2005 included $22 million of cash held in trust related to change-in-control payments to be made to former officers and key employees of UDS in connection with the UDS Acquisition that occurred in December 2001. Restricted cash as of December 31, 2006 and 2005 also included $8 million of cash assumed in the Premcor Acquisition, which was held in trust mainly to satisfy claims under Premcor’s directors’ and officers’ liability policy.
4. RECEIVABLES
Receivables consisted of the following (in millions):
Accounts receivable
Notes receivable and other
Allowance for doubtful accounts
The changes in the allowance for doubtful accounts consisted of the following (in millions):
Balance as of beginning of year
Increase in allowance charged to expense
Accounts charged against the allowance,
net of recoveries
Foreign currency translation
Balance as of end of year
We have an accounts receivable sales facility with a group of third-party financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables, which matures in August 2008. Under this program, one of our wholly owned subsidiaries sells an undivided percentage ownership interest in the eligible receivables, without recourse, to third-party financial institutions. We remain responsible for servicing the
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transferred receivables and pay certain fees related to our sale of receivables under the program. Under the facility, we retain the residual interest in the designated pool of receivables. This retained interest, which is included in “receivables, net” in the consolidated balance sheets, is recorded at fair value. Due to (i) a short average collection cycle for such receivables, (ii) our collection experience history, and (iii) the composition of the designated pool of trade accounts receivable that are part of this program, the fair value of our retained interest approximates the total amount of the designated pool of accounts receivable reduced by the amount of accounts receivable sold to the third-party financial institutions under the program.
The costs we incurred related to this facility, which were included in “other income (expense), net” in the consolidated statements of income, were $55 million, $30 million, and $12 million for the years ended December 31, 2006, 2005, and 2004, respectively. Proceeds from collections under this facility of $31.2 billion, $24.1 billion, and $17.6 billion for the years ended December 31, 2006, 2005, and 2004, respectively, were reinvested in the program by the third-party financial institutions. However, the third-party financial institutions’ interests in our accounts receivable were never in excess of the sales facility limits at any time under this program. No accounts receivable included in this program were written off during 2006, 2005, or 2004.
As of both December 31, 2006 and 2005, $2.6 billion of our accounts receivable composed the designated pool of accounts receivable included in the program. Of these amounts, we sold $1 billion to the third-party financial institutions and retained the remaining amount.
5. INVENTORIES
Inventories consisted of the following (in millions):
Refinery feedstocks
Refined products and blendstocks
Convenience store merchandise
Materials and supplies
Refinery feedstock and refined product and blendstock inventory volumes totaled 114 million barrels and 108 million barrels as of December 31, 2006 and 2005, respectively. There were no significant liquidations of LIFO inventory layers for the years ended December 31, 2006, 2005, and 2004.
As of December 31, 2006 and 2005, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $2.9 billion and $3.3 billion, respectively.
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6. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment, which include capital lease assets, consisted of the following (in millions):
Land
Crude oil processing facilities
Butane processing facilities
Pipeline and terminal facilities
Retail facilities
Buildings
Construction in progress
As of December 31, 2006 and 2005, we had crude oil processing facilities, pipeline and terminal facilities, and certain buildings and other equipment under capital leases totaling $92 million and $45 million, respectively. Accumulated amortization on assets under capital leases was $7 million and $3 million, respectively, as of December 31, 2006 and 2005.
Depreciation expense for the years ended December 31, 2006, 2005, and 2004 was $812 million, $594 million, and $418 million, respectively. For the year ended December 31, 2006, depreciation expense was reduced by a $12 million gain on the sale of storage facilities at Mont Belvieu for total proceeds of $22 million, and depreciation expense was increased by $8 million of net losses on the disposition of certain retail stores. For the year ended December 31, 2005, depreciation expense includes losses and write-offs of $25 million related to our retail store operations, primarily attributable to the conversion of retail and wholesale sites from the Diamond Shamrock brand to the Valero brand. During 2004, net gains of $13 million were recorded as a reduction of depreciation expense on the disposition of various facilities, including a $15 million gain on the sale in December 2004 of a pipeline grid system at Mont Belvieu and the tankage and idle MTBE plant at Morgan’s Point for total proceeds of $27 million.
See Note 23 under “Structured Lease Arrangements” for a discussion of our purchases during 2004 of certain property, plant and equipment which had been leased under structured lease arrangements.
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7. INTANGIBLE ASSETS
Intangible assets consisted of the following (in millions):
Gross
Cost
Amortization
Intangible assets subject to amortization:
Customer lists
Canadian retail operations
U.S. retail store operations
Air emission credits
Royalties and licenses
Gasoline and diesel sulfur credits
Intangible assets subject to amortization
All of our intangible assets are subject to amortization. Amortization expense for intangible assets was $35 million, $29 million, and $26 million for the years ended December 31, 2006, 2005, and 2004, respectively. The estimated aggregate amortization expense for the years ending December 31, 2007 through December 31, 2011 is as follows (in millions):
Expense
2007
2008
2009
2010
2011
During the year ended December 31, 2006, certain intangible assets were retired which resulted in a reduction of $23 million in both gross cost and accumulated amortization.
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8. GOODWILL
The changes in the carrying amount of goodwill were as follows (in millions):
Final (2006) and preliminary (2005) Premcor Acquisition purchase price allocation and adjustments
Acquisition earn-out payments not previously accrued (see Note 23)
Settlements and adjustments related to acquisition tax contingencies, stock option exercises, and other
Settlements and adjustments related to acquisition tax contingencies, stock option exercises, and other reflected in the table above relate primarily to settlements of various income tax contingencies assumed in the UDS and Premcor Acquisitions and exercises of stock options assumed in those acquisitions, the effects of which were recorded as purchase price adjustments, and adjustments to the amount of goodwill attributable to our investment in Valero L.P. (see Note 9).
All of our goodwill has been allocated among four reporting units that comprise the refining segment. These reporting units are the Gulf Coast, Mid-Continent, Northeast, and West Coast refining regions. We completed our annual test for impairment of goodwill as of October 1, 2006 and 2005, confirming that no impairment of goodwill had occurred in any of our reporting units as of those dates.
9. INVESTMENT IN AND TRANSACTIONS WITH VALERO L.P.
Valero L.P. is a limited partnership that owns and operates crude oil and refined product pipeline, terminalling, and storage tank assets. As of December 31, 2004, we owned approximately 45.7% of Valero L.P. On July 1, 2005, Valero L.P. completed its acquisition of Kaneb Pipe Line Partners, L.P. (Kaneb Partners) and Kaneb Services LLC (together, the Kaneb Acquisition) in a transaction that included the issuance of Valero L.P. common units in exchange for Kaneb Partners’ units. In addition, we contributed $29 million to Valero L.P. to maintain our 2% general partner interest in Valero L.P. As a result of these transactions, our combined ownership interest in Valero L.P. was reduced to 23.4%. Our ownership interest in Valero L.P. remained at 23.4% as of December 31, 2005, which was composed of a 2% general partner interest, incentive distribution rights, and a 21.4% limited partner interest represented by 622,772 common units and 9,599,322 subordinated units of Valero L.P.
One of our previously wholly owned subsidiaries, Valero GP Holdings, LLC, serves as the general partner of Valero L.P. As a result of the offerings by Valero GP Holdings, LLC in July and December 2006 discussed below under the heading “Valero GP Holdings, LLC,” we no longer own any interest in Valero L.P. as of December 31, 2006.
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Valero L.P. has issued common units to the public on three separate occasions, which diluted our ownership percentage. These three issuances resulted in increases (or credits) in our proportionate share of Valero L.P.’s capital because, in each case, the issuance price per unit exceeded our carrying amount per unit at the time of issuance. We had not recognized any SAB 51 credits in our consolidated financial statements through March 31, 2006 and were not permitted to do so until our subordinated units converted to common units. In conjunction with the conversion of the subordinated units held by us to common units in the second quarter of 2006, we recognized the entire balance of $158 million in SAB 51 credits as an increase in our investment in Valero L.P. and $101 million after tax as an increase to “additional paid-in capital” in our consolidated balance sheet.
Summary Financial Information
Financial information reported by Valero L.P. is summarized below (in millions):
2005
Property and equipment, net
Other long-term assets
Total liabilities
Partners’ equity
Total liabilities and partners’ equity
Revenues
Related-Party Transactions
Under various throughput, handling, terminalling, and service agreements, we use Valero L.P.’s pipelines to transport crude oil shipped to and refined products shipped from certain of our refineries and use Valero L.P.’s refined product terminals for certain terminalling services. In addition, through 2006, we provided personnel to Valero L.P. to perform operating and maintenance services with respect to certain assets for which we received reimbursement from Valero L.P. We recognized in “cost of sales” both our costs related to the throughput, handling, terminalling, and service agreements with Valero L.P. and the receipt from Valero L.P. of payment for operating and maintenance services we provided to Valero L.P. We have indemnified Valero L.P. for certain environmental liabilities related to assets we previously sold to Valero L.P. that were known on the date the assets were sold or are discovered within a specified number of years after the assets were sold as a result of events occurring or conditions existing prior to the date of sale.
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Under a services agreement, through December 31, 2005, we provided Valero L.P. with the corporate functions of legal, accounting, treasury, engineering, information technology, and other services for an administrative fee. Effective January 1, 2006, the administrative fee was amended to provide for fewer services as a result of the transfer to Valero GP, LLC, the general partner of the general partner of Valero L.P., of a substantial number of employees of our subsidiaries who had previously provided services to Valero GP, LLC under the prior services agreement. The administrative fee is recorded as a reduction of “general and administrative expenses.” Effective January 1, 2007, the services agreement was amended to provide for limited services. Under the new services agreement, we will receive approximately $97,000 per month for administrative services (consisting primarily of human resources, information technology, risk management, and corporate communications) and approximately $92,000 per month for telecommunications services. In addition, we no longer provide operating and maintenance services to Valero L.P. This amended services agreement will terminate on December 31, 2010, unless we terminate the agreement earlier, in which case we will pay a termination fee of $13 million.
