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FORM 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                       to
Commission file number 1-13175
VALERO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
     
Delaware
(State or other jurisdiction of
incorporation or organization)
  74-1828067
(I.R.S. Employer
Identification No.)
     
One Valero Way
San Antonio, Texas

(Address of principal executive offices)
  78249
(Zip Code)
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 þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule12b-2 of the Exchange Act).
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ
The aggregate market value of the voting and non-voting common stock held by non-affiliates was approximately $20.4 billion based on the last sales price quoted as of June 30, 2005 on the New York Stock Exchange, the last business day of the registrant’s most recently completed second fiscal quarter.
As of January 31, 2006, 621,838,191 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, 2006 a definitive Proxy Statement for our Annual Meeting of Stockholders scheduled for April 27, 2006, at which our directors will be elected. Portions of the 2006 Proxy Statement are incorporated by reference in Part III of this Form 10-K and are deemed to be a part of this report.
 
 

 


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CROSS-REFERENCE SHEET
The following table indicates the headings in the 2006 Proxy Statement where the information required in Part III of Form 10-K may be found.
     
Form 10-K Item No. and Caption   Heading in 2006 Proxy Statement
10. Directors and Executive Officers of the Registrant
  Information Regarding the Board of Directors, Independent Directors, Audit Committee, Code of Ethics for Senior Financial Officers, Proposal No. 1 Election of Directors, Information Concerning Nominees and Other Directors and Section 16(a) Beneficial Ownership Reporting Compliance
 
   
11. Executive Compensation
  Compensation Committee, Compensation of Directors, Performance Graph, Executive Compensation and Certain Relationships and Related Transactions
 
   
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
  Beneficial Ownership of Valero Securities and Equity Compensation Plan Information
 
   
13. Certain Relationships and Related Transactions
  Certain Relationships and Related Transactions
 
   
14. Principal Accountant Fees and Services
  KPMG LLP Fees for Fiscal Years 2005 and 2004 and Audit Committee Pre-Approval Policy
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, Vice President and Corporate Secretary, Valero Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-6000.
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CONTENTS
         
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Item 11. Executive Compensation
    127  
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
    127  
Item 13. Certain Relationships and Related Transactions
    127  
Item 14. Principal Accountant Fees and Services
    127  
 
       
       
    127  
    133  
 Third Certificate of Amendment to Restated Certificate of Incorporation
 Third Supplemental Indenture
 Fourth Supplemental Indenture
 Guaranty
 Guaranty
 2001 Executive Stock Incentive Plan
 2003 Employee Stock Incentive Plan
 Stock Option Plan, as Amended and Restated
 Statements of Computations of Ratios of Earnings to Fixed Charges
 Subsidiaries
 Consent of KPMG LLP
 Consent of Ernst & Young LLP
 Rule 13a-14(a) Certifications
 Section 1350 Certifications
 Audit Committee Pre-Approval Policy
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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 21 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, 2006, we had 22,068 employees.
We own and operate 18 refineries located in the United States, Canada and Aruba that produce premium, environmentally clean refined products such as reformulated gasoline (RFG), gasoline meeting the specifications of the California Air Resources Board (CARB), CARB diesel fuel, 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 5,000 retail and wholesale branded outlets in the United States, Canada and Aruba.
We are the general partner of Valero L.P., a publicly traded master limited partnership (NYSE: VLI). Our ownership interest in Valero L.P. was 23.4% as of December 31, 2005, which was composed of a 2% general partner interest and a 21.4% limited partner interest. Our investment in and transactions with Valero L.P. are discussed further in Note 9 of Notes to Consolidated Financial Statements.
Available Information. Our internet website address is http://www.valero.com. Information contained on our website is not part of this 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 our board’s committees in the same website location. Our governance documents are available in print to any stockholder that makes a written request to Jay D. Browning, Vice President and Corporate Secretary, Valero Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-0600.

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RECENT DEVELOPMENTS
Stock Split. On September 15, 2005, our board of directors approved a two-for-one split of our common stock. The stock split was effected in the form of a stock dividend which was distributed on December 15, 2005. All share and per share data (except par value) in this Form 10-K have been adjusted to reflect the effect of the stock split for all periods presented.
Premcor Acquisition. On September 1, 2005, we completed the merger of Premcor Inc. with and into Valero Energy Corporation (the Premcor Acquisition). When used in this report, “Premcor” means Premcor Inc. or one or more of its wholly owned subsidiaries at the time of the Premcor Acquisition. 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.
In the merger, we issued 85 million shares of Valero common stock and paid $3.4 billion of cash to Premcor stockholders. We paid the cash portion of the merger consideration from available cash and proceeds from a $1.5 billion bank term loan (which we fully repaid by December 31, 2005). In addition, we assumed Premcor’s existing debt, which had a fair value of $1.9 billion as of September 1, 2005. The Premcor Acquisition and the Premcor debt that we assumed are more fully described in Notes 2 and 12 of Notes to Consolidated Financial Statements in Item 8 of this report. We hereby incorporate by reference those disclosures into this Item.
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 the Northeast System. Our retail operations in the United States are referred to as the U.S. System. The financial information about our segments in Note 21 of Notes to Consolidated Financial Statements is incorporated herein by reference.

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VALERO’S OPERATIONS
REFINING
On December 31, 2005, 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, 2005.
As of December 31, 2005
                 
            Throughput Capacity (a)
Refinery   Location   (barrels per day)
Gulf Coast:
               
Corpus Christi (b)
  Texas     340,000  
Port Arthur
  Texas     295,000  
Aruba
  Aruba     275,000  
St. Charles
  Louisiana     250,000  
Texas City
  Texas     245,000  
Houston
  Texas     130,000  
Three Rivers
  Texas     100,000  
Krotz Springs
  Louisiana     85,000  
 
               
 
            1,720,000  
 
               
 
               
West Coast:
               
Benicia
  California     170,000  
Wilmington
  California     135,000  
 
               
 
            305,000  
 
               
 
               
Mid-Continent:
               
Memphis
  Tennessee     195,000  
McKee
  Texas     170,000  
Lima
  Ohio     160,000  
Ardmore
  Oklahoma     90,000  
 
               
 
            615,000  
 
               
 
               
Northeast:
               
Jean Gaulin
  Quebec, Canada     215,000  
Delaware City
  Delaware     210,000  
Paulsboro
  New Jersey     195,000  
 
               
 
            620,000  
 
               
 
Total
            3,260,000  
 
               
 
(a)   “Throughput capacity” represents processed crude oil, intermediates and other feedstocks. Total crude oil capacity is approximately 2.8 million BPD.
 
(b)   Represents the combined capacities of two refineries – the Corpus Christi East and Corpus Christi West Refineries.
We process a wide slate of feedstocks, including sour crude oils, intermediates and residual fuel oil (resid) which can typically be purchased at a discount to West Texas Intermediate, a benchmark crude oil. In the fourth quarter of 2005, 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 a discount to sweet crude oils.

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In the fourth quarter of 2005, gasolines and blendstocks represented 47% 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 18%.
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, 2005. Total throughput volumes for the Gulf Coast refining region averaged 1,364,000 BPD and 1,586,600 BPD for the twelve months and three months ended December 31, 2005, respectively.
Combined Gulf Coast Region Charges and Yields *
Fiscal 2005 Actual
             
        Percentage
Charges:
           
 
  sour crude oil     53 %
 
  high-acid sweet crude oil     2 %
 
  sweet crude oil     16 %
 
  residual fuel oil     13 %
 
  other feedstocks     6 %
 
  blendstocks     10 %
Yields:
           
 
  gasolines and blendstocks     43 %
 
  distillates     30 %
 
  petrochemicals     4 %
 
  other products (includes vacuum gas oil, no. 6 fuel oil, petroleum coke, asphalt and other)     23 %
 
*   The percentages stated above include the charges and yields of the Port Arthur Refinery from September 1, 2005 (the date of the Premcor Acquisition) through December 31, 2005.
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 is a highly complex refinery that specializes in processing primarily lower-cost sour crude oil and resid into premium products such as RFG and RBOB.1 The East Refinery is also a complex refinery that 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. An eight-bay truck rack services local markets. The refineries distribute refined products using the Colonial, Explorer, Valley and other major pipelines, including pipelines owned by Valero L.P.
 
1   RBOB is a base unfinished reformulated gasoline mixture known as “reformulated gasoline blendstock for oxygenate blending” or “RBOB.”

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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, premium and reformulated gasoline 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.
Aruba Refinery. Our Aruba Refinery is located on the island of Aruba in the Caribbean Sea. It generally processes heavy sour crude oil and produces primarily intermediate feedstocks and finished distillate products. Significant amounts of the refinery’s intermediate feedstock production are 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 a high percentage of 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 typically receives and delivers its feedstocks and products by tanker and barge via deepwater docking facilities along the Texas City Ship Channel and also has access to the Colonial, Explorer and TEPPCO pipelines for distribution of its products.
Houston Refinery. Our Houston Refinery is located on the Houston Ship Channel. It generally processes sour crude oils and low-sulfur resid into conventional gasoline and distillates. The plant also produces roofing-grade asphalt. The refinery typically receives its feedstocks via tanker at deepwater docking facilities along the Houston Ship Channel and primarily 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 generally processes 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 generally processes light sweet crude oils (received primarily 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 Southeast and Northeast.

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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, 2005. Total throughput volumes for the West Coast refining region averaged 311,600 BPD and 318,300 BPD for the twelve months and three months ended December 31, 2005, respectively.
Combined West Coast Region Charges and Yields
Fiscal 2005 Actual
             
        Percentage
Charges:
           
 
  sour crude oil     71 %
 
  other feedstocks     13 %
 
  blendstocks     16 %
Yields:
           
 
  gasolines and blendstocks     65 %
 
  distillates     21 %
 
  other products (includes vacuum gas oil, no. 6 fuel oil, petroleum coke, asphalt and other)     14 %
Benicia Refinery. Our Benicia Refinery is located northeast of San Francisco on the Carquinez Straits of San Francisco Bay. It is a highly complex refinery that processes sour crude oils into a high percentage of 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, 2005. Total throughput volumes for the Mid-Continent refining region averaged 364,500 BPD and 548,500 BPD for the twelve months and three months ended December 31, 2005, respectively.
Combined Mid-Continent Region Charges and Yields *
Fiscal 2005 Actual
             
        Percentage
Charges:
           
 
  sour crude oil     11 %
 
  sweet crude oil     81 %
 
  other feedstocks     1 %
 
  blendstocks     7 %
Yields:
           
 
  gasolines and blendstocks     55 %
 
  distillates     32 %
 
  petrochemicals     3 %
 
  other products (includes vacuum gas oil, no. 6 fuel oil, petroleum coke, asphalt and other)     10 %
 
*   The percentages stated above include the charges and yields of the Memphis and Lima Refineries from September 1, 2005 (the date of the Premcor Acquisition) through December 31, 2005.
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 primarily 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, RFG, low-sulfur diesel, jet fuels and asphalt. The refinery has access to crude oil from Texas, Oklahoma, Kansas and Colorado through Valero L.P.’s pipelines and 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, RFG, 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 primarily processes 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, 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, 2005. Total throughput volumes for the Northeast refining region averaged 447,800 BPD and 570,400 BPD for the twelve months and three months ended December 31, 2005, respectively.
Combined Northeast Region Charges and Yields *
Fiscal 2005 Actual
             