As of December 31, 2006 and 2005, our “receivables, net” included $1 million and $13 million, respectively, from Valero L.P., representing amounts due for employee costs, insurance costs, operating expenses, administrative costs, and rentals. As of December 31, 2006 and 2005, our “accounts payable” included $21 million and $22 million, respectively, to Valero L.P., representing amounts due for pipeline tariffs, terminalling fees, and tank rentals and fees. The following table summarizes the results of transactions with Valero L.P. (in millions):
Expenses charged by us to Valero L.P.
Fees and expenses charged to us by Valero L.P.
Effective July 1, 2005, we acquired Martin Oil Company LLC, a wholesale motor fuel marketer in the midwestern United States, from Valero L.P. The acquisition cost was $26 million, $22 million of which represented working capital acquired in the transaction.
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As discussed above, we have no remaining investment in Valero L.P. as of December 31, 2006. As of December 31, 2005, our investment in Valero L.P. (representing the 2% general partner interest, the incentive distribution rights, all of Valero L.P.’s subordinated units, and 622,772 of Valero L.P.’s common units) reconciled to Valero L.P.’s total partners’ equity as follows (in millions):
Valero L.P. total partners’ equity
Valero’s ownership interest in Valero L.P.
Valero’s equity in Valero L.P.’s partners’ equity
Unrecognized SAB 51 credits
Excess of proceeds over carrying amount of our retained interest in assets sold to Valero L.P., net
Step-up in basis related to Valero L.P.’s assets and liabilities, including equity method goodwill
As of December 31, 2005, our investment in Valero L.P. included 622,772 publicly traded common units, which had an aggregate market value of $32 million. A quoted market price was not available for our 2% general partner interest, the incentive distribution rights, and the 9,599,322 subordinated units we held.
Valero GP Holdings, LLC
On July 19, 2006, Valero GP Holdings, LLC consummated an initial public offering (IPO) of 17,250,000 of its units representing limited liability company interests to the public at $22.00 per unit, before an underwriters’ discount of $1.265 per unit. On December 22, 2006, Valero GP Holdings, LLC completed a secondary public offering of 20,550,000 units representing limited liability company interests at a price of $21.62 per unit, before an underwriters’ discount of $0.8648 per unit. In addition, Valero GP Holdings, LLC sold 4,700,000 unregistered units to its chairman of the board of directors (who was at that time also chairman of Valero’s board of directors) at $21.62 per unit. All such units were sold by our subsidiaries that held various ownership interests in Valero GP Holdings, LLC. As a result, Valero GP Holdings, LLC did not receive any proceeds from these offerings, and our indirect ownership interest in Valero GP Holdings, LLC was reduced to zero.
Proceeds to our selling subsidiaries from the IPO totaled approximately $355 million, net of the underwriters’ discount and other offering expenses, which resulted in a pre-tax gain to us of $132 million on the sale of the units. Proceeds to our selling subsidiaries from the secondary offering and private sale of units totaled approximately $525 million, net of the underwriters’ discount and other offering expenses, which resulted in an additional pre-tax gain to us of $196 million. The total pre-tax gain of $328 million is included in “other income (expense), net” in the consolidated statement of income for the year ended December 31, 2006. The funds received from these offerings are being used for general corporate purposes.
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10. DEFERRED CHARGES AND OTHER ASSETS
“Deferred charges and other assets, net” includes refinery turnaround and catalyst costs. As indicated in Note 1, refinery turnaround costs are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. Fixed-bed catalyst costs are deferred when incurred and amortized on a straight-line basis over the estimated useful life of the specific catalyst. Amortization expense for deferred refinery turnaround and catalyst costs was $297 million, $205 million, and $154 million for the years ended December 31, 2006, 2005, and 2004, respectively.
Cameron Highway Oil Pipeline Project
We own a 50% interest in the Cameron Highway Oil Pipeline Company, a general partnership formed to construct and operate a crude oil pipeline (the Cameron Highway Oil Pipeline Project). The 390-mile crude oil pipeline, which began operations during the first quarter of 2005, delivers up to 500,000 barrels per day from the Gulf of Mexico to the major refining areas of Port Arthur and Texas City, Texas. Our investment in the Cameron Highway Oil Pipeline Project is accounted for using the equity method and is included in “deferred charges and other assets, net” in the consolidated balance sheets. In 2005, we received a $48 million return of our investment resulting from the refinancing of the Cameron Highway Oil Pipeline Project’s debt. As of December 31, 2006 and 2005, our investment in the Cameron Highway Oil Pipeline Project totaled $100 million and $87 million, respectively.
Investment in Clear Lake Methanol Partners, L.P.
As of December 31, 2004, we and Hoechst Celanese Chemical Group, Inc. (Celanese) each held a 50% ownership interest in Clear Lake Methanol Partners, L.P. (Clear Lake), a limited partnership formed in 1994 for the purpose of refurbishing and operating Celanese’s methanol production facility in Clear Lake, Texas. Under the terms of the limited partnership arrangement, we and Celanese historically had each provided 50% of the natural gas processed at the facility and had taken 50% of the methanol produced by the facility. In December 2004, we secured a more economical supply of methanol from other sources and made the decision to discontinue our participation in the Clear Lake joint venture beginning in the second half of 2005. As a result, an impairment charge of $57 million was recognized in December 2004 to write off the carrying amount of our equity investment in Clear Lake. The impairment charge was reflected in “other income (expense), net” in the consolidated statement of income for the year ended December 31, 2004. This equity investment was previously included in the refining reporting segment as shown in Note 20. During 2005, no additional costs were incurred by us in connection with the termination of our participation in the Clear Lake joint venture, and during 2006, we received a $4 million distribution representing our portion of funds held by the Clear Lake joint venture in excess of the estimated amount required to liquidate and terminate the joint venture. This distribution was recorded in “other income (expense), net” in the consolidated statement of income for the year ended December 31, 2006.
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11. ACCRUED EXPENSES
Accrued expenses consisted of the following (in millions):
Employee wage and benefit costs
Interest expense
Contingent earn-out payments
Derivative liabilities
Environmental costs
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12. DEBT
Long-term debt balances, at stated values, consisted of the following (in millions):
Industrial revenue bonds:
Tax-exempt Revenue Refunding Bonds (a):
Series 1997A, 5.45%
Series 1997B, 5.40%
Series 1997C, 5.40%
Series 1997D, 5.125%
Tax-exempt Waste Disposal Revenue Bonds:
Series 1997, 5.6%
Series 1998, 5.6%
Series 1999, 5.7%
Series 2001, 6.65%
CORE notes, 6.311%
3.50% notes
4.75% notes
6.125% notes
6.875% notes
7.375% notes
7.50% notes
8.75% notes
Debentures:
7.25% (non-callable)
7.65% (putable July 1, 2006)
8.75% (non-callable)
Senior Notes:
6.125%
6.70%
6.75%
6.75% (putable October 15, 2009; callable thereafter)
7.20% (callable)
7.45% (callable)
7.50% (callable)
9.25% (callable) (b)
9.50% (callable)
Net unamortized premium (discount), including fair market value adjustments
Total debt
Less current portion, including unamortized (discount) premium of $10 and $(1)
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Revolving Bank Credit Facilities
As of January 1, 2005, we had two revolving bank credit facilities which provided for commitments of $750 million for a five-year term and $750 million for a three-year term.
In August 2005, we replaced our two $750 million revolving bank credit facilities with a $2.5 billion five-year revolving credit facility (the Revolver), which originally had a maturity date of August 2010. Borrowings under the Revolver bear interest at LIBOR plus a margin, or an alternate base rate as defined under the agreement. We are also being charged various fees and expenses in connection with the Revolver, including facility fees and letter of credit fees. The interest rate and fees under the Revolver are subject to adjustment based upon the credit ratings assigned to our long-term debt. The Revolver also included certain restrictive covenants including a coverage ratio and a debt-to-capitalization ratio. In July 2006, the Revolver was amended to (i) extend the maturity date by one year to August 2011, (ii) eliminate the coverage ratio covenant, and (iii) reduce the pricing under the agreement. As of December 31, 2006 and 2005, there were no borrowings outstanding under the Revolver and outstanding letters of credit issued under this facility totaled $245 million and $254 million, respectively.
In addition to the Revolver, one of our Canadian subsidiaries has a committed revolving credit facility under which it may borrow and obtain letters of credit up to Cdn. $115 million. As of both December 31, 2006 and 2005, we had no borrowings outstanding and letters of credit issued under this credit facility totaled Cdn. $85 million and Cdn. $8 million, respectively.
We also have various uncommitted short-term bank credit facilities. As of December 31, 2006 and 2005, we had no borrowings outstanding under our uncommitted short-term bank credit facilities; however, there were $343 million and $232 million, respectively, of letters of credit outstanding under such facilities. The uncommitted credit facilities have no commitment or other fees or compensating balance requirements and are unsecured and unrestricted as to use.
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Debt Resulting from Premcor Acquisition
In connection with the Premcor Acquisition, we assumed the following debt obligations, which were recorded at fair value as of September 1, 2005:
Senior notes:
7.5%
9.25%
9.5%
12.5%
7.75% senior subordinated notes
Ohio Water Development Authority Environmental Facilities Revenue Bonds
Debt assumed
Generally, the debt obligations assumed in the Premcor Acquisition are unsecured with interest payable semi-annually. During September 2005, we repurchased $190 million of the 7.75% senior subordinated notes due in February 2012. In October 2005, we repurchased the 12.5% senior notes due in January 2009 for $182 million. In November 2005, we repurchased the Ohio Water Development Authority Environmental Facilities Revenue Bonds for $10 million. In December 2006, we exercised a call provision on the 9.25% senior notes which were redeemed on February 1, 2007 for $183 million.
We also assumed two capital lease obligations of Premcor, which had a fair value of $14 million as of September 1, 2005.