        Percentage
Charges:
           
 
  sour crude oil     39 %
 
  high-acid sweet crude oil     17 %
 
  sweet crude oil     34 %
 
  residual fuel oil     1 %
 
  other feedstocks     2 %
 
  blendstocks     7 %
Yields:
           
 
  gasolines and blendstocks     42 %
 
  distillates     38 %
 
  petrochemicals     1 %
 
  other products (includes vacuum gas oil, no. 6 fuel oil, petroleum coke, asphalt and other)     19 %
 
*   The percentages stated above include the charges and yields of the Delaware City Refinery from September 1, 2005 (the date of the Premcor Acquisition) through December 31, 2005.
Jean Gaulin Refinery. Our Jean Gaulin Refinery is located in Lévis, Canada (near Quebec City). It generally 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 primarily by train to markets in Quebec and New Brunswick, and by tankers and trucks throughout Canada’s Atlantic Provinces.
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, RFG, low-sulfur diesel and home heating oil. Feedstocks and refined products are typically 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 and fuel oil. Feedstocks and refined products are typically transported by tanker and barge via refinery-owned dock facilities along the Delaware River, ExxonMobil’s product distribution system, an onsite truck rack, 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, Ecuador 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 Jean Gaulin 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 in maintaining our 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 2005.
     Wholesale Marketing
We market branded and unbranded transportation fuels on a wholesale basis in about 40 states primarily 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 3,000 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 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), refinery- and chemical-grade propylene and anhydrous ammonia. Aromatic solvents and propylene are sold to customers in the chemical industry for further processing into such products as paints, plastics and adhesives. Ammonia is sold to customers in the agriculture industry to be used as fertilizer.
     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, 2005. Our retail operations are segregated geographically into two groups: the U.S. System and the Northeast System.
     U.S. System
Sales in the U.S. System represent sales of transportation fuels and convenience store merchandise through our company-operated retail sites. For the year ended December 31, 2005, total sales of refined products through the U.S. System’s retail sites averaged approximately 118,000 BPD. In addition to transportation fuels, our company-operated convenience stores sell snacks, candy, beer, fast foods, cigarettes and fountain drinks. On December 31, 2005, we had 1,008 company-operated sites in our U.S. System (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 U.S. System stores are sold primarily under the Valero® brand, with some sites selling under the Diamond Shamrock® brand pending their conversion to the Valero® brand.
     Northeast System
Sales in our Northeast System 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
 
    sales of home heating oil to residential customers.
Our Northeast System 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, 2005, total retail sales of refined products through the Northeast System averaged approximately 76,300 BPD. Transportation fuels are sold under the Ultramar® brand through a network of 987 outlets throughout eastern Canada. On December 31, 2005, we owned or leased 455 retail stores in the Northeast System and distributed gasoline to 532 dealers and independent jobbers. In addition, the Northeast System 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. The Northeast System operations also include a large home heating oil business that provides home heating oil to approximately 161,000 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 2003, 2004 and 2005 were $1.27 per share, $3.27 per share and $6.10 per share, respectively. Refining margins were a significant contributing factor to the increase in our earnings between 2003 and 2005. 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 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 methyl tertiary butyl ether, or “MTBE,” CARB gasoline, the Tier II gasoline and distillate standards and the Maximum Available Control Technology rule under the Clean Air 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 are satisfied through supplies originating in Saudi Arabia, Mexico, Iraq, Kuwait, Venezuela, Ecuador 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.

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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,”
 
    Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Environmental Matters,” and
 
    Item 8 “Financial Statements” in Note 24 of Notes to Consolidated Financial Statements.
Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2005, our capital expenditures attributable to compliance with environmental regulations were approximately $1.1 billion, and are currently estimated to be approximately $1.3 billion for 2006 and approximately $660 million for 2007. The estimates for 2006 and 2007 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.
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, 2005, 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 important to our wholesale and retail marketing operations.

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EXECUTIVE OFFICERS OF THE REGISTRANT
                     
Name   Age*   Positions Held with Valero   Officer Since
William R. Klesse
    59     Chief Executive Officer and Vice-Chairman of the Board     2001  
Gregory C. King
    45     President     1997  
Michael S. Ciskowski
    48     Executive Vice President and Chief Financial Officer     1998  
S. Eugene Edwards
    49     Executive Vice President - Corporate Development and Strategic Planning     1998  
Joseph W. Gorder
    48     Executive Vice President - Marketing and Supply     2003  
Richard J. Marcogliese
    53     Executive Vice President - Operations     2001  
 
*   on February 28, 2006
Mr. Klesse became Chief Executive Officer and Vice-Chairman of the Board on December 31, 2005. He previously served as Executive Vice President and Chief Operating Officer since January 2003. He has served as an Executive Vice President of Valero since the closing of our acquisition of Ultramar Diamond Shamrock Corporation (UDS) on December 31, 2001. He had served as an Executive Vice President of UDS since February 1995, overseeing operations, refining, product supply and logistics. Mr. Klesse is also a director of the general partner of Valero L.P.
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. He was elected Vice President and General Counsel of Valero in 1997. He joined our former parent in 1993. Mr. King is also a director of the general partner of Valero L.P.
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. He was elected Vice President of Valero in 1998. He joined our former parent in 1985.
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. He served as President of Duncan-Smith Company, an investment banking firm in San Antonio, from April 1999 to October 2000.
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 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. Prior to that, he held numerous management positions in engineering and operations with ExxonMobil, including work at its headquarters office in Houston and its Baton Rouge and Bayway refineries.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
     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
 
    Rosolowski
 
    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. Nevertheless, 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.
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 response 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). We are subject to 28 outstanding violation notices (VNs) issued by the BAAQMD since January 2004 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 recently settled 41 air-related VNs issued by the BAAQMD in 2004.
Delaware Department of Natural Resources and Environmental Control (DDNREC) (Delaware City Refinery). The DDNREC has issued several notices of violations to the Delaware City Refinery since Premcor’s acquisition of the refinery in May 2004 alleging excess air emissions and failure to obtain a state construction permit. We have initiated negotiations with DDNREC to resolve all outstanding allegations of noncompliance. No penalty amount is demanded in the NOVs.

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New Jersey Department of Environmental Protection (NJDEP) (Paulsboro Refinery). We are subject to six 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 $139,500. We have appealed these Notices. In the fourth quarter of 2005, we settled the NJDEP’s prior demands for stipulated penalties relating to alleged failures of a stack test required by an Administrative Consent Order entered in May 2000.
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.
People of the State of Illinois, ex rel. v. The Premcor Refining Group Inc., et al., Chancery Division, Circuit Court, Cook County (Case No. 05-CH-07694, filed May 3, 2005) (former Clark retail sites). The Illinois EPA has issued NOVs to Premcor pertaining to reported releases from underground storage tanks at certain retail sites alleging that Premcor was either the operator or landlord/owner at the time of the releases. The Illinois Attorney General’s office on behalf of Illinois EPA is seeking a consent order requiring a penalty and corrective action at 54 retail sites. The State filed its complaint against Premcor in May 2005, and made an initial penalty demand of $1.2 million.
South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). The SCAQMD has issued 24 VNs to our Wilmington Refinery since May 2003 for alleged excess emissions and one permitting discrepancy. No penalties have been assessed for the alleged violations; however, the SCAQMD has made a settlement offer to resolve 17 of the violations (issued through June 2004). We are continuing to negotiate with the SCAQMD to resolve these issues.
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
A special meeting of our stockholders was held December 1, 2005. Stockholders met to consider an amendment to the certificate of incorporation of Valero Energy Corporation to increase the total number of shares of common stock, par value $0.01 per share, that Valero is authorized to issue from 600 million shares to 1.2 billion shares. The proposal passed, and the voting results were as follows:
         
for
    266,480,751  
against
    5,278,329  
abstain
    1,485,369  
broker non-votes
    n/a  

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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the New York Stock Exchange under the symbol “VLO.”
As of January 31, 2006, there were 7,238 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 2005 and 2004. The amounts presented below for the quarters ended on and prior to September 30, 2005 and September 30, 2004 have been adjusted to reflect the effects of two separate two-for-one splits of our common shares, which were effected in the form of common stock dividends distributed on December 15, 2005 and October 7, 2004, respectively.
                         
    Sales Prices of the     Dividends  
    Common Stock     Per  
     Quarter Ended   High     Low     Common Share  
2005:
                       
December 31
  $ 58.15     $ 45.86     $ 0.05  
September 30
    58.63       39.38       0.05  
June 30
    41.13       28.90       0.05  
March 31
    38.58       21.01       0.04  
 
                       
2004:
                       
December 31
  $ 23.91     $ 19.42     $ 0.04  
September 30
    20.30       15.90       0.0375  
June 30
    18.73       13.97       0.0375  
March 31
    15.38       11.43       0.03  
On January 19, 2006, our board of directors declared a regular quarterly cash dividend of $0.06 per common share payable March 15, 2006 to holders of record at the close of business on February 15, 2006.
Dividends are considered quarterly by the board of directors and may be paid only when approved by the board.
Unregistered Sales of Equity Securities
During 2005 and January and February of 2006, 14,961,721 shares of our common stock, together with cash in lieu of fractional shares, were issued upon conversion of 7,548,809 shares of our 2% mandatory convertible preferred stock as discussed in Note 15 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.

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The following table discloses purchases of shares of Valero’s common stock made by us or on our behalf during the fourth quarter of 2005.
                                 
                            Maximum Number (or
                    Total Number of   Approximate Dollar
                    Shares Purchased as   Value) of Shares
    Total Number of           Part of Publicly   that May Yet Be
    Shares Purchased   Average Price Paid   Announced Plans or   Purchased Under the
Period   (1)   per Share   Programs (2)   Plans or Programs
October 2005
    1,000,600     $ 51.82       0     $361 million
November 2005
    1,704,400     $ 50.07       0     $361 million
December 2005
    5,274,200     $ 52.55       0     $361 million
Total (3)
    7,979,200     $ 51.93       0     $361 million
 
(1)   All of the reported shares were purchased in open-market transactions to satisfy our obligations under employee benefit plans and not through any publicly announced stock purchase plan or program.
 
(2)   Our existing stock repurchase program was publicly announced on December 3, 2001. The program authorizes us to purchase up to $400 million aggregate purchase price of shares of Valero common stock. The program has no expiration date.
 
(3)   The total shares purchased during the fourth quarter of 2005 reflected herein include 850,000 shares at a cost of $44 million that were not settled and certificated until January 2006, and therefore are not included in our treasury stock balance at December 31, 2005 or our cash flow statement for the year ended December 31, 2005.

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ITEM 6. SELECTED FINANCIAL DATA
The selected financial data for the five-year period ended December 31, 2005 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:
                                         
    Year Ended December 31,  
    2005 (a)     2004 (b)     2003 (c) (d)     2002 (e)     2001 (f)  
Operating revenues (g)
  $ 82,162     $ 54,619     $ 37,969     $ 29,048     $ 14,988  
Operating income
    5,459       2,979       1,222       471       1,001  
Net income
    3,590       1,804       622       92       564  
Earnings per common share - assuming dilution (h)
    6.10       3.27       1.27       0.21       2.21  
Dividends per common share (h)
    0.19       0.145       0.105       0.10       0.085  
Property, plant and equipment, net
    17,856       10,317       8,195       7,412       7,217  
Goodwill
    4,926       2,401       2,402       2,580       2,211  
Total assets
    32,728       19,392       15,664       14,465       14,400  
Long-term debt and capital lease obligations (less current portions)
    5,156       3,901       4,245       4,494       2,805  
Company-obligated preferred securities of subsidiary trusts
                      373       373  
Stockholders’ equity
    15,050       7,798       5,735       4,308       4,203  
 
(a)   Includes the operations related to the Premcor Acquisition beginning September 1, 2005.
 