As discussed in Note 2, the cash portion of the Premcor Acquisition was partially financed with proceeds received under a new $1.5 billion five-year bank term loan entered into by us in August 2005. The term loan bore interest at LIBOR plus 75 basis points. The loan was fully repaid by December 31, 2005.
Other Long-Term Debt
During March 2006, we made a scheduled debt repayment of $220 million related to our 7.375% notes. In addition, during the year ended December 31, 2006, we made the following debt payments:
$1 million during March 2006 related to our 7.75% notes due in February 2012,
$14 million during July 2006 related to our 6.75% senior notes due in May 2014, and
$14 million during July 2006 related to our 7.5% senior notes due in June 2015.
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During January 2005, we repurchased $40 million of our 7.375% notes due in 2006 and $42 million of our 6.125% notes due in 2007 at a premium of $4 million. In addition, during the year ended December 31, 2005, we made the following scheduled debt repayments:
$46 million during February 2005 related to our 7.44% medium-term notes,
$150 million during March 2005 related to our 8% medium-term notes,
$200 million during June 2005 related to our 8.375% notes, and
$14 million during August 2005 related to our 6.797% notes.
In March 2004, we issued $200 million of 3.50% Senior Notes due April 1, 2009 and $200 million of 4.75% Senior Notes due April 1, 2014 (together, the Notes). Interest is payable on the Notes on April 1 and October 1 of each year. The Notes are unsecured and are redeemable, in whole or in part, at our option. The net proceeds from this offering were used to repay borrowings under our revolving bank credit facilities. Also in March 2004, we borrowed $200 million under a five-year term loan, with a maturity date of March 31, 2009, the net proceeds of which were used to repay borrowings under our revolving bank credit facilities. In December 2004, we repaid the entire outstanding balance of this term loan and repurchased $41 million of the 7.375% notes due in March 2006 and $28 million of the 6.125% notes due in April 2007.
Our revolving bank credit facilities and other long-term debt arrangements contain various customary restrictive covenants, including cross-default and cross-acceleration clauses.
Principal payments due on long-term debt as of December 31, 2006 were as follows (in millions):
Thereafter
Net unamortized discount and fair value adjustments
As of December 31, 2006 and 2005, the estimated fair value of our long-term debt, including current portion, was as follows (in millions):
Carrying amount
Fair value
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13. OTHER LONG-TERM LIABILITIES
Other long-term liabilities consisted of the following (in millions):
Employee benefit plan liabilities
Environmental liabilities
Deferred gain on sale of assets to Valero L.P.
Insurance liabilities
Tax liabilities other than income taxes
Unfavorable lease obligations
Asset retirement obligations
Employee benefit plan liabilities include the long-term obligation for our pension and other postretirement benefit plans as discussed in Note 21. Environmental liabilities reflect the long-term portion of our estimated remediation costs for environmental matters as discussed in Note 24. Deferred gain reflects the unamortized balance of the proceeds in excess of the carrying amount of assets we sold to Valero L.P. As a result of the 2006 disposition of our entire ownership interest in Valero L.P., the portion of deferred gain previously recorded as a reduction in our investment in Valero L.P. totaling $79 million was reclassified to “other long-term liabilities” due to our continuing involvement with Valero L.P. under various throughput agreements. Insurance liabilities reflect reserves established by our two captive insurance subsidiaries, self-insured liabilities, and obligations for losses related to our participation in certain mutual insurance companies. Tax liabilities other than income taxes include long-term liabilities for franchise taxes and excise taxes as well as interest accrued on all tax-related liabilities, including income taxes. The liability for contingent earn-out payments resulted from the purchase price allocations for the Premcor Acquisition and the acquisition of the St. Charles Refinery (St. Charles Acquisition).
Unfavorable lease obligations reflect the fair value of liabilities assumed in connection with the Premcor Acquisition related to lease agreements for closed retail facilities and the UDS Acquisition related to lease agreements for retail facilities and vessel charters. Included in “other” are liabilities for various matters including legal and regulatory liabilities, derivative obligations, and various contractual obligations.
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The table below reflects the changes in our asset retirement obligations (in millions). See Note 1 under “Asset Retirement Obligations” for a discussion of the liability related to these obligations.
Additions to accrual
Accretion expense
Settlements
Changes in timing and amount of estimated cash flows
14. STOCKHOLDERS’ EQUITY
Share Activity
For the years ended December 31, 2006, 2005, and 2004, activity in the number of shares of preferred stock, common stock, and treasury stock was as follows (in millions):
Balance as of December 31, 2003
Issuance of common stock in connection with Premcor Acquisition
2% Mandatory Convertible Preferred Stock
In connection with the acquisition of the St. Charles Refinery from Orion on July 1, 2003, we issued 10 million shares of 2% mandatory convertible preferred stock. The mandatory convertible preferred stock had a fair value of $22 per share, or an aggregate of $220 million. Of this amount, $21 million was attributable to beneficial conversion terms of the preferred stock and was recorded in “additional paid-in capital” in the consolidated balance sheets, with the remaining $199 million reflected as “preferred stock.” The resulting
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$21 million preferred stock discount was amortized as additional preferred stock dividends through June 30, 2006, the day before the mandatory conversion of the preferred stock as discussed below.
Each share of convertible preferred stock was convertible, at the option of the holder, at any time before July 1, 2006 into 1.982 shares of our common stock. All mandatory convertible preferred stock not previously converted automatically converted to our common stock on July 1, 2006. Upon automatic conversion of the convertible preferred stock on July 1, 2006, 1.982 shares of common stock were issued for each share of convertible preferred stock based on the average closing price of our common stock over the 20-day trading period ending on the second trading day prior to July 1, 2006. During 2006 and 2005, 3,164,151 and 6,835,849 shares of the preferred stock were converted into 6,271,327 and 13,548,636 shares of our common stock, respectively.
Prior to the issuance of shares of our common stock upon conversion of the convertible preferred stock, the number of shares of our common stock included in the calculation of “earnings per common share – assuming dilution” for each reporting period was based on the average closing price of our common stock over the 20-day trading period ending on the second trading day prior to the end of the reporting period.
Common Stock Offerings
As discussed in Note 2, on September 1, 2005, we issued 85 million shares of common stock as partial consideration for the Premcor Acquisition. The common stock issued was recorded at a price of $37.41 per share, representing the average price of our common stock from two days before to two days after the announcement of the Premcor Acquisition in April 2005, resulting in an aggregate recorded amount of $3.2 billion for the common stock issued. In addition, we issued stock options with a fair value of $595 million.
On February 5, 2004, we sold in a public offering 31 million shares of our common stock, which included 4 million shares related to an overallotment option exercised by the underwriter, at a price of $13.32 per share and received proceeds, net of underwriter’s discount, commissions and other issuance costs, of $406 million. These shares were issued to partially fund the Aruba Acquisition discussed in Note 2.
Common Stock Splits
On July 15, 2004, our board of directors approved a two-for-one split of our common stock that was effected in the form of a stock dividend. The stock dividend was distributed on October 7, 2004 to stockholders of record on September 23, 2004. In connection with the stock split, our shareholders approved on September 13, 2004, an amendment to our certificate of incorporation to increase the number of authorized common shares from 300 million to 600 million.
On September 15, 2005, our board of directors approved another two-for-one split of our common stock that was effected in the form of a stock dividend. The stock dividend was distributed on December 15, 2005 to stockholders of record on December 2, 2005. In connection with the stock split, our shareholders approved on December 1, 2005, an amendment to our certificate of incorporation to increase the number of authorized common shares from 600 million to 1.2 billion.
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All share and per share data (except par value) for 2005 and 2004 were adjusted to reflect the effect of the stock splits. In addition, the number of shares of common stock issuable upon conversion of the mandatory convertible preferred stock, the exercise of outstanding stock options, and the vesting of other stock awards, as well as the number of shares of common stock reserved for issuance under our various employee benefit plans, were proportionately increased in accordance with the terms of those respective agreements and plans.
Treasury Stock
We purchase shares of our common stock in open market transactions to meet our obligations under employee benefit plans. We also purchase shares of our common stock from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions. During the years ended December 31, 2006, 2005, and 2004, we purchased 35 million, 13 million, and 19 million shares of our common stock, respectively, at a cost of $2.0 billion, $571 million, and $318 million, respectively, in connection with the administration of our employee benefit plans and the stock purchase program authorized by our board of directors. During the years ended December 31, 2006, 2005, and 2004, we issued 15 million, 20 million, and 11 million treasury shares, respectively, at an average cost of $55.57, $27.60, and $13.86 per share, respectively, for our employee benefit plans.
On October 19, 2006, our board of directors approved a $2 billion common stock purchase program. This new authorization is in addition to our existing authorization to purchase shares to offset dilution created by our employee stock incentive programs. Stock purchases under this program will be made from time to time at prevailing prices as permitted by securities laws and other legal requirements, and are subject to market conditions and other factors. The program does not have a scheduled expiration date.
Common Stock Dividends
Accumulated Other Comprehensive Income
Accumulated balances for each component of accumulated other comprehensive income (loss) were as follows (in millions):
Foreign
Currency
Translation
Adjustment
Pension/OPEB
Liability
Net Gain
(Loss) OnCash Flow
Hedges
2004 change
2005 change
2006 change
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15. EARNINGS PER SHARE
Earnings per common share amounts were computed as follows (dollars and shares in millions, except per share amounts):
Earnings per Common Share:
Weighted-average common shares outstanding
Earnings per Common Share – Assuming Dilution:
Net income applicable to common equivalent shares
Effect of dilutive securities:
Stock options
Performance awards and other benefit plans
Mandatory convertible preferred stock
Weighted-average common equivalent shares outstanding
The following table reflects outstanding stock options that were not included in the computation of dilutive securities because the options’ exercise prices were greater than the average market price of the common shares during the reporting period, and therefore the effect of including such options would be anti-dilutive (in millions):
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16. STATEMENTS OF CASH FLOWS
In order to determine net cash provided by operating activities, net income is adjusted by, among other things, changes in current assets and current liabilities as follows (in millions):
Decrease (increase) in current assets:
Increase (decrease) in current liabilities:
The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable consolidated balance sheets for the respective periods for the following reasons:
the amounts shown above exclude changes in cash and temporary cash investments, deferred income taxes, short-term debt, and current portion of long-term debt and capital lease obligations, as well as the effect of certain noncash investing and financing activities discussed below;
the amounts shown above exclude the current assets and current liabilities acquired in connection with the Premcor Acquisition and certain minor acquisitions in 2005 and the Aruba Acquisition in 2004, as well as the current assets and current liabilities disposed of in connection with the sale of the Denver Refinery in 2005, all of which are reflected separately in the consolidated statements of cash flows;
previously accrued contingent earn-out payments and capital investments are reflected in investing activities in the consolidated statements of cash flows; and
certain differences between consolidated balance sheet changes and consolidated statement of cash flow changes reflected above result from translating foreign currency denominated amounts at different exchange rates.