(b)   Includes the operations related to the acquisition of the Aruba Refinery and related businesses (Aruba Acquisition) beginning March 5, 2004.
 
(c)   Includes the operations of the St. Charles Refinery beginning July 1, 2003.
 
(d)   On March 18, 2003, our ownership interest in Valero L.P. decreased from 73.6% to 49.5%. As a result of this decrease in ownership of Valero L.P. combined with certain other partnership governance changes, we ceased consolidating Valero L.P. on that date and began using the equity method to account for our investment in the partnership.
 
(e)   Includes the operations related to the acquisition of UDS beginning January 1, 2002.
 
(f)   Includes the operations related to the acquisitions from Huntway Refining Company and El Paso Corporation beginning June 1, 2001. 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 and stockholders’ equity include amounts related to UDS, which was acquired by us on December 31, 2001.
 
(g)   Operating revenues include approximately $7.8 billion, $4.9 billion, $3.9 billion, $3.7 billion and $1.0 billion, respectively, related to crude oil buy/sell arrangements.
 
(h)   Per share amounts originally reported for 2004, 2003, 2002 and 2001 have been adjusted as appropriate to reflect the effects of two separate two-for-one stock splits, which were effected in the form of common stock dividends distributed on December 15, 2005 and October 7, 2004.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
On September 15, 2005, our board of directors approved a two-for-one split of our common stock, the second such split in the last two years, which was distributed in the form of a stock dividend on December 15, 2005 to stockholders of record on December 2, 2005. All previously reported share and per share data (except par value) in this Form 10-K have been adjusted to reflect the effect of this stock split for all periods presented.
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:
    the synergies and accretion to reported earnings estimated to result from the Premcor Acquisition and level of costs and expenses to be incurred by us in connection with the Premcor Acquisition;
 
    various actions to be taken or requirements to be met in connection with integrating Valero and Premcor after the Premcor Acquisition;
 
    our revenue, income and operations after the Premcor Acquisition;
 
    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 discounts, 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 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:

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    expected cost savings from the Premcor Acquisition may not be fully realized or realized within the expected time frame, and costs or expenses relating to the Premcor Acquisition may be higher than expected;
 
    revenues or margins following the Premcor Acquisition may be lower than expected;
 
    costs or difficulties related to the integration of the businesses of Valero and Premcor may be greater than expected;
 
    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;
 
    the actions taken by competitors, including both pricing and the expansion and retirement of refining capacity in response to market conditions;
 
    environmental and other regulations at both the 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;
 
    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;
 
    legislation or regulatory action, including the introduction or enactment of federal, state 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.

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OVERVIEW
As of December 31, 2005, we owned and operated 18 refineries in the United States, Canada and Aruba with a combined throughput capacity, including crude oil and other feedstocks, of approximately 3.3 million barrels per day.
We market refined products through an extensive bulk and rack marketing network and a network of approximately 5,000 retail and wholesale branded outlets in the United States, Canada and Aruba under various brand names including primarily Valeroâ, Diamond Shamrockâ, Shamrockâ, Ultramarâ and Beaconâ. During the second quarter of 2005, we announced our plan to retire the Diamond Shamrock brand and convert those U.S. retail and wholesale sites to the Valero brand. This program is progressing well, with 385 sites having been converted to the Valero brand by the end of 2005 and 894 sites remaining to be rebranded during 2006 and early 2007.
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; 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.
 
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.” Since almost 70% 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 discount.” During 2005, we benefited from even stronger industry fundamentals than the already strong industry fundamentals experienced in 2004. In reporting our results for 2004, we indicated that both refined product margins and sour crude oil discounts were the best we had ever experienced. During 2005, gasoline and distillate margins improved in all four of our refining regions, with overall distillate margins more than double the 2004 margins. In addition, the sour crude oil discount increased more than 30%. This improvement in gasoline and distillate margins combined with the strong sour crude oil discounts contributed to a significant increase in operating results in 2005 compared to the prior year, resulting in earnings per share of $6.10 for 2005, or an 87% increase over the $3.27 earnings per share reported for 2004.
 
On September 1, 2005, we completed our acquisition of Premcor. 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. We benefited from the addition of the four former Premcor refineries, which generated approximately $810 million of operating income during the last four months of 2005.
 
The positive industry fundamentals experienced during the year ended December 31, 2005, combined with the incremental operating income generated from the Premcor Acquisition, resulted in net income for the year ended December 31, 2005 that was approximately double the net income reported for the year ended December 31, 2004. We reported net income of $3.6 billion for 2005, compared to $1.8 billion for 2004. Our debt-to-capitalization ratio (net of cash) decreased approximately 6% during 2005 to 24.8%.

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RESULTS OF OPERATIONS
2005 Compared to 2004
Financial Highlights
(millions of dollars, except per share amounts)
                         
    Year Ended December 31,  
    2005 (a)     2004 (b)     Change  
Operating revenues (c)
  $ 82,162     $ 54,619     $ 27,543  
 
                 
 
                       
Costs and expenses:
                       
Cost of sales (c)
    71,673       47,797       23,876  
Refining operating expenses
    2,926       2,141       785  
Retail selling expenses
    771       705       66  
General and administrative expenses
    458       379       79  
Depreciation and amortization expense:
                       
Refining
    722       518       204  
Retail
    83       58       25  
Corporate
    70       42       28  
 
                 
Total costs and expenses
    76,703       51,640       25,063  
 
                 
 
                       
Operating income
    5,459       2,979       2,480  
Equity in earnings of Valero L.P
    41       39       2  
Other income (expense), net
    53       (48 )     101  
Interest and debt expense:
                       
Incurred
    (334 )     (297 )     (37 )
Capitalized
    68       37       31  
 
                 
 
                       
Income before income tax expense
    5,287       2,710       2,577  
Income tax expense
    1,697       906       791  
 
                 
 
                       
Net income
    3,590       1,804       1,786  
Preferred stock dividends
    13       13        
 
                 
 
                       
Net income applicable to common stock
  $ 3,577     $ 1,791     $ 1,786  
 
                 
 
                       
Earnings per common share – assuming dilution
  $ 6.10     $ 3.27     $ 2.83  
 
See the footnote references on pages 27 and 28.    

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Operating Highlights
(millions of dollars, except per barrel and per gallon amounts)
                         
    Year Ended December 31,  
    2005 (a)     2004 (b)     Change  
Refining:
                       
Operating income
  $ 5,846     $ 3,225     $ 2,621  
Throughput margin per barrel (d)
  $ 11.14     $ 7.44     $ 3.70  
Operating costs per barrel:
                       
Refining operating expenses
  $ 3.22     $ 2.70     $ 0.52  
Depreciation and amortization
    0.80       0.66       0.14  
 
                 
Total operating costs per barrel
  $ 4.02     $ 3.36     $ 0.66  
 
                 
 
                       
Throughput volumes (thousand barrels per day) (e):
                       
Feedstocks:
                       
Heavy sour crude
    548       485       63  
Medium/light sour crude
    610       575       35  
Acidic sweet crude
    103       92       11  
Sweet crude
    670       531       139  
Residuals
    181       136       45  
Other feedstocks
    132       128       4  
 
                 
Total feedstocks
    2,244       1,947       297  
Blendstocks and other
    244       215       29  
 
                 
Total throughput volumes
    2,488       2,162       326  
 
                 
 
                       
Yields (thousand barrels per day):
                       
Gasolines and blendstocks
    1,174       1,034       140  
Distillates
    763       650       113  
Petrochemicals
    72       71       1  
Other products (f)
    481       417       64  
 
                 
Total yields
    2,490       2,172       318  
 
                 
 
                       
Retail – U.S.:
                       
Operating income
  $ 72     $ 87     $ (15 )
Company-operated fuel sites (average)
    1,024       1,106       (82 )
Fuel volumes (gallons per day per site)
    4,830       4,644       186  
Fuel margin per gallon
  $ 0.154     $ 0.142     $ 0.012  
Merchandise sales
  $ 934     $ 925     $ 9  
Merchandise margin (percentage of sales)
    29.7 %     28.4 %     1.3 %
Margin on miscellaneous sales
  $ 126     $ 100     $ 26  
Retail selling expenses
  $ 549     $ 505     $ 44  
Depreciation and amortization expense
  $ 60     $ 37     $ 23  
 
                       
Retail – Northeast:
                       
Operating income
  $ 69     $ 88     $ (19 )
Fuel volumes (thousand gallons per day)
    3,204       3,250       (46 )
Fuel margin per gallon
  $ 0.211     $ 0.211     $  
Merchandise sales
  $ 150     $ 140     $ 10  
Merchandise margin (percentage of sales)
    25.6 %     23.8 %     1.8 %
Margin on miscellaneous sales
  $ 30     $ 24     $ 6  
Retail selling expenses
  $ 222     $ 200     $ 22  
Depreciation and amortization expense
  $ 23     $ 21     $ 2  
 
See the footnote references on pages 27 and 28.    

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Refining Operating Highlights by Region (g)
(millions of dollars, except per barrel amounts)
                         
    Year Ended December 31,  
    2005 (a)     2004 (b)     Change  
Gulf Coast:
                       
Operating income
  $ 3,932     $ 1,976     $ 1,956  
Throughput volumes (thousand barrels per day) (e) (h)
    1,364       1,213       151  
Throughput margin per barrel (d)
  $ 11.73     $ 7.69     $ 4.04  
Operating costs per barrel:
                       
Refining operating expenses
  $ 3.09     $ 2.65     $ 0.44  
Depreciation and amortization
    0.74       0.59       0.15  
 
                 
Total operating costs per barrel
  $ 3.83     $ 3.24     $ 0.59  
 
                 
 
                       
Mid-Continent: (i)
                       
Operating income
  $ 850     $ 229     $ 621  
Throughput volumes (thousand barrels per day) (h)
    364       291       73  
Throughput margin per barrel (d)
  $ 10.44     $ 5.50     $ 4.94  
Operating costs per barrel:
                       
Refining operating expenses
  $ 3.40     $ 2.75     $ 0.65  
Depreciation and amortization
    0.65       0.60       0.05  
 
                 
Total operating costs per barrel
  $ 4.05     $ 3.35     $ 0.70  
 
                 
 
                       
Northeast:
                       
Operating income
  $ 717     $ 502     $ 215  
Throughput volumes (thousand barrels per day) (h)
    448       380       68  
Throughput margin per barrel (d)
  $ 8.33     $ 6.22     $ 2.11  
Operating costs per barrel:
                       
Refining operating expenses
  $ 3.16     $ 2.01     $ 1.15  
Depreciation and amortization
    0.78       0.60       0.18  
 
                 
Total operating costs per barrel
  $ 3.94     $ 2.61     $ 1.33  
 
                 
 
                       
West Coast:
                       
Operating income
  $ 968     $ 518     $ 450  
Throughput volumes (thousand barrels per day)
    312       278       34  
Throughput margin per barrel (d)
  $ 13.42     $ 10.02     $ 3.40  
Operating costs per barrel:
                       
Refining operating expenses
  $ 3.68     $ 3.86     $ (0.18 )
Depreciation and amortization
    1.23       1.06       0.17  
 
                 
Total operating costs per barrel
  $ 4.91     $ 4.92     $ (0.01 )
 
                 
 
                       
Operating income for regions above
  $ 6,467     $ 3,225     $ 3,242  
LIFO charge (a)
    (621 )           (621 )
 
                 
Total refining operating income
  $ 5,846     $ 3,225     $ 2,621  
 
                 
 
See the footnote references on pages 27 and 28.    

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Average Market Reference Prices and Differentials (j)
(dollars per barrel)
                         
    Year Ended December 31,
    2005   2004   Change
Feedstocks:
                       
West Texas Intermediate (WTI) crude oil
  $ 56.44     $ 41.42     $ 15.02  
WTI less sour crude oil at U.S. Gulf Coast (k)
    6.88       5.31       1.57  
WTI less Alaska North Slope (ANS) crude oil
    3.06       2.53       0.53  
WTI less Maya crude oil
    15.58       11.43       4.15  
 
                       
Products:
                       
U.S. Gulf Coast:
                       
Conventional 87 gasoline less WTI
    10.60       7.73       2.87  
No. 2 fuel oil less WTI
    11.57       3.98       7.59  
Propylene less WTI
    10.11       9.80       0.31  
U.S. Mid-Continent:
                       
Conventional 87 gasoline less WTI
    10.39       8.59       1.80  
Low-sulfur diesel less WTI
    15.54       6.95       8.59  
U.S. Northeast:
                       
Conventional 87 gasoline less WTI
    8.95       8.15       0.80  
No. 2 fuel oil less WTI
    11.60       5.44       6.16  
Lube oils less WTI
    33.68       23.83       9.85  
U.S. West Coast:
                       
CARBOB 87 gasoline less ANS
    19.42       19.39       0.03  
Low-sulfur diesel less ANS
    20.69       15.48       5.21  
 
     
The following notes relate to references on pages 24 through 27.
(a)   Includes the operations related to the Premcor Acquisition commencing on September 1, 2005. A $621 million 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 under our LIFO accounting policy was excluded from the consolidated and regional throughput margins per barrel and the regional operating income amounts presented herein in order to make the information presented comparable between periods.
 
(b)   Includes the operations related to the Aruba Acquisition commencing on March 5, 2004.
 
(c)   Operating revenues and cost of sales both include approximately $7.8 billion for the year ended December 31, 2005 and approximately $4.9 billion for the year ended December 31, 2004 related to certain crude oil buy/sell arrangements, which involve linked purchases and sales related to crude oil contracts entered into to address location, quality or grade requirements. For further explanation of this accounting treatment, see the discussion about EITF No. 04-13 in Note 1 of Notes to Consolidated Financial Statements.
 
(d)   Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.
 
(e)   Total throughput volumes and throughput volumes for the Gulf Coast region for the year ended December 31, 2004 are based on 366 days, which results in 183,000 barrels per day being included for the Aruba Refinery for the year ended December 31, 2004. Throughput volumes for the Aruba Refinery for the 302 days of its operations during 2004 averaged 221,000 barrels per day.
 
(f)   Other products primarily include gas oils, No. 6 fuel oil, petroleum coke and asphalt.
 
(g)   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 Refineries; the Northeast refining region includes the Quebec, Paulsboro and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.
 
(h)   Throughput volumes for the Gulf Coast, Mid-Continent and Northeast regions for the year ended December 31, 2005 include 78,000, 106,000 and 63,000 barrels per day, respectively, related to the operations of the refineries acquired from Premcor commencing on September 1, 2005. Throughput volumes for those acquired refineries for the 122 days of their operations subsequent to the acquisition date of September 1, 2005 were 234,000, 317,000, and 187,000 barrels per day, respectively, for the Gulf Coast, Mid-Continent and Northeast regions.
 
(i)   The information presented for the Mid-Continent region includes the operations of the Denver Refinery through May 31, 2005, the date of our sale of this facility to Suncor Energy (U.S.A.) Inc. (Suncor). Throughput volumes for the Mid-Continent region

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    include 15,000 and 37,000 barrels per day related to the Denver Refinery for the years ended December 31, 2005 and 2004, respectively.
 
(j)   The average market reference prices and differentials, with the exception of the propylene and lube oil differentials, are based on posted prices from Platt’s Oilgram. The propylene differential is based on posted propylene prices in Chemical Market Associates, Inc. and the lube oil differential is based on Exxon Mobil Corporation postings provided by Independent Commodity Information Services-London Oil Reports. The average market reference prices and differentials are presented to provide users of the consolidated financial statements with economic indicators that significantly affect our operations and profitability.
 
(k)   The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.
General
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 $34 million decrease in the retail segment and a $107 million increase in general and administrative expenses (including corporate depreciation and amortization expense).
Refining
Operating income for our refining segment increased from $3.2 billion for the year ended December 31, 2004 to $5.8 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 $989 million.
Refining total 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.
 
    Discounts 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, discounts 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.
 
    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

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    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
Retail operating income was $141 million for the year ended December 31, 2005 compared to $175 million for the year ended December 31, 2004, a decrease of 19% between the periods. The decrease was primarily attributable to increased selling expenses in the U.S. and Northeast as higher retail fuel prices resulted in higher credit card processing fees. In addition, Northeast selling expenses increased $15 million due to an increase in the Canadian dollar exchange rate.
Corporate Expenses and Other
General and administrative expenses, including corporate depreciation and amortization expense, increased $107 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. These increases were mainly related to 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.
Interest and debt expense incurred increased from 2004 to 2005 due to interest incurred in 2005 on the debt resulting from the Premcor Acquisition. However, the increased interest incurred was almost entirely offset by increased capitalized interest due to an increase in capital projects, including those 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,

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which included a deduction from income in 2005 for qualified domestic manufacturing activities, as allowed under the American Jobs Creation Act of 2004.
2004 Compared to 2003
Financial Highlights
(millions of dollars, except per share amounts)
                         
    Year Ended December 31,  
    2004 (a)     2003 (b)     Change  
Operating revenues (c)
  $ 54,619     $ 37,969     $ 16,650  
 
                 
 
                       
Costs and expenses:
                       
Cost of sales (c)
    47,797       33,587       14,210  
Refining operating expenses
    2,141       1,656       485  
Retail selling expenses
    705       694       11  
General and administrative expenses
    379       299       80  
Depreciation and amortization expense:
                       
Refining
    518       417       101  
Retail
    58       40       18  
Corporate
    42       54       (12 )
 
                 
Total costs and expenses
    51,640       36,747       14,893  
 
                 
 
                       
Operating income
    2,979       1,222       1,757  
Equity in earnings of Valero L.P. (d)
    39       30       9  
Other income (expense), net
    (48 )     15       (63 )
Interest and debt expense:
                       
Incurred
    (297 )     (287 )     (10 )
Capitalized
    37       26       11  
Minority interest in net income of Valero L.P. (d)
          (2 )     2  
Distributions on preferred securities of subsidiary trusts
          (17 )     17  
 
                 
 
                       
Income before income tax expense
    2,710       987       1,723  
Income tax expense
    906       365       541  
 
                 
 
                       
Net income
    1,804       622       1,182  
Preferred stock dividends
    13       5       8  
 
                 
 
                       
Net income applicable to common stock
  $ 1,791     $ 617     $ 1,174  
 
                 
 
                       
Earnings per common share – assuming dilution
  $ 3.27     $ 1.27     $ 2.00  
 
See the footnote references on pages 33 and 34.    

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Operating Highlights
(millions of dollars, except per barrel and per gallon amounts)
                         
    Year Ended December 31,  
    2004 (a)     2003 (b)     Change  
Refining:
                       
Operating income
  $ 3,225     $ 1,363     $ 1,862  
Throughput margin per barrel (e)
  $ 7.44     $ 5.13     $ 2.31  
Operating costs per barrel:
                       
Refining operating expenses
  $ 2.70     $ 2.47     $ 0.23  
Depreciation and amortization
    0.66       0.63       0.03  
 
                 
Total operating costs per barrel
  $ 3.36     $ 3.10     $ 0.26  
 
                 
 
                       
Throughput volumes (thousand barrels per day) (f):
                       
Feedstocks:
                       
Heavy sour crude
    485       199       286  
Medium/light sour crude
    575       595       (20 )
Acidic sweet crude
    92       94       (2 )
Sweet crude
    531       562       (31 )
Residuals
    136       79       57  
Other feedstocks
    128       166       (38 )
 
                 
Total feedstocks
    1,947       1,695       252  
Blendstocks and other
    215       140       75  
 
                 
Total throughput volumes
    2,162       1,835       327  
 
                 
 
                       
Yields (thousand barrels per day):
                       
Gasolines and blendstocks
    1,034       975       59  
Distillates
    650       536       114  
Petrochemicals
    71       61       10  
Other products (g)
    417       270       147  
 
                 
Total yields
    2,172       1,842       330  
 
                 
 
                       
Retail – U.S.:
                       
Operating income
  $ 87     $ 115     $ (28 )
Company-operated fuel sites (average)
    1,106       1,201       (95 )
Fuel volumes (gallons per day per site)
    4,644       4,512       132  
Fuel margin per gallon
  $ 0.142     $ 0.148     $ (0.006 )
Merchandise sales
  $ 925     $ 939     $ (14 )
Merchandise margin (percentage of sales)
    28.4 %     28.1 %     0.3 %
Margin on miscellaneous sales
  $ 100     $ 90     $ 10  
Retail selling expenses
  $ 505     $ 508     $ (3 )
Depreciation and amortization expense
  $ 37     $ 23     $ 14  
 
                       
Retail – Northeast:
                       
Operating income
  $ 88     $ 97     $ (9 )
Fuel volumes (thousand gallons per day)
    3,250       3,328       (78 )
Fuel margin per gallon
  $ 0.211     $ 0.209     $ 0.002  
Merchandise sales
  $ 140     $ 122     $ 18  
Merchandise margin (percentage of sales)
    23.8 %     22.9 %     0.9 %
Margin on miscellaneous sales
  $ 24     $ 19     $ 5  
Retail selling expenses
  $ 200     $ 186     $ 14  
Depreciation and amortization expense
  $ 21     $ 17     $ 4  
 
See the footnote references on pages 33 and 34.    