Noncash investing and financing activities for the year ended December 31, 2006 included:
the recognition of $158 million (pre-tax) of SAB 51 credits related to our investment in Valero L.P. (as discussed in Note 9);
adjustments to property, plant and equipment, goodwill, and certain current and noncurrent assets and liabilities resulting from adjustments to the purchase price allocations related to the Premcor and UDS Acquisitions;
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the conversion of 3,164,151 shares of preferred stock into 6,271,327 shares of our common stock as discussed in Note 14; and
the recognition of a $39 million capital lease obligation and related capital lease asset pertaining to certain facilities at our Lima Refinery.
Noncash investing and financing activities for the year ended December 31, 2005 included:
the issuance of $3.2 billion (85 million shares) of common stock and $595 million of vested employee stock options as partial consideration for the Premcor Acquisition;
the conversion of 6,835,849 shares of preferred stock into 13,548,636 shares of our common stock as discussed in Note 14;
the recognition of a $28 million capital lease obligation and related capital lease asset pertaining to certain equipment at our Texas City Refinery; and
adjustments to property, plant and equipment and certain current and noncurrent assets and liabilities resulting from adjustments to the purchase price allocation related to the Aruba Acquisition.
Noncash investing activities for the year ended December 31, 2004 included adjustments to property, plant and equipment and certain current and noncurrent assets and liabilities resulting from adjustments to the purchase price allocation related to the St. Charles Acquisition (including recognition of the $175 million of potential earn-out payments related to the St. Charles Acquisition). There were no significant noncash financing activities for the year ended December 31, 2004.
Cash flows related to interest and income taxes were as follows (in millions):
Interest paid (net of amount capitalized)
Income taxes paid, net of tax refunds received
17. PRICE RISK MANAGEMENT ACTIVITIES
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 refining operations. To reduce the impact of this price volatility, we use derivative commodity instruments (swaps, futures, and options) to manage our exposure to:
changes in the fair value of a portion of our refinery feedstock and refined product inventories and a portion of our unrecognized firm commitments to purchase these inventories (fair value hedges);
changes in cash flows of certain forecasted transactions such as forecasted feedstock and product purchases, natural gas purchases, and refined product sales (cash flow hedges); and
price volatility on a portion of our refinery feedstock and refined product inventories and on certain forecasted feedstock and product purchases, refined product sales, and natural gas purchases that are not designated as either fair value or cash flow hedges (economic hedges).
In addition, we use derivative commodity instruments for trading purposes based on our fundamental and technical analysis of market conditions.
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Interest Rate Risk
We are exposed to market risk for changes in interest rates related to certain of our long-term debt obligations. We sometimes use interest rate swap agreements to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt.
As of December 31, 2005, we had interest rate swap agreements with a notional amount of $1.0 billion and interest rates ranging from 5.6% to 6.0%. All of these swaps were accounted for as fair value hedges. During the first quarter of 2006, $125 million of these interest rate swaps were settled on their scheduled maturity date. Effective May 1, 2006, we terminated the remaining $875 million of interest rate swap contracts outstanding at that date for a payment of $54 million. Substantially all of this payment was deferred and is being amortized to interest expense over the remaining lives of the debt instruments that were being hedged.
Foreign Currency Risk
We are exposed to exchange rate fluctuations on transactions related to our Canadian operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments.
As of December 31, 2006, we had commitments to purchase $290 million of U.S. dollars. These commitments matured on or before January 19, 2007, resulting in a 2007 gain of $4 million.
Current Period Disclosures
The net gain (loss) recognized in income representing the amount of hedge ineffectiveness was as follows (in millions):
Fair value hedges
Cash flow hedges
The above amounts were included in “cost of sales” in the consolidated statements of income. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness. No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges.
During 2005, we recognized in “cost of sales” approximately $525 million of pre-tax losses resulting from the forward sales of distillates and associated forward purchases of crude oil. All of these forward derivative positions were closed prior to December 31, 2005. During 2006, 2005, and 2004, we recognized in “cost of sales” gains (losses) of $4 million, $(6) million, and $26 million, respectively, associated with trading activities.
For cash flow hedges, gains and losses reported in “accumulated other comprehensive income” in the consolidated balance sheets are reclassified into cost of sales when the forecasted transactions affect income. During the years ended December 31, 2006, 2005, and 2004, respectively, we recognized in “accumulated other comprehensive income” unrealized after-tax gains (losses) of $70 million, $(218) million, and $(168) million on certain cash flow hedges, primarily related to forward sales of gasoline and distillates and associated forward purchases of crude oil, with $45 million, $4 million, and $(49) million of cumulative after-tax gains (losses) on cash flow hedges remaining in “accumulated other comprehensive income” as of
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December 31, 2006, 2005, and 2004, respectively. The deferred gains at December 31, 2006 will be reclassified into “cost of sales” in 2007 as a result of hedged transactions that are forecasted to occur. The amount ultimately realized in income, however, will differ as commodity prices change. For the years ended December 31, 2006, 2005, and 2004, there were no amounts reclassified from “accumulated other comprehensive income” into income as a result of the discontinuance of cash flow hedge accounting.
Market and Credit Risk
Our price risk management activities involve the receipt or payment of fixed price commitments into the future. These transactions give rise to market risk, the risk that future changes in market conditions may make an instrument less valuable. We closely monitor and manage our exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Market risks are monitored by a risk control group to ensure compliance with our stated risk management policy. Concentrations of customers in the refining industry may impact our overall exposure to credit risk, in that these customers may be similarly affected by changes in economic or other conditions. We believe that our counterparties will be able to satisfy their obligations under their price risk management contracts with us.
18. PREFERRED SHARE PURCHASE RIGHTS
Each outstanding share of our common stock is accompanied by one preferred share purchase right (Right). With certain exceptions, each Right entitles the registered holder to purchase from us .0025 of a share of our Junior Participating Preferred Stock, Series I at a price of $100 per .0025 of a share, subject to adjustment for certain recapitalization events.
The Rights are transferable only with the common stock until the earlier of:
10 days following a public announcement that a person or group of affiliated or associated persons (Acquiring Person) has acquired beneficial ownership of 15% or more of the outstanding shares of our common stock,
10 business days (or later date as may be determined by our board of directors) following the initiation of a tender offer or exchange offer that would result in an Acquiring Person having beneficial ownership of 15% or more of our outstanding common stock (the earlier of these two options being called the Rights Separation Date), or
the earlier redemption or expiration of the Rights.
The Rights are not exercisable until the Rights Separation Date. At any time prior to the acquisition by an Acquiring Person of beneficial ownership of 15% or more of our outstanding common stock, our board of directors may redeem the Rights at a price of $0.01 per Right. The Rights will expire on June 30, 2007, unless we extend, redeem, or exchange the Rights.
If, after the Rights Separation Date, we are acquired in a merger or other business combination transaction, or if 50% or more of our consolidated assets or earning power is sold, each holder of a Right will have the right to receive, upon the exercise of the Right at its then current exercise price, that number of shares of common stock of the acquiring company which at the time of the transaction will have a market value of two times the exercise price of the Right. In the event that any Acquiring Person becomes the beneficial owner of 15% or more of our outstanding common stock, each holder of a Right, other than Rights beneficially owned by the Acquiring Person (which will thereafter be void), will thereafter have the right to receive upon exercise that number of shares of common stock having a market value of two times the exercise price of the Right.
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At any time after an Acquiring Person acquires beneficial ownership of 15% or more of our outstanding common stock and prior to the acquisition by the Acquiring Person of 50% or more of our outstanding common stock, our board of directors may exchange the Right (other than Rights owned by the Acquiring Person which have become void), at an exchange ratio of one share of common stock, or .0025 of a share of Junior Preferred Stock, per Right (subject to adjustment).
Until a Right is exercised, the holder will have no rights as our stockholder, including, without limitation, the right to vote or to receive dividends. The Rights may have certain anti-takeover effects. The Rights will cause substantial dilution to any Acquiring Person that attempts to acquire us on terms not approved by our board of directors, except pursuant to an offer conditioned on a substantial number of Rights being acquired. The Rights should not interfere with any merger or other business combination approved by our board of directors since the Rights may be redeemed by us prior to the time that an Acquiring Person has acquired beneficial ownership of 15% or more of our outstanding common stock.
19. INCOME TAXES
Components of income tax expense (benefit) were as follows (in millions):
Current:
U.S. federal
U.S. state
Canada
Total current
Deferred:
Total deferred
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The following is a reconciliation of total income tax expense to income taxes computed by applying the statutory federal income tax rate (35% for all years presented) to income before income tax expense (in millions):
Federal income tax expense at the U.S. statutory rate
U.S. state income tax expense, net of U.S. federal income tax effect
U.S. manufacturing deduction
Canadian operations
Aruban operations
Other, net
The Aruba Refinery’s profits are non-taxable in Aruba due to a tax holiday granted by the Government of Aruba through December 31, 2010. The tax holiday resulted in increased net income of $6 million, or $0.01 per common share – assuming dilution, $11 million, or $0.02 per common share – assuming dilution, and $5 million, or $0.01 per common share – assuming dilution, for the years ended December 31, 2006, 2005, and 2004, respectively.