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Refining Operating Highlights by Region (h)
(millions of dollars, except per barrel amounts)
                         
    Year Ended December 31,  
    2004 (a)     2003 (b)     Change  
Gulf Coast:
                       
Operating income
  $ 1,976     $ 426     $ 1,550  
Throughput volumes (thousand barrels per day) (f)
    1,213       867       346  
Throughput margin per barrel (e)
  $ 7.69     $ 4.62     $ 3.07  
Operating costs per barrel:
                       
Refining operating expenses
  $ 2.65     $ 2.64     $ 0.01  
Depreciation and amortization
    0.59       0.63       (0.04 )
 
                 
Total operating costs per barrel
  $ 3.24     $ 3.27     $ (0.03 )
 
                 
 
                       
Mid-Continent:
                       
Operating income
  $ 229     $ 185     $ 44  
Throughput volumes (thousand barrels per day)
    291       276       15  
Throughput margin per barrel (e)
  $ 5.50     $ 4.70     $ 0.80  
Operating costs per barrel:
                       
Refining operating expenses
  $ 2.75     $ 2.35     $ 0.40  
Depreciation and amortization
    0.60       0.52       0.08  
 
                 
Total operating costs per barrel
  $ 3.35     $ 2.87     $ 0.48  
 
                 
 
                       
Northeast:
                       
Operating income
  $ 502     $ 418     $ 84  
Throughput volumes (thousand barrels per day)
    380       375       5  
Throughput margin per barrel (e)
  $ 6.22     $ 5.17     $ 1.05  
Operating costs per barrel:
                       
Refining operating expenses
  $ 2.01     $ 1.60     $ 0.41  
Depreciation and amortization
    0.60       0.51       0.09  
 
                 
Total operating costs per barrel
  $ 2.61     $ 2.11     $ 0.50  
 
                 
 
                       
West Coast:
                       
Operating income
  $ 518     $ 334     $ 184  
Throughput volumes (thousand barrels per day)
    278       317       (39 )
Throughput margin per barrel (e)
  $ 10.02     $ 6.86     $ 3.16  
Operating costs per barrel:
                       
Refining operating expenses
  $ 3.86     $ 3.14     $ 0.72  
Depreciation and amortization
    1.06       0.83       0.23  
 
                 
Total operating costs per barrel
  $ 4.92     $ 3.97     $ 0.95  
 
                 
 
See the footnote references on pages 33 and 34.    

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Average Market Reference Prices and Differentials (i)
(dollars per barrel)
                         
    Year Ended December 31,  
    2004     2003     Change  
Feedstocks:
                       
WTI crude oil
  $ 41.42     $ 31.11     $ 10.31  
WTI less sour crude oil at U.S. Gulf Coast (j)
    5.31       3.39       1.92  
WTI less ANS crude oil
    2.53       1.47       1.06  
WTI less Maya crude oil
    11.43       6.87       4.56  
 
                       
Products:
                       
U.S. Gulf Coast:
                       
Conventional 87 gasoline less WTI
    7.73       5.50       2.23  
No. 2 fuel oil less WTI
    3.98       2.76       1.22  
Propylene less WTI
    9.80       1.17       8.63  
U.S. Mid-Continent:
                       
Conventional 87 gasoline less WTI
    8.59       7.44       1.15  
Low-sulfur diesel less WTI
    6.95       5.16       1.79  
U.S. Northeast:
                       
Conventional 87 gasoline less WTI
    8.15       5.95       2.20  
No. 2 fuel oil less WTI
    5.44       4.50       0.94  
Lube oils less WTI
    23.83       24.80       (0.97 )
U.S. West Coast:
                       
CARBOB 87 gasoline less ANS
    19.39       14.46       4.93  
Low-sulfur diesel less ANS
    15.48       7.42       8.06  
 
     
The following notes relate to references on pages 30 through 33.
(a)   Includes the operations related to the Aruba Acquisition commencing on March 5, 2004.
 
(b)   Includes the operations of the St. Charles Refinery commencing on July 1, 2003.
 
(c)   Operating revenues and cost of sales both include approximately $4.9 billion for the year ended December 31, 2004 and approximately $3.9 billion for the year ended December 31, 2003 related to crude oil buy/sell arrangements, which involve linked purchases and sales related to crude oil contracts entered into to address location, quality or grade requirements. For further explanation of this accounting treatment, see the discussion about EITF No. 04-13 in Note 1 of Notes to Consolidated Financial Statements.
 
(d)   On March 18, 2003, our ownership interest in Valero L.P. decreased from 73.6% to 49.5%. As a result of this decrease in ownership of Valero L.P. combined with certain other partnership governance changes, we ceased consolidating Valero L.P. as of that date and began using the equity method to account for our investment in the partnership.
 
(e)   Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.
 
(f)   Total throughput volumes and throughput volumes for the Gulf Coast region for the years ended December 31, 2004 and 2003 are based on 366 days and 365 days, respectively, which results in 183,000 barrels per day and 99,000 barrels per day being included for the Aruba Refinery in 2004 and the St. Charles Refinery in 2003, respectively. Throughput volumes for the Aruba Refinery for the 302 days of its operations during 2004 averaged 221,000 barrels per day. Throughput volumes for the St. Charles Refinery for the 184 days of its operations during 2003 averaged 197,000 barrels per day.
 
(g)   Other products primarily include gas oils, No. 6 fuel oil, petroleum coke and asphalt.
 
(h)   The Gulf Coast refining region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, Krotz Springs, St. Charles and Aruba Refineries; the Mid-Continent refining region includes the McKee, Ardmore and Denver Refineries; the Northeast refining region includes the Quebec and Paulsboro Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.
 
(i)   The average market reference prices and differentials, with the exception of the propylene and lube oil differentials, are based on posted prices from Platt’s Oilgram. The propylene differential is based on posted propylene prices in Chemical Market Associates, Inc. and the lube oil differential is based on Exxon Mobil Corporation postings provided by Independent Commodity Information Services-London Oil Reports. The CARBOB 87 gasoline differential for 2003 represents CARB 87 gasoline, which includes MTBE as a blending component, for the periods prior to October 31, 2003. Prices for products meeting these specifications ceased to be available after October 31, 2003. The average market reference prices and differentials are presented

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    to provide users of the consolidated financial statements with economic indicators that significantly affect our operations and profitability.
 
(j)   The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.
General
Operating revenues increased 44% from the year ended December 31, 2003 to the year ended December 31, 2004 primarily as a result of higher refined product prices combined with additional throughput volumes from refinery operations. The increases in operating income from $1.2 billion for 2003 to $3.0 billion for 2004 and net income from $622 million for 2003 to $1.8 billion for 2004 were attributable primarily to improved fundamentals for our refining segment as discussed below.
Refining
Operating income for our refining segment was $3.2 billion for the year ended December 31, 2004, an increase of $1.9 billion from the year ended December 31, 2003. The increase in refining segment operating income resulted primarily from a 45% increase in refining throughput margin per barrel and an 18% increase in refining throughput volumes, partially offset by a $586 million increase in refining operating expenses (including depreciation and amortization expense).
Refining total throughput margin for 2004 increased due to the following factors:
    Discounts on our sour crude oil feedstocks improved during 2004 compared to 2003 due to ample supplies of sour crude oils and heavy sour residual fuel oils on the world market. In addition, discounts 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 refineries to lower the sulfur content of the gasoline they produce, (ii) high gasoline margins, which increased the demand for sweet versus sour crude oil due to the higher gasoline content of sweet crude oil, and (iii) a global increase in refined product demand, particularly in Asia, which has resulted in more gasoline production by less complex foreign refineries that require sweet crude oil as feedstock.
 
    Gasoline margins increased in all of our refining regions during 2004 compared to 2003 due mainly to strong demand. Gasoline demand was up in 2004 primarily due to strong U.S. and global economic activity.
 
    Distillate margins also increased in all of our refining regions in 2004 compared to 2003 due mainly to increased foreign and U.S. demand resulting from improved economies.
 
    Petrochemical feedstock margins improved significantly in 2004 compared to 2003 due to increased demand for such feedstocks resulting from a stronger worldwide economy.
 
    Our throughput volumes increased 327,000 barrels per day in 2004 compared to 2003 due mainly to incremental throughput of 117,000 barrels per day at the St. Charles Refinery, which was acquired in July 2003, and 183,000 barrels per day of throughput at the Aruba Refinery during the partial period commencing on its acquisition date of March 5, 2004.
The above increases in throughput margin for 2004 were partially offset by the effects of:
    lower margins on products such as asphalt, No. 6 fuel oil, sulfur and petroleum coke due to an increase in the price of crude oil in 2004 compared to 2003,
 
    an approximate $20 million reduction resulting from our ceasing consolidation of Valero L.P. commencing in March 2003,
 
    a higher level of turnaround activity in 2004 compared to 2003, and
 
    approximately $230 million of pre-tax losses in 2004 on hedges related to forward sales of distillates and associated forward purchases of crude oil.

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Refining operating expenses, excluding depreciation and amortization expense, were 29% higher for the year ended December 31, 2004 compared to the year ended December 31, 2003 due primarily to the acquisitions of the St. Charles Refinery in July 2003 and the Aruba Refinery in March 2004, higher energy costs (primarily related to an increase in natural gas prices), increased maintenance expense, an increase in employee compensation and benefits expense including increased variable and incentive compensation, and increases in insurance expense, injected catalyst, professional fees and regulatory costs. Although total refining operating expenses increased 29% from 2003 to 2004, this increase was 9% on a per-barrel basis. The lower percentage increase on a per-barrel basis was due to the throughput increases that resulted from the St. Charles and Aruba Acquisitions. Refining depreciation and amortization expense increased 24% from the year ended December 31, 2003 to the year ended December 31, 2004 due mainly to the implementation of new capital projects, the acquisitions of the St. Charles and Aruba Refineries and increased turnaround and catalyst amortization.
Retail
Retail operating income was $175 million for the year ended December 31, 2004, a decrease of $37 million from the year ended December 31, 2003. Retail fuel margins in the United States decreased due to a rise in crude oil prices during 2004 which could not be fully passed through to the consumer, and fuel sales declined in the United States due to fewer stores. Retail depreciation and amortization expense was higher in 2004 due mainly to gains recognized in 2003 on the disposition of certain home heating oil businesses and service stations. In the Northeast, operating income declined due mainly to an increase in selling expenses resulting primarily from a significant increase in the Canadian dollar exchange rate from 2003 to 2004.
Corporate Expenses and Other
General and administrative expenses, including corporate depreciation and amortization expense, increased $68 million for the year ended December 31, 2004 compared to the year ended December 31, 2003. Employee compensation and benefits increased approximately $41 million from 2003 to 2004, including the recognition of increased variable and incentive compensation expense of approximately $21 million as a result of improved financial performance between the respective years. The remainder of the increase was attributable primarily to costs related to legal and regulatory matters and increased charitable contributions.
Equity in earnings of Valero L.P. represents our equity interest in the earnings of Valero L.P. after March 18, 2003. On March 18, 2003, our ownership interest in Valero L.P. decreased from 73.6% to 49.5%. As a result of this decrease in ownership of Valero L.P. combined with certain other partnership governance changes, we ceased consolidating Valero L.P. as of that date and began using the equity method to account for our investment in Valero L.P. The minority interest in net income of Valero L.P. represented the minority unitholders’ share of the net income of Valero L.P. during the periods that we consolidated such operations.
“Other income (expense), net” for the year ended December 31, 2004 includes an impairment charge of $57 million to write off the carrying amount of our equity investment in Clear Lake Methanol Partners, L.P., as further described in Note 10 of Notes to Consolidated Financial Statements. Excluding the effect of this impairment charge, other income declined $6 million due primarily to the nonrecurrence of a $17 million gain recognized in 2003 related to the sale of certain notes received as partial consideration for the 2002 sale of the Golden Eagle Business (described further in Note 10 of Notes to Consolidated Financial Statements), partially offset by a $10 million increase in equity income in 2004 from the Javelina joint venture due to higher natural gas liquids prices.