Income before income tax expense from domestic and foreign operations was as follows (in millions):
U.S. operations
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The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows (in millions):
Deferred income tax assets:
Tax credit carryforwards
Net operating losses (NOL)
Compensation and employee benefit liabilities
Environmental
Other assets
Total deferred income tax assets
Less: Valuation allowance
Net deferred income tax assets
Deferred income tax liabilities:
Turnarounds
Total deferred income tax liabilities
Net deferred income tax liabilities
As of December 31, 2006, we had the following U.S. federal and state income tax credit and loss carryforwards (in millions):
U.S. state income tax credits
Foreign tax credit
U.S. state NOL
We have recorded a valuation allowance as of December 31, 2006 and 2005, due to uncertainties related to our ability to utilize some of our deferred income tax assets, primarily consisting of certain state net operating losses, state income tax credits, and foreign tax credits, before they expire. The valuation allowance is based on our estimates of taxable income in the various jurisdictions in which we operate and the period over which deferred income tax assets will be recoverable. The realization of net deferred income tax assets recorded as of December 31, 2006 is dependent upon our ability to generate future taxable income in the United States, Canada, and Aruba.
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Subsequently recognized tax benefits related to the valuation allowance for deferred tax assets as of December 31, 2006 will be allocated as follows (in millions):
Income tax benefit in consolidated statement of income
U.S. federal deferred income taxes and Canadian withholding taxes have not been provided for on the undistributed earnings of our Canadian and Aruban subsidiaries based on the determination that those earnings will be indefinitely reinvested in our foreign operations. As of December 31, 2006, the cumulative undistributed earnings of these subsidiaries were approximately $2.9 billion. If those earnings were not considered indefinitely reinvested, U.S. federal deferred income taxes and Canadian withholding taxes would have been recorded after consideration of foreign tax credits. It is not practicable to estimate the amount of additional tax that might be payable on this foreign income, if distributed.
Our tax years through 1999 and UDS’s tax years through 1998 are closed to adjustment by the Internal Revenue Service. UDS’s separate tax years 1999, 2000, and 2001 and Valero’s separate tax years 2000 and 2001 (prior to the UDS Acquisition) are currently under examination. In addition, our tax years 2002 and 2003 are currently under examination and Premcor’s separate tax years 2002 and 2003 are also under examination. We believe that adequate provisions for income taxes have been reflected in the consolidated financial statements.
See Note 1 under “New Accounting Pronouncements – FASB Interpretation No. 48” for a discussion of certain changes in our accounting for income taxes that were effective on January 1, 2007.
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20. SEGMENT INFORMATION
We have two reportable segments, refining and retail. Our refining segment includes refining operations, wholesale marketing, product supply and distribution, and transportation operations. The retail segment includes company-operated convenience stores, Canadian dealers/jobbers and truckstop facilities, cardlock facilities, and home heating oil operations. Operations that are not included in either of the two reportable segments are included in the corporate category.
The reportable segments are strategic business units that offer different products and services. They are managed separately as each business requires unique technology and marketing strategies. Performance is evaluated based on operating income. Intersegment sales are generally derived from transactions made at prevailing market rates.
Year ended December 31, 2006:
Operating revenues from external customers
Intersegment revenues
Operating income (loss)
Total expenditures for long-lived assets
Year ended December 31, 2005:
Year ended December 31, 2004:
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Our principal products include conventional and CARB gasolines, RBOB, low-sulfur diesel, and oxygenates and other gasoline blendstocks. We also produce a substantial slate of middle distillates, jet fuel, and petrochemicals, in addition to lube oils and asphalt. Through December 31, 2005, our revenues related to crude oil buy/sell arrangements were included in the refining segment in the “other product revenues” line in the table below. Commencing January 1, 2006, in accordance with the guidance provided by EITF 04-13, revenues and cost of sales related to these arrangements ceased to be recognized (see Note 1 for a discussion of EITF 04-13 in “Revenue Recognition”). Other product revenues also include such products as gas oils, No. 6 fuel oil, and petroleum coke. Operating revenues from external customers for our principal products for the years ended December 31, 2006, 2005, and 2004 were as follows (in millions):
Lubes and asphalts
Other product revenues
Total refining operating revenues
Retail:
Fuel sales (gasoline and diesel)
Merchandise sales and other
Home heating oil
Total retail operating revenues
Consolidated operating revenues
Operating revenues by geographic area for the years ended December 31, 2006, 2005, and 2004 are shown in the table below (in millions). The geographic area is based on location of customer.
United States
Other foreign countries
For the years ended December 31, 2006, 2005, and 2004, no customer accounted for more than 10% of our consolidated operating revenues.
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Long-lived assets include property, plant and equipment, intangible assets subject to amortization, and certain long-lived assets included in “deferred charges and other assets, net.” Geographic information by country for long-lived assets consisted of the following (in millions):
Consolidated long-lived assets
Total assets by reportable segment were as follows (in millions):
Total consolidated assets
The entire balance of goodwill as of December 31, 2006 and 2005 has been included in the total assets of the refining reportable segment.
21. EMPLOYEE BENEFIT PLANS
Pension Plans and Postretirement Benefits Other Than Pensions
We have several qualified non-contributory defined benefit plans (the Qualified Plans), some of which are subject to collective bargaining agreements. The Qualified Plans cover substantially all employees in the United States and generally provide eligible employees with retirement income based on years of service and compensation during specific periods.
We also have various nonqualified supplemental executive retirement plans (Supplemental Plans) which provide additional pension benefits to executive officers and certain other employees. The Supplemental Plans and the Qualified Plans are collectively referred to as the Pension Plans.
We also provide certain health care and life insurance benefits for retired employees, referred to as other postretirement benefits. Substantially all of our employees may become eligible for these benefits if, while still working for us, they either reach normal retirement age or take early retirement. We offer health care benefits through a self-insured plan and, for certain locations, a health maintenance organization while life insurance benefits are provided through an insurance company. We fund our postretirement benefits other than pensions on a pay-as-you-go basis. Individuals who became our employees as a result of an acquisition became eligible for other postretirement benefits under our plan as determined by the terms of the relevant acquisition agreement.
We assumed certain obligations under various pension and other postretirement plans in conjunction with the Aruba and Premcor Acquisitions, and in connection with the Kaneb Acquisition by Valero L.P. Our initial
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obligations under these plans were recorded through purchase accounting as of the date of each respective acquisition. Our disclosures include net periodic benefit costs related to such obligations commencing on the date of acquisition. In conjunction with the sale of our ownership interest in Valero GP Holdings, LLC discussed in Note 9, effective July 1, 2006, certain eligible employees of Valero GP, LLC ceased participating in our Pension Plans and other postretirement benefit plans. These former employees became participants in separate employee benefit plans of Valero GP, LLC. Certain liabilities related to pension and other postretirement benefits for these participants were transferred from us to Valero GP, LLC and are included in the disclosures below as “Spin-off of Valero L.P.”
The FASB has provided guidance on accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Medicare Act) for sponsors of postretirement health care plans. We incorporated the effects of the Medicare Act into the regular measurement of plan obligations as of December 31, 2004, which resulted in a $15 million reduction in the accumulated postretirement benefit obligation as of December 31, 2004 and a $2 million reduction in the net periodic postretirement benefit cost for 2005.
We use December 31 as the measurement date for our Pension Plans and other postretirement benefit plans.
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The changes in benefit obligation, the changes in fair value of plan assets, and the funded status of our Pension Plans and other postretirement benefit plans as of and for the years ended December 31, 2006 and 2005 were as follows (in millions):
Other Postretirement
Change in benefit obligation:
Benefit obligation at beginning of year
Service cost
Interest cost
Acquisitions
Participant contributions
Plan amendments
Special termination benefits
Spin-off of Valero L.P.
Benefits paid
Actuarial (gain) loss
Foreign currency exchange rate changes
Benefit obligation at end of year
Change in plan assets:
Fair value of plan assets at beginning of year
Actual return on plan assets
Valero contributions
Fair value of plan assets at end of year
Reconciliation of funded status:
Less: Benefit obligation at end of year
Funded status at end of year
Unrecognized net loss
Unrecognized prior service cost (credit)
Accrued benefit cost
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The pre-tax amounts related to our Pension Plans and other postretirement benefit plans recognized in our consolidated balance sheets as of December 31, 2006 and 2005 were as follows (in millions):
Accumulated other comprehensive loss
The pre-tax amounts in accumulated other comprehensive income (loss) as of December 31, 2006 that have not yet been recognized as components of net periodic benefit cost were as follows (in millions):
Net actuarial loss
Prior service credit (cost)
The following amounts included in accumulated other comprehensive income as of December 31, 2006 are expected to be recognized as components of net periodic benefit cost during the year ending December 31, 2007 (in millions):
Amortization of prior service cost (credit)
Amortization of loss
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As of December 31, 2006 and 2005, the accumulated benefit obligation for our Pension Plans was $986 million and $925 million, respectively. As of December 31, 2006 and 2005, the accumulated benefit obligation for each of our Pension Plans was in excess of plan assets, with the exception of the main Qualified Plan as of December 31, 2006. We made $340 million of contributions to the main Qualified Plan during 2006, and as a result, the plan assets were in excess of the projected benefit obligation and the accumulated benefit obligation for the main Qualified Plan by $66 million and $294 million, respectively, as of December 31, 2006. The aggregate projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for our Pension Plans for which the accumulated benefit obligation exceeded the fair value of plan assets were as follows (in millions):
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
The percentage of fair value of plan assets by asset category for the Qualified Plans as of December 31, 2006 and 2005 are shown below. There are no plan assets for other postretirement benefit plans.
Equity securities
Mutual funds
Corporate debt securities
Government securities
Insurance contracts
Money market funds
Equity securities in the Qualified Plans include our common stock in the amounts of approximately $66 million (6% of total Qualified Plan assets) and $85 million (11% of total Qualified Plan assets) as of December 31, 2006 and 2005, respectively.
The investment policies and strategies for the assets of our Qualified Plans incorporate a well-diversified approach which is expected to earn long-term returns from capital appreciation and a growing stream of current income. This approach recognizes that assets are exposed to risk and the market value of the Qualified Plans’ assets may fluctuate from year to year. Risk tolerance is determined based on our financial ability to withstand risk within the investment program and the willingness to accept return volatility. In line with the investment return objective and risk parameters, the Qualified Plans’ mix of assets includes a diversified portfolio of equity and fixed-income investments. Equity investments include international stocks and a blend of domestic growth and value stocks of various sizes of capitalization. The aggregate asset allocation is reviewed on an annual basis.
The overall expected long-term rate of return on plan assets for the Qualified Plans is estimated using models of asset returns. Model assumptions are derived using historical data given the assumption that capital markets are informationally efficient. Three methods are used to derive the long-term expected returns for each asset
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class. Since each method has distinct advantages and disadvantages and differing results, an equal weighted-average of the methods’ results is used.
Although we have no expected minimum required contribution to our Qualified Plans during 2007 under the Employee Retirement Income Security Act, we expect to contribute $100 million to our Qualified Plans during 2007.
The following benefit payments, which reflect expected future service and anticipated Medicare subsidy, as appropriate, are expected to be paid (received) for the years ending December 31 (in millions):
HealthCare
SubsidyReceipts
Years 2012-2016
The components of net periodic benefit cost were as follows for the years ended December 31, 2006, 2005, and 2004 (in millions):
Components of net periodic benefit cost:
Expected return on plan assets
Amortization of:
Prior service cost (credit)
Net loss
Net periodic benefit cost before special charges
Charge for special termination benefits
Net periodic benefit cost
Amortization of prior service cost shown in the above table was based on the average remaining service period of employees expected to receive benefits under the plan.
The pre-tax increase in the additional minimum pension liability which was recognized in “other comprehensive income” was $1 million and $1 million for the years ended December 31, 2006 and 2005, respectively, with no change for the year ended December 31, 2004.
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The weighted-average assumptions used to determine the benefit obligations as of December 31, 2006 and 2005 were as follows:
Discount rate
Rate of compensation increase
We select the discount rate based on a review of long-term bonds that receive one of the two highest ratings given by a recognized rating agency as of December 31 of each year. The average timing of benefit payments from our plans is compared to the average timing of cash flows from the long-term bonds to assess potential timing adjustments. Based on this analysis, there were no significant differences in the timing of the cash flows, and therefore no adjustments were necessary.
The weighted-average assumptions used to determine the net periodic benefit cost for the years ended December 31, 2006, 2005, and 2004 were as follows:
Expected long-term rate of return on plan assets
The assumed health care cost trend rates as of December 31, 2006 and 2005 were as follows:
Health care cost trend rate assumed for next year
Rate to which the cost trend rate was assumed to decline (the ultimate trend rate)
Year that the rate reaches the ultimate trend rate
Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one percentage-point change in assumed health care cost trend rates would have the following effects on other postretirement benefits (in millions):
Effect on total of service and interest cost components
Effect on accumulated postretirement benefit obligation
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Profit-Sharing/Savings Plans
Valero Energy Corporation Thrift Plan
We are the sponsor of the Valero Energy Corporation Thrift Plan, which is a qualified employee profit-sharing plan. Participation in the Thrift Plan is voluntary. Through June 30, 2006, employees were eligible to participate in the plan upon the completion of one month of continuous service. Effective July 1, 2006, participants may participate in the plan as soon as practicable following enrollment. This service may include prior employment with other companies we acquire.
Thrift Plan participants can make basic contributions up to 8% of their total annual salary, which includes overtime and cash bonuses. In addition, participants who make a basic contribution of 8% can also make a supplemental contribution of up to 22% of their total annual salary. We match 75% of each participant’s total basic contributions up to 8% based on the participant’s total annual salary, excluding cash bonuses.
Our contributions to the Thrift Plan for the years ended December 31, 2006, 2005, and 2004 were $37 million, $31 million, and $27 million, respectively.
Valero Savings Plan
The Valero Savings Plan is a defined contribution plan covering our retail store employees. Under the Valero Savings Plan, participants can contribute from 1% to 30% of their compensation. We contribute $0.60 for every $1.00 of the participant’s contribution up to 6% of compensation.
Our contributions to the Valero Savings Plan were $5 million for each of the years ended December 31, 2006, 2005, and 2004.
Premcor Retirement Savings Plan
The Premcor Retirement Savings Plan is a defined contribution plan covering former Premcor employees who became employees of Valero effective September 1, 2005. Under this plan, participants can contribute from 1% to 50% of their eligible compensation. We contribute 200% of the first 3% of a participant’s pre-tax contribution. In addition, we contribute 100% of a participant’s pre-tax contribution above 3% up to 6% for certain union participants who contribute to the plan.
Our contributions to the Premcor Retirement Savings Plan for the year ended December 31, 2006 were $9 million and for the period from September 1, 2005 (the date of the Premcor Acquisition) to December 31, 2005 were $2 million.
22. STOCK-BASED COMPENSATION
As discussed in Note 1, on January 1, 2006, we adopted Statement No. 123R, which requires the expensing of the fair value of stock compensation awards. Prior to our adoption of Statement No. 123R, we accounted for our employee stock compensation plans using the intrinsic value method of accounting set forth in APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as permitted by Statement No. 123, “Accounting for Stock-Based Compensation.”
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We have various fixed and performance-based stock compensation plans under which awards may currently be granted, which are summarized as follows:
The 2005 Omnibus Stock Incentive Plan (the OSIP) authorizes the grant of various stock and stock-based awards to our employees and our non-employee directors. Awards available under the OSIP include options to purchase shares of common stock, performance awards that vest upon the achievement of an objective performance goal, and restricted stock which vests over a period determined by our compensation committee. As of December 31, 2006, a total of 19,235,942 shares of our common stock remained available to be awarded under the OSIP.
A non-employee director stock option plan provides our non-employee directors with grants of stock options to purchase our common stock. Effective January 1, 2007, each director will be granted an option to purchase 10,000 shares of our common stock upon initial election to our board of directors. Prior to January 1, 2007, the plan provided automatic grants of stock options upon their election to our board of directors and annual grants of stock options upon their continued service on the board. As of December 31, 2006, a total of 278,000 shares of our common stock remained available for issuance under this plan. These options expire seven years from the date of grant.
Through December 31, 2006, our restricted stock plan for non-employee directors provided non-employee directors, upon their election to the board of directors, a grant of our common stock valued at $60,000 that vests in three equal annual installments. Effective January 1, 2007, each non-employee director will receive an annual grant of our common stock valued at $80,000 that vests in three equal annual installments. As of December 31, 2006, a total of 261,458 shares of our common stock remained available to be awarded under this plan.
The 2003 Employee Stock Incentive Plan authorizes the grant of various stock and stock-related awards to employees and prospective employees. Awards include options to purchase shares of common stock, performance awards that vest upon the achievement of an objective performance goal, stock appreciation rights, and restricted stock which vests over a period determined by our compensation committee. As of December 31, 2006, a total of 3,162,234 shares of our common stock remained available to be awarded under this plan.
In addition, we formerly maintained other stock option plans under which previously granted stock options remain outstanding. No shares are available to be awarded under these plans.
Each of our current stock-based compensation arrangements is discussed below. The tax benefit realized for tax deductions resulting from exercises and vestings under all of our stock-based compensation arrangements totaled $264 million, $278 million, and $56 million for the years ended December 31, 2006, 2005, and 2004, respectively.
Stock Options
Under the terms of our various stock option plans, the exercise price of options granted is not less than the fair market value of our common stock on the date of grant. Stock options become exercisable pursuant to the individual written agreements between the participants and us, usually in three or five equal annual installments beginning one year after the date of grant, with unexercised options generally expiring seven or ten years from the date of grant.
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The fair value of each stock option grant was estimated on the grant date using the Black-Scholes option-pricing model. The expected life of options granted is the period of time from the grant date to the date of expected exercise or other expected settlement. Expected volatility is based on closing prices of our common stock for periods corresponding to the life of options granted. Expected dividend yield is based on annualized dividends at the date of grant. The risk-free interest rate used is the implied yield currently available from the U.S. Treasury zero-coupon issues with a remaining term equal to the expected life of the options at the grant date. A summary of the weighted-average assumptions used in our fair value measurements is presented in the table below:
Expected life in years
Expected volatility
Expected dividend yield
Risk-free interest rate
A summary of the status of our stock option awards is presented in the table below.
Number
of StockOptions
Weighted-
Average
Exercise
Per Share
Remaining
Contractual
Term
Aggregate
Intrinsic
Outstanding at January 1, 2006
Granted
Exercised
Forfeited
Outstanding at December 31, 2006
Exercisable at December 31, 2006
The weighted-average grant-date fair value of stock options granted during the years ended December 31, 2006, 2005, and 2004 was $19.76, $18.80, and $8.02 per stock option, respectively. The total intrinsic value of stock options exercised during the years ended December 31, 2006, 2005, and 2004 was $385 million, $297 million, and $146 million, respectively. Cash received from stock option exercises for the years ended December 31, 2006, 2005, and 2004 was $77 million, $152 million, and $77 million, respectively.
As of December 31, 2006, there was $80 million of unrecognized compensation cost related to outstanding unvested stock option awards, which is expected to be recognized over a weighted-average period of approximately two years.
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Restricted Stock
Restricted stock is granted to employees and non-employee directors. Restricted stock vests in accordance with individual written agreements between the participants and us, usually in equal annual installments over a period of five years beginning one year after the date of grant. A summary of the status of our restricted stock awards is presented in the table below.