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Distributions on preferred securities of subsidiary trusts ceased during 2003 due to the redemption of the 8.32% Trust Originated Preferred Securities (TOPrS) in June 2003 and the settlement of the Premium Equity Participating Security Units (PEPS Units) in August 2003.
Income tax expense increased $541 million from 2003 to 2004 mainly as a result of a 175% increase in income before income tax expense. Our effective tax rate for the year ended December 31, 2004, however, decreased from the year ended December 31, 2003 due mainly to income contributed by the Aruba Refinery in 2004, the operations of which are non-taxable in Aruba through December 31, 2010.
OUTLOOK
In January 2006, we saw a continuation of the positive refining industry fundamentals that we experienced in 2005. Refined product margins for January 2006 were well above historical five-year averages. For example, the Gulf Coast gasoline margin for January 2006 was $6.66 per barrel compared to the historical January average for the last five years of $5.18 per barrel, while the Gulf Coast distillate margin was $7.84 per barrel, $3.23 per barrel above the historical January average for the last five years of $4.61 per barrel. Despite a drop in refined product margins in February due primarily to an unusually warm winter and record imports of winter-grade gasolines, we expect these strong fundamentals to remain in place throughout 2006.
Our outlook for gasoline margins is positive as we expect demand for gasoline during 2006 to remain strong due to continuing strong economic activity in the United States and abroad. We expect that the supply required to satisfy the high demand will be tight for several reasons. First, gasoline inventories in early 2006 on a days-of-supply basis have been low for this time of year. Second, a very high level of turnaround activity is projected for the first half of 2006 for the U.S. refining industry, which should reduce gasoline production. Third, the industry’s typical switch to summer-grade gasoline in early March will be complicated this year by the lower sulfur-content specifications that have taken effect. Fourth, the effective elimination by Congress of MTBE in the gasoline pool by early in the second quarter of 2006 is expected to result in a loss of gasoline production that will have to be made up through increased imports or the blending of higher-cost blendstocks, either of which will require higher margins to attract the necessary supply. And finally, a limited amount of new refining capacity in the U.S. is expected to come on-line in 2006.
The outlook for low-sulfur distillate margins is also favorable. Inventories of on-road diesel on a days-of-supply basis are near historical five-year lows. We expect that supplies of on-road diesel will remain tight throughout 2006 as demand is expected to exceed production capacity, particularly in light of the EPA’s tightening diesel fuel specifications that take effect on June 1, 2006.
Sour crude oil discounts are also expected to remain wide for the foreseeable future. The combination of high refined product margins and the new low-sulfur specifications for refined products has resulted in increased demand for sweet crude oil versus sour crude oil due to its higher yield of light products and lower sulfur content. Higher utilization rates globally by certain less complex refineries have also resulted in the production of more residual fuel oil. The increased supply of resid supports wider discounts for heavy sour crude oil since complex refiners can substitute resid for a portion of their heavy sour crude oil purchases if resid becomes more economic to process than crude oil.
Overall, we believe that we are well-positioned to capitalize on the expected continuing positive industry fundamentals and our resulting favorable outlook for refined product margins and sour crude oil discounts during 2006.

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LIQUIDITY AND CAPITAL RESOURCES
Cash Flows for the Year Ended December 31, 2005
Net cash provided by operating activities for the year ended December 31, 2005 was $5.8 billion compared to $3.0 billion for the year ended December 31, 2004, an increase of $2.8 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 17 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 $1.5 billion of proceeds from debt borrowings, $428 million of available cash on hand, $227 million of proceeds from the issuance of common stock related to our benefit plans, $78 million of proceeds from the sale of our investment in the Javelina joint venture and $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 debt repayments of $2.4 billion;
 
    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 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.

Cash Flows for the Year Ended December 31, 2004
Net cash provided by operating activities for the year ended December 31, 2004 was $3.0 billion compared to $1.8 billion for the year ended December 31, 2003, an increase of $1.2 billion. The increase in cash provided by operating activities from 2003 to 2004 was due primarily to the significant increase in operating income in 2004 as described above under “Results of Operations,” partially offset by a $226 million decrease in the amount of favorable working capital changes between the years. As reflected in Note 17 of Notes to Consolidated Financial Statements, for the year ended December 31, 2004, working capital requirements decreased by $203 million compared to a $429 million decrease for the year ended December 31, 2003. The decrease for 2004 was largely due to a significant increase in current income tax liabilities, while 2003 benefited primarily from a $350 million increase in the amount of receivables sold under our accounts receivable sales program.
In addition to the $3.0 billion of net cash provided by operating activities, we generated cash from various other sources during 2004, including proceeds of $406 million from the sale of common stock, $135 million of proceeds from the issuance of common stock related to our benefit plans, $108 million of proceeds from dispositions of property, plant and equipment, and $64 million of net borrowings (borrowings net of debt repayments). We used these proceeds to:
    fund $1.6 billion of capital expenditures and deferred turnaround and catalyst costs;
 
    exercise options under structured lease arrangements to purchase $567 million of leased property;
 
    fund the Aruba Acquisition for $541 million, net of cash acquired;

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    purchase 19 million shares of treasury stock at a cost of $318 million;
 
    fund contingent payments in connection with prior acquisitions of $53 million;
 
    invest $36 million in the Cameron Highway Oil Pipeline Project (described further in Note 10 of Notes to Consolidated Financial Statements);
 
    pay common and preferred stock dividends of $79 million; and
 
    increase our cash balance by $495 million.
Capital Investments
On September 1, 2005, we completed our merger with Premcor. We paid the $3.4 billion 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 of Notes to Consolidated Financial Statements 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 the year ended December 31, 2005, we incurred $2.1 billion for capital expenditures and $441 million for deferred turnaround and catalyst costs. Capital expenditures for the year ended December 31, 2005 included approximately $1.1 billion of costs related to environmental projects. In addition, $85 million of contingent earn-out payments were made, $62 million was expended for minor acquisitions, $29 million was contributed to Valero L.P. in conjunction with its acquisition of Kaneb Pipe Line Partners, L.P. (Kaneb Partners) and Kaneb Services LLC (together, the Kaneb Acquisition) to maintain our 2% general partner interest in Valero L.P., and $20 million was expended on the conversion of U.S. retail and wholesale sites from the Diamond Shamrock brand to the Valero brand (with approximately $45 million of additional spending anticipated during 2006 and early 2007 on this program).
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 an earn-out contingency agreement related to Premcor’s acquisition of the Delaware City Refinery from Motiva Enterprises LLC (Motiva). Under this agreement, Motiva is 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. Any payments due under all of these earn-out arrangements are limited based on annual and aggregate limits. During 2005, we made earn-out payments of $50 million related to the acquisition of the St. Charles Refinery and $35 million related to the Basis Petroleum Acquisition. In January 2006, we made an earn-out payment of $50 million related to the St. Charles Acquisition. Based on estimated margin levels through April 2006, earn-out payments of $26 million (maximum remaining payment based on the aggregate limitation under the agreement) related to the Basis Petroleum Acquisition and $25 million related to the acquisition of the Delaware City Refinery would be due in the second quarter of 2006.
For 2006, we expect to incur approximately $3.4 billion for capital investments, including approximately $3.0 billion for capital expenditures (approximately $1.3 billion 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.

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Contractual Obligations
Our contractual obligations as of December 31, 2005 are summarized below (in millions).
                                                         
    Payments Due by Period        
    2006     2007     2008     2009     2010     Thereafter     Total  
Long-term debt
  $ 220     $ 287     $ 6     $ 209     $ 208     $ 4,392     $ 5,322  
Capital lease obligations
    6       7       6       7       6       39       71  
Operating lease obligations
    320       285       226       160       96       443       1,530  
Purchase obligations
    17,304       6,258       5,735       1,489       303       2,555       33,644  
 
                                         
Total
  $ 17,850     $ 6,837     $ 5,973     $ 1,865     $ 613     $ 7,429     $ 40,567  
 
                                         
Long-Term Debt
Payments for long-term debt are at stated values.
In conjunction with the Premcor Acquisition, we assumed debt with a fair value of $1.9 billion and $14 million of capital lease obligations. In August 2005, we entered into a $1.5 billion term bank loan to finance a portion of the cash consideration for the Premcor Acquisition, which was fully repaid by December 31, 2005.
During January 2005, we repurchased $40 million of our 7.375% notes due in March 2006 and $42 million of our 6.125% notes due in April 2007 at a premium of $4 million. In addition, during 2005, we made scheduled debt repayments of $410 million related to various notes as discussed in Note 12 of Notes to Consolidated Financial Statements. During September 2005, we repurchased $190 million of the 7.75% senior subordinated notes assumed in the Premcor Acquisition. We also repurchased the 12.5% senior notes assumed in the Premcor Acquisition for $182 million in October 2005 and the Ohio Water Development Authority Environmental Facilities Revenue Bonds for $10 million in November 2005.
As of December 31, 2005, “current portion of long-term debt and capital lease obligations” included mainly $220 million of notes which become due in the first quarter of 2006.
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. Following the completion of the Premcor Acquisition, Standard & Poor’s Ratings Services affirmed its rating of our senior unsecured debt of BBB minus and recently changed our outlook from negative to stable while Moody’s Investors Service affirmed our senior unsecured debt rating of Baa3 with a stable outlook. In February 2006, Fitch Ratings upgraded its rating of our senior unsecured debt to BBB with a stable outlook.
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

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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, 2005, our short-term and long-term purchase obligations increased by approximately $19.1 billion from the amount reported as of December 31, 2004. The increase is primarily attributable to purchase obligations arising from the Premcor Acquisition totaling approximately $13.0 billion and an increase in obligations under crude oil supply contracts resulting from significantly higher crude oil prices as of December 31, 2005 and new contracts in 2005. 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.
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, 2005. However, certain expected payments related to our anticipated pension contribution in 2006 and our other postretirement benefit obligations are discussed in Note 22 of Notes to Consolidated Financial Statements.
Other Commercial Commitments
As of December 31, 2005, our committed lines of credit were as follows:
                 
    Borrowing      
    Capacity   Expiration
5-year revolving credit facility
  $2.5 billion   August 2010
Canadian revolving credit facility
  Cdn. $115 million   December 2010
As of December 31, 2005, we had $232 million of letters of credit outstanding under uncommitted short-term bank credit facilities, Cdn. $8 million of letters of credit outstanding under our Canadian committed revolving credit facility and $254 million of letters of credit outstanding under our 5-year committed revolving credit facility. All of these letters of credit expire during 2006.
Under our revolving bank credit facility’s definitions, our debt-to-capitalization ratio (net of cash) was 24.8% as of December 31, 2005 compared to 30.7% as of December 31, 2004.
Equity
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.
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 2005, we expended $571 million for the purchase of 13 million shares of our common stock under these programs. Through February 24, 2006, we have purchased in the open market an additional

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3.7 million common shares at a cost of $199 million. No shares were purchased during 2005 or through February 24, 2006 under our $400 million stock repurchase program that was publicly announced on December 3, 2001.
Pension Plan Funded Status
During 2005, we contributed $61 million to our qualified pension plans. Based on a 5.5% discount rate and fair values of plan assets as of December 31, 2005, the fair value of the assets in our qualified pension plans were equal to approximately 76% of the projected benefit obligation under those plans as of the end of 2005. However, the qualified pension plans were more than 90% funded based on their “current liability,” which is a funding measure defined under applicable pension regulations.
Although our expected minimum required contribution to our qualified pension plans during 2006 is less than $5 million under the Employee Retirement Income Security Act, we expect to contribute approximately $65 million to our qualified pension plans during 2006, including the former Premcor qualified pension plans discussed below. During January 2006, we contributed $15 million to our qualified pension plans.
In connection with the Premcor Acquisition, we became the plan sponsor for two additional qualified pension plans. Prior to September 1, 2005, Premcor had contributed $20 million to these plans during 2005; we made no further contributions to these plans in 2005.
Environmental Matters
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 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 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.
Other
During the third quarter of 2005, certain of our refineries experienced business interruption losses associated with Hurricanes Katrina and Rita. As a result of these losses, we have submitted claims to our insurance carriers under our insurance policies. No amounts related to these potential business interruption insurance recoveries were accrued in our consolidated financial statements as of and for the year ended December 31, 2005.
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. Under an existing shelf registration statement that was declared effective by the SEC in August 2004, we have $3.5 billion of securities registered for potential future issuance. However, there can be no assurances