Number of
Shares
Grant-Date
Fair Value
Nonvested shares at January 1, 2006
Vested
Nonvested shares at December 31, 2006
As of December 31, 2006, there was $48 million of unrecognized compensation cost related to outstanding unvested restricted stock awards, which is expected to be recognized over a weighted-average period of approximately four years. The total fair value of restricted stock that vested during the years ended December 31, 2006, 2005, and 2004 was $24 million, $18 million, and $5 million, respectively.
Performance Awards
We issue performance awards to certain key employees which represent rights to receive shares of Valero common stock only upon Valero’s achievement of an objective performance measure. Performance awards are subject to vesting in three annual amounts beginning approximately one year after the date of grant. The number of common shares earned each year is based on the vested award adjusted by a factor determined by our total shareholder return over a rolling three-year period compared to the total shareholder return of a defined peer group for the same time period.
During the year ended December 31, 2006, 143,010 performance awards were issued and 11,033 awards were forfeited. The fair value of performance awards subject to vesting for the year ended December 31, 2006 was based on an expected conversion to common shares at a rate of 150% and a weighted-average fair value of $58.90 per share, representing the market value of our common stock on the grant date reduced by expected dividends over the vesting period. The total fair value of performance awards that vested during the years ended December 31, 2006, 2005, and 2004 was $263 million, $15 million, and $4 million, respectively.
Restricted Stock Units
As of December 31, 2006, 204,790 unvested restricted stock units were outstanding. Restricted stock units vest in equal annual amounts over a three-year or five-year period beginning one year after the date of grant. These restricted stock units are payable in cash based on the price of our common stock on the date of vesting, and therefore they are accounted for as liability-based awards under Statement No. 123R. For the years ended December 31, 2006, 2005, and 2004, cash payments of $25 million, $24 million, and $8 million, respectively, were made for vested restricted stock units. During the year ended December 31, 2006, 16,380 restricted stock units were granted and no units were forfeited. Based on the price of our common stock on December 31,
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2006, the fair value of the unvested restricted stock units was $10 million, of which $3 million was recognized as of December 31, 2006.
23. COMMITMENTS AND CONTINGENCIES
Leases
We have long-term operating lease commitments for land, office facilities, retail facilities and related equipment, transportation equipment, time charters for ocean-going tankers and coastal vessels, dock facilities, and various facilities and equipment used in the storage, transportation, production, and sale of refinery feedstocks and refined products.
Certain leases for production equipment and feedstock and refined product storage facilities provide for various contingent payments based on, among other things, throughput volumes in excess of a base amount. Certain leases for vessels contain renewal options and escalation clauses, which vary by charter, and provisions for the payment of chartering fees, which either vary based on usage or provide for payments, in addition to established minimums, that are contingent on usage. Leases for convenience stores may also include provisions for contingent rental payments based on sales volumes. In most cases, we expect that in the normal course of business, our leases will be renewed or replaced by other leases.
As of December 31, 2006, our future minimum rentals and minimum rentals to be received under subleases for leases having initial or remaining noncancelable lease terms in excess of one year were as reflected in the following table (in millions).
Operating
Remainder
Total minimum rental payments
Less minimum rentals to be received under subleases
Net minimum rental payments
Less interest expense
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Consolidated rental expense for all operating leases was as follows (in millions):
Minimum rental expense
Contingent rental expense
Total rental expense
Less sublease rental income
Net rental expense
Structured Lease Arrangements
In early 2004, we had various long-term operating lease commitments that were funded through structured lease arrangements with non-consolidated third party entities (the lessors). These leases were for land, office facilities and equipment, dock facilities, transportation equipment, and various facilities and equipment used in the production of refined products. In March 2004, we exercised our option to purchase the leased properties under these structured lease arrangements, and the leased properties, which totaled $567 million, were purchased through borrowings under our existing bank credit facilities. These purchases were capitalized in property, plant and equipment.
Other Commitments
We have various purchase obligations under certain industrial gas and chemical supply arrangements (such as hydrogen supply arrangements), crude oil and other feedstock supply arrangements, and various throughput and terminalling agreements. We enter into these contracts to ensure an adequate supply of utilities, feedstock, and storage to operate our refineries. Many of our purchase obligations are based on market prices or adjustments based on market indices. Certain of these purchase obligations include fixed or minimum volume requirements, while others are based on our usage requirements. The purchase obligations reflected below include both short-term and long-term obligations as of December 31, 2006, and are based on minimum quantities to be purchased and/or estimated prices to be paid under the agreements based on current market conditions. These purchase obligations are not reflected in the consolidated balance sheets.
Estimated future annual purchase obligations as of December 31, 2006 were as follows (in millions):
Estimated future purchase obligations
As discussed in Note 4, as of December 31, 2006, we had an accounts receivable sales facility with a group of third-party financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables, which matures in August 2008. As of December 31, 2006, the amount of eligible receivables sold to the third-party financial institutions was $1 billion.
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Contingent Earn-Out Agreements
In connection with our acquisitions of Basis Petroleum, Inc. in 1997 and the St. Charles Refinery in 2003, the sellers are entitled to receive payments in any of the ten and seven years, respectively, following these acquisitions if certain average refining margins during any of those years exceed a specified level. In connection with the Premcor Acquisition in 2005, we assumed Premcor’s obligation under a contingent earn-out agreement related to Premcor’s acquisition of the Delaware City Refinery from Motiva Enterprises LLC (Motiva). Under this agreement, Motiva was entitled to receive two separate annual earn-out payments depending on (a) the amount of crude oil processed at the refinery and the level of refining margins through May 2007, and (b) the achievement of certain performance criteria at the gasification facility through May 2006.
The following table summarizes the aggregate payments we have made and payment limitations related to the following acquisitions (in millions). The amounts reflected for the Delaware City Refinery represent amounts applicable only to the throughput/margin earn-out contingency since the earn-out contingency related to the refinery’s gasification facility expired during the second quarter of 2006 with no payment required. The amounts reflected represent only amounts for which we are potentially liable subsequent to the Premcor Acquisition.
Basis
Petroleum,
Inc.
Delaware
City
Payments made during the year ended December 31:
2004
2006
Aggregate payments made through 2006
Annual maximum limit
Aggregate limit
For the acquisition of Basis Petroleum, Inc., we account for payments under this arrangement as an additional cost of the acquisition when the payments are made. As of December 31, 2006, $47 million of the aggregate earn-out payments related to this acquisition had been attributed to “property, plant and equipment” and is being depreciated over the remaining lives of the assets to which the additional cost was allocated and $153 million had been attributed to “goodwill” and is not being amortized.
As part of the purchase price allocation related to the St. Charles Acquisition, a liability was accrued for the aggregate limit of potential earn-out payments totaling $175 million. The offsetting amount is reflected in “property, plant and equipment” and is being depreciated over the remaining lives of the assets to which the cost was allocated. In January 2007, we made an additional earn-out payment of $50 million related to the St. Charles Acquisition.
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In connection with the Premcor Acquisition, a liability of $50 million was accrued as of September 1, 2005 as we believed it was probable that the maximum payments would be made related to the Delaware City Refinery margin contingency. The offsetting amount was recorded in “goodwill.”
Insurance Recoveries
McKee Refinery Fire
On February 16, 2007, our McKee Refinery experienced a fire in its propane deasphalting unit. As of the filing of this annual report, the entire McKee Refinery remains shut down while efforts are underway to determine the cause of the accident, assess damages, and establish a plan for making repairs. Full scale efforts to assess damages, make repairs, and restart the refinery are underway though we do not yet have a firm estimated date for commencement of operations. Although we are in the preliminary stages of assessing the extent of damages, we do not believe that this incident will have a material adverse effect on our results of operations.
24. ENVIRONMENTAL MATTERS
Remediation Liabilities
Liabilities for future remediation costs are recorded when environmental assessments and/or remedial efforts are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Environmental liabilities are based on best estimates of probable undiscounted future costs using currently available technology and applying current regulations, as well as our own internal environmental policies.
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The balance of and changes in the accruals for environmental matters, which are principally included in “other long-term liabilities” described in Note 13, were as follows (in millions):
St. Charles Acquisition
Adjustments to estimates, net
Payments, net of third-party recoveries
The balance of accruals for environmental matters is included in the consolidated balance sheet as follows (in millions):
Accruals for environmental matters
In connection with our various acquisitions, we assumed certain environmental liabilities including, but not limited to, certain remediation obligations, site restoration costs, and certain liabilities relating to soil and groundwater remediation.
We believe that we have adequately provided for our environmental exposures with the accruals referred to above. These liabilities have not been reduced by potential future recoveries from third parties. Environmental liabilities are difficult to assess and estimate due to unknown factors such as the timing and extent of remediation, the determination of our obligation in proportion to other parties, improvements in remediation technologies, and the extent to which environmental laws and regulations may change in the future.
25. LITIGATION MATTERS
As of February 1, 2007, we were named as a defendant in 73 cases alleging liability related to MTBE contamination in groundwater. The plaintiffs are generally water providers, governmental authorities, and private water companies alleging that refiners and marketers of MTBE and gasoline containing MTBE are liable for manufacturing or distributing a defective product. We have been named in these lawsuits together with many other refining industry companies. We are being sued primarily as a refiner and marketer of MTBE and gasoline containing MTBE. We do not own or operate gasoline station facilities in most of the geographic locations in which damage is alleged to have occurred. The lawsuits generally seek individual, unquantified compensatory and punitive damages, injunctive relief, and attorneys’ fees. Two of the cases are pending in state court. Pursuant to a 2006 settlement, the plaintiff’s claims in one of the state court cases were dismissed, but minor cross-claims are still pending against Valero. The second state court case was recently filed, but
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Valero has not been served with the complaint. The remainder of the cases are pending in federal court and are consolidated for pre-trial proceedings in the U.S. District Court for the Southern District of New York (Multi-District Litigation Docket No. 1358, In re: Methyl-Tertiary Butyl Ether Products Liability Litigation). Four of the cases Valero is involved in have been selected by the court as “focus cases” for discovery and pre-trial motions. The Suffolk County Water Authority et al. case is scheduled for trial in January 2008. The United Water New York case may also be tried in 2008. Activity in the “non-focus” cases is generally stayed. We believe that we have strong defenses to these claims and are vigorously defending the cases. We have recorded a loss contingency liability with respect to this matter in accordance with FASB Statement No. 5. However, due to the inherent uncertainty of litigation, we believe that it is reasonably possible (as defined in FASB Statement No. 5) that we may suffer a loss with respect to one or more of the lawsuits in excess of the amount accrued. We believe that such an outcome in any one of these lawsuits would not have a material adverse effect on our results of operations or financial position. However, we believe that an adverse result in all or a substantial number of these cases could have a material effect on our results of operations and financial position. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.