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regarding the availability of any future financings or whether such financings can be made available on terms that are acceptable to us.
As of June 30, 2005, we owned 45.5% of the outstanding units (including the 2% general partner interest) of Valero L.P., a limited partnership that owns and operates crude oil and refined product pipeline, terminalling and storage tank assets. On July 1, 2005, our ownership interest decreased to 23.4% as a result of the completion of the Kaneb Acquisition by Valero L.P. Historically, Valero L.P. has issued common units to the public which have resulted in increases in our proportionate share of Valero L.P.’s capital because the issuance price per unit exceeded our carrying amount per unit at the time of issuance. These increases in our investment in Valero L.P., however, have not been recognized in our consolidated financial statements through December 31, 2005 and we are not permitted to do so until Valero L.P.’s subordinated units that we own convert to common units, which is expected to occur in the second quarter of 2006. See Note 9 of Notes to Consolidated Financial Statements for a discussion of the amounts that will be recognized, either in income or directly as a credit to equity, upon the conversion of the subordinated units to common units. Subsequent to the conversion of the subordinated units, any credits or charges generated upon the issuance of new units to the public by Valero L.P. will be recognized immediately by us, either in income or directly in equity, depending on the accounting policy we adopt.
OFF-BALANCE SHEET ARRANGEMENTS
Accounts Receivable Sales Facility
As of December 31, 2005, 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, 2005, 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, 2005, 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, or is not 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 which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s 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 and an impairment charge of $26 million in 2003 related to our former headquarters buildings as discussed in Note 6 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

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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 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, 2005, 2004 and 2003 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 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, 2005 and net periodic benefit cost for the year ending December 31, 2006 (in millions):
                 
            Other
    Pension   Postretirement
    Benefits   Benefits
Increase in benefit obligation resulting from:
               
Discount rate decrease
  $ 54     $ 16  
Compensation rate increase
    21        
Health care cost trend rate increase
          9  
 
               
Increase in expense resulting from:
               
Discount rate decrease
    9       1  
Expected return on plan assets decrease
    1        
Compensation rate increase
    5        
Health care cost trend rate increase
          1  

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our 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 $3.8 billion and $2.1 billion as of December 31, 2005 and 2004, respectively, and the fair value of such inventories was $7.1 billion and $3.3 billion as of December 31, 2005 and 2004, respectively. We also from time to time 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 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 use derivative commodity instruments that we mark to market for trading purposes based on our fundamental and technical analysis of market conditions. 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.
The following tables provide information about our derivative commodity instruments as of December 31, 2005 and 2004 (dollars in millions, except for the weighted-average pay and receive prices as described below), including:
    fair value hedges held to hedge refining inventories and unrecognized firm commitments,
 
    cash flow hedges held to hedge forecasted feedstock and product purchases, refined product sales and natural gas purchases,
 
    economic hedges held to:
    manage price volatility in refinery feedstock and refined product inventories, and
 
    manage price volatility in forecasted feedstock and product purchases, refined product sales and natural gas purchases, and
    trading activities held or issued for trading purposes.
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 fair value for futures, swaps and options represents the fair value of the derivative contract. The 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 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.

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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.
                                                 
    December 31, 2005
            Wtd Avg   Wtd Avg           Pre-tax
    Contract   Pay   Receive   Contract   Market   Fair
    Volumes   Price   Price   Value   Value   Value
Fair Value Hedges:
                                               
Futures – long:
                                               
2006 (crude oil and refined products)
    50,912     $ 59.03       N/A     $ 3,005     $ 3,113     $ 108  
Futures – short:
                                               
2006 (crude oil and refined products)
    64,422       N/A     $ 59.87       3,857       3,958       (101 )
 
                                               
Cash Flow Hedges:
                                               
Futures – long:
                                               
2006 (crude oil and refined products)
    18,179       62.24       N/A       1,131       1,152       21  
Futures – short:
                                               
2006 (crude oil and refined products)
    13,690       N/A       60.51       828       849       (21 )
 
                                               
Economic Hedges:
                                               
Swaps – long:
                                               
2006 (crude oil and refined products)
    7,947       8.12       8.81       N/A       5       5  
2006 (natural gas)
    2,700       11.37       9.19       N/A       (6 )     (6 )
Swaps – short:
                                               
2006 (crude oil and refined products).
    4,481       17.27       16.85       N/A       (2 )     (2 )
2006 (natural gas)
    1,350       9.19       11.46       N/A       3       3  
Futures – long:
                                               
2006 (crude oil and refined products)
    29,945       65.64       N/A       1,966       2,036       70  
Futures – short:
                                               
2006 (crude oil and refined products)
    27,052       N/A       65.34       1,768       1,815       (47 )
Options – long:
                                               
2006 (natural gas)
    1,290       9.27       N/A       (2 )     (1 )     1  
Options – short:
                                               
2006 (crude oil and refined products)
    190       N/A       72.95       (1 )     (1 )      
2006 (natural gas)
    690       N/A       7.98                    
 
                                               
Trading Activities:
                                               
Swaps – long:
                                               
2006 (crude oil and refined products)
    300       11.64       11.94       N/A              
2006 (natural gas)
    350       9.33       11.28       N/A       1       1  
Swaps – short:
                                               
2006 (crude oil and refined products)
    1,350       12.66       13.17       N/A       1       1  
2006 (natural gas)
    350       11.28       9.18       N/A       (1 )     (1 )
Futures – long:
                                               
2006 (crude oil and refined products)
    12,266       60.01       N/A       736       763       27  
2006 (natural gas)
    840       8.03       N/A       6       9       3  
Futures – short:
                                               
2006 (crude oil and refined products)
    10,816       N/A       60.49       654       678       (24 )
2006 (natural gas)
    840       N/A       8.34       7       9       (2 )
Options – long:
                                               
2006 (crude oil and refined products)
    2,000       0.50       N/A                    
2006 (natural gas)
    900       10.00       N/A                    
Options – short:
                                               
2006 (crude oil and refined products)
    2,000       N/A       0.50                    
2006 (natural gas)
    900       N/A       10.00                    

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    December 31, 2004
            Wtd Avg   Wtd Avg           Pre-tax
    Contract   Pay   Receive   Contract   Market   Fair
    Volumes   Price   Price   Value   Value   Value
Fair Value Hedges:
                                               
Futures – long:
                                               
2005 (crude oil and refined products)
    17,423     $ 46.39       N/A     $ 808     $ 772     $ (36 )
Futures – short:
                                               
2005 (crude oil and refined products)
    26,726       N/A     $ 46.00       1,229       1,190       39  
 
                                               
Cash Flow Hedges:
                                               
Swaps – long:
                                               
2005 (crude oil and refined products)
    67,378       37.05       42.84       N/A       390       390  
Swaps – short:
                                               
2005 (crude oil and refined products)
    67,378       48.54       41.65       N/A       (464 )     (464 )
Futures – long:
                                               
2005 (crude oil and refined products)
    28,354       45.39       N/A       1,287       1,286       (1 )
Futures – short:
                                               
2005 (crude oil and refined products)
    23,152       N/A       45.95       1,064       1,067       (3 )
 
                                               
Economic Hedges:
                                               
Swaps – long:
                                               
2005 (crude oil and refined products)
    3,505       11.49       11.37       N/A              
Swaps – short:
                                               
2005 (crude oil and refined products)
    4,239       10.10       10.25       N/A       1       1  
Futures – long:
                                               
2005 (crude oil and refined products)
    19,230       46.90       N/A       902       896       (6 )
Futures – short:
                                               
2005 (crude oil and refined products)
    17,787       N/A       47.55       846       824       22  
Options – long:
                                               
2005 (crude oil and refined products)
    1,000       35.00       N/A       3       5       2  
Options – short:
                                               
2005 (crude oil and refined products)
    4,201       N/A       21.69       (2 )     3       (5 )
 
                                               
Trading Activities:
                                               
Swaps – long:
                                               
2005 (crude oil and refined products)
    25,460       35.15       39.17       N/A       102       102  
Swaps – short:
                                               
2005 (crude oil and refined products)
    23,585       42.66       38.20       N/A       (105 )     (105 )
Futures – long:
                                               
2005 (crude oil and refined products)
    15,956       45.09       N/A       719       725       6  
2005 (natural gas)
    210       7.04       N/A       1       1        
Futures – short:
                                               
2005 (crude oil and refined products)
    21,781       N/A       45.81       998       1,003       (5 )
2005 (natural gas)
    210       N/A       6.38       1       1        
Options – long:
                                               
2005 (crude oil and refined products)
    1,550       48.35       N/A       1       1        
Options – short:
                                               
2005 (crude oil and refined products)
    150       N/A       10.55                    

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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 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 is recorded in interest expense along with the offsetting gain or loss on the debt that is being hedged, and the recorded amount 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.
                                                                 
    December 31, 2005
    Expected Maturity Dates            
                                            There-           Fair
    2006   2007   2008   2009   2010   after   Total   Value
Long-term Debt:
                                                               
Fixed rate
  $ 220     $ 287     $ 6     $ 209     $ 208     $ 4,392     $ 5,322     $ 5,735  
Average interest rate
    7.4 %     6.1 %     6.0 %     3.6 %     8.9 %     7.0 %     6.9 %        
 
                                                               
Interest Rate Swaps
                                                               
Fixed to Floating:
                                                               
Notional amount
  $ 125     $ 225           $ 9           $ 641     $ 1,000     $ (28 )
Average pay rate
    6.5 %     6.2 %     5.8 %     5.9 %     5.9 %     5.6 %     5.9 %        
Average receive rate
    6.0 %     5.8 %     5.7 %     5.7 %     5.7 %     5.6 %     5.7 %        
                                                                 
    December 31, 2004
    Expected Maturity Dates            
                                            There-           Fair
    2005   2006   2007   2008   2009   after   Total   Value
Long-term Debt:
                                                               
Fixed rate
  $ 410     $ 260     $ 329     $ 6     $ 208     $ 3,164     $ 4,377     $ 4,790  
Average interest rate
    8.1 %     7.4 %     6.1 %     6.0 %     3.6 %     6.8 %     6.8 %        
 
                                                               
Interest Rate Swaps
                                                               
Fixed to Floating:
                                                               
Notional amount
  $     $ 125     $ 225     $     $ 8     $ 642     $ 1,000     $ (15 )
Average pay rate
    5.0 %     5.6 %     5.6 %     5.4 %     5.8 %     6.2 %     5.9 %        
Average receive rate
    6.0 %     6.0 %     5.8 %     5.7 %     5.7 %     5.6 %     5.7 %        

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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.
During May 2002, we entered into foreign currency exchange contracts to hedge our exposure to exchange rate fluctuations on an investment in our Canadian operations that we intended to redeem in the future. Under these contracts, we sold $400 million of Canadian dollars and bought $253 million of U.S. dollars. In February 2004, we redeemed our remaining balance of this investment in our Canadian operations. As a result, we liquidated the outstanding amount of these foreign currency exchange contracts for a net cash payment by us of approximately $34 million, with an immaterial effect on income in the first quarter of 2004 as a result of the liquidation of these contracts.
As of December 31, 2005, we had commitments to purchase $303 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before January 27, 2006.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 2005. 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, 2005, our internal control over financial reporting was effective based on those criteria.
Management’s evaluation of and conclusion regarding the effectiveness of our internal control over financial reporting excludes the internal control over financial reporting of Premcor Inc. and its subsidiaries (Premcor), which we acquired on September 1, 2005 (as described in Note 2 of Notes to Consolidated Financial Statements). The acquisition of Premcor contributed approximately 10 percent of our total revenue for the year ended December 31, 2005 and accounted for approximately 30 percent of our total assets as of December 31, 2005. We plan to fully integrate Premcor into our internal control over financial reporting in 2006.
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 52 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, 2005 and 2004, and the related consolidated statements of income, stockholders’ equity, cash flows and comprehensive income for the years then ended. 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 audits 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, 2005 and 2004, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States.
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, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 1, 2006, 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
March 1, 2006

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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 management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting for the year ended December 31, 2005, that Valero Energy Corporation and subsidiaries (the Company) maintained effective internal control over financial reporting as of December 31, 2005, 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, 2005, 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, 2005, based on criteria established in Internal Control—Integrated Framework issued by COSO.