Along with several other defendants in the retail petroleum marketing business, we have been named in eight consumer class actions relating to fuel temperature. The complaints, filed in federal courts in California, Kansas, Kentucky, Missouri, Oklahoma, and Tennessee, allege that because fuel volume increases with fuel temperature, the defendants have violated state consumer protection laws by failing to adjust the volume of fuel when the fuel temperature exceeded 60 degrees Fahrenheit. The complaints seek to certify classes of retail consumers who purchased fuel in Arizona, California, Florida, Kansas, Kentucky, Missouri, New Jersey, North Carolina, Oklahoma, Tennessee, Texas, and Virginia. The complaints seek an order compelling the installation of temperature correction devices as well as associated monetary relief. We anticipate that these lawsuits together with similar suits not involving Valero will be consolidated in a multidistrict litigation case at some point in the future. We believe that we have several strong defenses to these lawsuits and intend to contest them. We have not recorded a loss contingency liability with respect to this matter, but we believe that it is reasonably possible (as defined in FASB Statement No. 5) that we may suffer a loss with respect to one or more of the lawsuits. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.
Rosolowski
Rosolowski v. Clark Refining & Marketing, Inc., et al., Judicial Circuit Court, Cook County, Illinois (Case No. 95-L 014703). We assumed this class action lawsuit in the Premcor Acquisition. The lawsuit, filed October 11, 1995, relates in part to a release to the atmosphere of spent catalyst containing low levels of metals from the now-closed Blue Island, Illinois refinery on October 7, 1994. The case was certified as a class action in 2000 with three classes: (i) Class A: persons purportedly affected by the 1994 catalyst release, but with no permanent health effects; (ii) Class B: persons with medical expenses for dependents purportedly affected by the 1994 release; and (iii) Class C: local residents claiming property damage or loss of use and enjoyment of their property over a period of several years. In November 2005, the jury returned a verdict for the plaintiffs of $80.1 million in compensatory damages and $40 million in punitive damages. In January 2006, we filed motions for new trial, remittitur, and judgment notwithstanding the verdict, citing, among other things, misconduct by plaintiffs’ counsel and improper class certification. On November 3, 2006, the trial judge (i) upheld the jury’s award of $100,000 for Class A and no damages for Class B, (ii) decertified Class C, and (iii) vacated the jury’s award to Class C of $80 million in compensatory damages and $40 million in punitive
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damages. We have recorded a loss contingency liability with respect to this matter in accordance with FASB Statement No. 5. We do not believe that this matter will have a material effect on our financial position or results of operations.
We are also a party to additional claims and legal proceedings arising in the ordinary course of business. We believe that there is only a remote likelihood that future costs related to known contingent liabilities related to these legal proceedings would have a material adverse impact on our consolidated results of operations or financial position.
26. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
In conjunction with the Premcor Acquisition on September 1, 2005, Valero Energy Corporation has fully and unconditionally guaranteed the following debt of The Premcor Refining Group Inc. (PRG), a wholly owned subsidiary of Valero Energy Corporation, that was outstanding as of December 31, 2006:
9.25% senior notes due February 2010,
6.75% senior notes due February 2011,
6.125% senior notes due May 2011,
9.5% senior notes due February 2013,
6.75% senior notes due May 2014, and
7.5% senior notes due June 2015.
In addition, PRG has fully and unconditionally guaranteed all of the outstanding debt issued by Valero Energy Corporation.
The following condensed consolidating financial information is provided for Valero and PRG as an alternative to providing separate financial statements for PRG for the periods subsequent to the Premcor Acquisition. The accounts for all companies reflected herein are presented using the equity method of accounting for investments in subsidiaries.
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Condensed Consolidating Balance Sheet as of December 31, 2006
(in millions)
Valero
EnergyCorporation
Income tax receivable
Investment in Valero Energy affiliates
Long-term notes receivable from affiliates
Long-term debt and capital lease obligations, less current portion
Long-term notes payable to affiliates
Common stock
Treasury stock
Accumulated other comprehensive income (loss)
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Condensed Consolidating Balance Sheet as of December 31, 2005
Preferred stock
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Condensed Consolidating Statement of Income for the Year Ended December 31, 2006
Non-GuarantorSubsidiaries
Equity in earnings of subsidiaries
Income tax expense (1)
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Condensed Consolidating Statement of Income for the Year Ended December 31, 2005
Income (loss) before income tax expense
Income tax expense (benefit) (2)
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Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2006
Energy
Corporation
Net intercompany loans
Investment in Cameron Highway Oil Pipeline Project, net
Return of investment, net
Other investing activities, net
Net cash provided by (used in) investing activities
Long-term note repayments
Benefit from tax deduction in excess of recognized compensation cost
Dividends to parent
Net intercompany borrowings
Other financing activities, net
Net cash used in financing activities
Cash and temporary cash investments at beginning of period
Cash and temporary cash investments at end of period
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Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2005
Return of investment
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27. QUARTERLY RESULTS OF OPERATIONS (Unaudited)
Our results of operations by quarter for the years ended December 31, 2006 and 2005 were as follows (in millions, except per share amounts):
Earnings per common share (b)
Earnings per common share – assuming dilution (b)
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Disclosure Controls and Procedures. Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were operating effectively as of December 31, 2006.
Internal Control over Financial Reporting.
(a) Management’s Report on Internal Control over Financial Reporting.
The management report on Valero’s internal control over financial reporting required by Item 9A appears in Item 8 on page 52 of this report, and is incorporated herein by reference.
(b) Attestation Report of the Independent Registered Public Accounting Firm.
The report of KPMG LLP on our management’s assessment of Valero’s internal control over financial reporting appears in Item 8 beginning on page 54 of this report, and is incorporated herein by reference.
(c) Changes in Internal Control over Financial Reporting.
There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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PART III
ITEMS 10-14.
The information required by Items 10 through 14 of Form 10-K is incorporated herein by reference to the definitive Proxy Statement for our 2007 Annual Meeting of Stockholders which we will file with the SEC before March 31, 2007. Certain information required by Item 401 of Regulation S-K concerning our executive officers appears in Part I of this report.
PART IV
(a) 1. Financial Statements. The following consolidated financial statements of Valero Energy Corporation and its subsidiaries are included in Part II, Item 8 of this Form 10-K:
Management’s report on internal control over financial reporting
Reports of independent registered public accounting firm
Consolidated balance sheets as of December 31, 2006 and 2005
Consolidated statements of income for the years ended December 31, 2006, 2005, and 2004
Consolidated statements of stockholders’ equity for the years ended December 31, 2006, 2005, and 2004
Consolidated statements of cash flows for the years ended December 31, 2006, 2005, and 2004
Consolidated statements of comprehensive income for the years ended December 31, 2006, 2005, and 2004
Notes to consolidated financial statements
2. Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.
3. Exhibits. Filed as part of this Form 10-K are the following exhibits:
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132
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Copies of exhibits filed as a part of this Form 10-K may be obtained by stockholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to Jay D. Browning, Senior Vice President and Corporate Secretary, Valero Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-6000.
Pursuant to paragraph 601(b)(4)(iii)(A) of Regulation S-K, the registrant has omitted from the foregoing listing of exhibits, and hereby agrees to furnish to the SEC upon its request, copies of certain instruments, each relating to long-term debt not exceeding 10% of the total assets of the registrant and its subsidiaries on a consolidated basis.
Disclosures Required by Section 303A.12 of the NYSE Listed Company Manual. Section 303A.12 of the NYSE Listed Company Manual requires the chief executive officer (“CEO”) of each listed company to certify to the NYSE each year that he or she is not aware of any violation by the listed company of any of the NYSE corporate governance listing standards. The CEO of Valero submitted the required certification without qualification to the NYSE on May 3, 2006. In addition, the CEO certification and the chief financial officer’s certification required by Section 302 of the Sarbanes-Oxley Act of 2002 (the “SOX 302 Certifications”) with respect to our disclosures in our Form 10-K for the year ended December 31, 2005 were filed as Exhibit 31.01 to our Form 10-K for the year ended December 31, 2005. The SOX 302 Certifications with respect to our disclosures in our Form 10-K for the year ended December 31, 2006 are being filed as Exhibit 31.01 to this Form 10-K.
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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.
/s/ William R. Klesse
Date: February 26, 2007
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POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints William R. Klesse, Michael S. Ciskowski, and Jay D. Browning, or any of them, each with power to act without the other, his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes may lawfully do or cause to be done by virtue hereof.
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.
Signature
Title
Date
Chief Executive Officer and
Chairman of the Board
(Principal Executive Officer)
(William R. Klesse)
/s/ Michael S. Ciskowski
Executive Vice President
and Chief Financial Officer
(Principal Financial and Accounting Officer)
(Michael S. Ciskowski)
/s/ W.E. Bradford
(W.E. Bradford)
/s/ Ronald K. Calgaard
(Ronald K. Calgaard)
/s/ Jerry D. Choate
(Jerry D. Choate)
/s/ Irl F. Engelhardt
(Irl F. Engelhardt)
/s/ Ruben M. Escobedo
(Ruben M. Escobedo)
/s/ Bob Marbut
(Bob Marbut)
/s/ Donald L. Nickles
(Donald L. Nickles)
/s/ Robert A. Profusek
(Robert A. Profusek)
/s/ Susan Kaufman Purcell
(Susan Kaufman Purcell)
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