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The Company acquired Premcor Inc. and its subsidiaries (Premcor) on September 1, 2005, and management excluded Premcor’s internal control over financial reporting from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. The acquisition of Premcor contributed approximately 10 percent of the Company’s total revenue for the year ended December 31, 2005 and accounted for approximately 30 percent of the Company’s total assets as of December 31, 2005. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Premcor.
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, 2005 and 2004, and the related consolidated statements of income, stockholders’ equity, cash flows and comprehensive income for the years then ended, and our report dated March 1, 2006 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
San Antonio, Texas
March 1, 2006

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
of Valero Energy Corporation
We have audited the accompanying consolidated statements of income, stockholders’ equity, cash flows and comprehensive income of Valero Energy Corporation and subsidiaries (the Company) for the year ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Valero Energy Corporation and subsidiaries for the year ended December 31, 2003 in conformity with accounting principles generally accepted in the United States.
/s/ ERNST & YOUNG LLP
San Antonio, Texas
March 11, 2004

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)
                 
    December 31,  
    2005     2004  
ASSETS
               
Current assets:
               
Cash and temporary cash investments
  $ 436     $ 864  
Restricted cash
    30       24  
Receivables, net
    3,564       1,839  
Inventories
    4,039       2,318  
Deferred income taxes
    142       175  
Prepaid expenses and other
    65       44  
 
           
Total current assets
    8,276       5,264  
 
           
 
               
Property, plant and equipment, at cost
    20,388       12,295  
Accumulated depreciation
    (2,532 )     (1,978 )
 
           
Property, plant and equipment, net
    17,856       10,317  
 
           
 
               
Intangible assets, net
    298       311  
Goodwill
    4,926       2,401  
Investment in Valero L.P.
    327       265  
Deferred charges and other assets, net
    1,045       834  
 
           
Total assets
  $ 32,728     $ 19,392  
 
           
 
               
LIABILITIES AND STOCKHOLDERSEQUITY
               
 
Current liabilities:
               
Current portion of long-term debt and capital lease obligations
  $ 222     $ 412  
Accounts payable
    5,563       2,963  
Accrued expenses
    581       519  
Taxes other than income taxes
    595       480  
Income taxes payable
    39       160  
Deferred income taxes
    305        
 
           
Total current liabilities
    7,305       4,534  
 
           
 
               
Long-term debt, less current portion
    5,109       3,893  
 
           
Capital lease obligations, less current portion
    47       8  
 
           
Deferred income taxes
    3,615       2,011  
 
           
Other long-term liabilities
    1,602       1,148  
 
           
Commitments and contingencies (Note 23)
               
 
               
Stockholders’ equity:
               
Preferred stock, $0.01 par value; 20,000,000 shares authorized; 3,164,151 and 10,000,000 shares issued and outstanding
    68       208  
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 621,230,266 and 522,377,228 shares issued
    6       5  
Additional paid-in capital
    8,164       4,356  
Treasury stock, at cost; 3,807,976 and 11,425,524 common shares
    (196 )     (199 )
Retained earnings
    6,673       3,199  
Accumulated other comprehensive income
    335       229  
 
           
Total stockholders’ equity
    15,050       7,798  
 
           
Total liabilities and stockholders’ equity
  $ 32,728     $ 19,392  
 
           
See Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, Except per Share Amounts and Supplemental Information)
                         
    Year Ended December 31,  
    2005     2004     2003  
Operating revenues (1) (2)
  $ 82,162     $ 54,619     $ 37,969  
 
                 
 
                       
Costs and expenses:
                       
Cost of sales (1)
    71,673       47,797       33,587  
Refining operating expenses
    2,926       2,141       1,656  
Retail selling expenses
    771       705       694  
General and administrative expenses
    458       379       299  
Depreciation and amortization expense
    875       618       511  
 
                 
Total costs and expenses
    76,703       51,640       36,747  
 
                 
 
                       
Operating income
    5,459       2,979       1,222  
Equity in earnings of Valero L.P.
    41       39       30  
Other income (expense), net
    53       (48 )     15  
Interest and debt expense:
                       
Incurred
    (334 )     (297 )     (287 )
Capitalized
    68       37       26  
Minority interest in net income of Valero L.P.
                (2 )
Distributions on preferred securities of subsidiary trusts
                (17 )
 
                 
Income before income tax expense
    5,287       2,710       987  
Income tax expense
    1,697       906       365  
 
                 
 
                       
Net income
    3,590       1,804       622  
Preferred stock dividends
    13       13       5  
 
                 
 
                       
Net income applicable to common stock
  $ 3,577     $ 1,791     $ 617  
 
                 
 
                       
Earnings per common share
  $ 6.51     $ 3.51     $ 1.34  
Weighted average common shares outstanding (in millions)
    549       510       459  
 
                       
Earnings per common share – assuming dilution
  $ 6.10     $ 3.27     $ 1.27  
Weighted average common equivalent shares outstanding (in millions)
    588       552       488  
 
                       
Dividends per common share
  $ 0.19     $ 0.145     $ 0.105  
 
Supplemental information (billions of dollars):
                       
(1) Includes amounts related to crude oil buy/sell arrangements:
                       
Operating revenues
  $ 7.8     $ 4.9     $ 3.9  
Cost of sales
    7.8       4.9       3.9  
(2) Includes excise taxes on sales by our U.S. retail system
  $ 0.8     $ 0.8     $ 0.8  
See Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Millions of Dollars)
                                                 
                                            Accumulated  
                    Additional                     Other  
    Preferred     Common     Paid-in     Treasury     Retained     Comprehensive  
    Stock     Stock     Capital     Stock     Earnings     Income (Loss)  
Balance as of December 31, 2002
  $     $ 4     $ 3,433     $ (42 )   $ 913     $ (1 )
Net income
                            622        
Dividends on common stock
                            (48 )      
Dividends on and accretion of preferred stock
    1                         (4 )      
Sale of common stock
                250                    
Issuance of preferred stock in connection with St. Charles Acquisition
    199             21                    
Settlement of stock purchase contracts under PEPS Units
                173                    
Shares repurchased and shares issued in connection with employee stock plans and other
                42       1              
Other comprehensive income
                                  171  
 
                                   
 
                                               
Balance as of December 31, 2003
    200       4       3,919       (41 )     1,483       170  
Net income
                            1,804        
Dividends on common stock
                            (75 )      
Dividends on and accretion of preferred stock
    8                         (13 )      
Sale of common stock
          1       406                    
Shares repurchased and shares issued in connection with employee stock plans and other
                31       (158 )            
Other comprehensive income
                                  59  
 
                                   
 
                                               
Balance as of December 31, 2004
    208       5       4,356       (199 )     3,199       229  
Net income
                            3,590        
Dividends on common stock
                            (103 )      
Dividends on and accretion of preferred stock
    10                         (13 )      
Conversion of preferred stock
    (150 )           150                    
Issuance of common stock in connection with the Premcor Acquisition
          1       3,177                    
Fair value of replacement stock options issued in connection with the Premcor Acquisition
                595                    
Shares repurchased and shares issued in connection with employee stock plans and other
                (114 )     3              
Other comprehensive income
                                  106  
 
                                   
 
                                               
Balance as of December 31, 2005
  $ 68     $ 6     $ 8,164     $ (196 )   $ 6,673     $ 335  
 
                                   
See Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
                         
    Year Ended December 31,  
    2005     2004     2003  
Cash flows from operating activities:
                       
Net income
  $ 3,590     $ 1,804     $ 622  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization expense
    875       618       511  
Gain on sale of investment in Javelina joint venture
    (55 )            
Impairment of investment in Clear Lake Methanol Partners, L.P.
          57        
Distributions in excess of (less than) equity in earnings of Valero L.P.
    4       1       (4 )
Minority interest in net income of Valero L.P.
                2  
Noncash interest expense and other income, net
    27       10       2  
Deferred income tax expense
    255       345       287  
Changes in current assets and current liabilities
    1,082       203       429  
Changes in deferred charges and credits and other, net
    21       (80 )     (96 )
 
                 
Net cash provided by operating activities
    5,799       2,958       1,753  
 
                 
 
                       
Cash flows from investing activities:
                       
Capital expenditures
    (2,133 )     (1,292 )     (976 )
Deferred turnaround and catalyst costs
    (441 )     (304 )     (136 )
Buyout of assets under structured lease arrangements
          (567 )     (275 )
Premcor Acquisition, net of cash acquired
    (2,343 )            
Aruba Acquisition, net of cash acquired
          (541 )      
St. Charles Acquisition
                (309 )
Proceeds from sale of assets to Valero L.P.
                380  
Proceeds from sale of Tesoro notes
                90  
Proceeds from sale of the Denver Refinery
    45              
Proceeds from sale of investment in Javelina joint venture
    78              
General partner contribution to Valero L.P.
    (29 )           (1 )
Contingent payments in connection with acquisitions
    (85 )     (53 )     (51 )
(Investment) return of investment in Cameron Highway Oil Pipeline Project, net
    38       (36 )     (106 )
Proceeds from dispositions of property, plant and equipment and certain home heating oil operations
    30       108       94  
Minor acquisitions and other investing activities, net
    (60 )           (41 )
 
                 
Net cash used in investing activities
    (4,900 )     (2,685 )     (1,331 )
 
                 
 
                       
Cash flows from financing activities:
                       
Decrease in short-term debt, net
                (153 )
Repayment of capital lease obligations
    (2 )     (1 )     (289 )
Long-term debt borrowings, net of issuance costs
    1,537       3,782       4,014  
Long-term debt repayments
    (2,414 )     (3,718 )     (3,943 )
Proceeds from cash settlement of PEPS Unit purchase contracts
                14  
Redemption of company-obligated preferred securities of subsidiary trust
                (200 )
Proceeds from issuance of common units by Valero L.P., net of issuance costs
                200  
Cash distributions to minority interest in Valero L.P.
                (4 )
Proceeds from the sale of common stock, net of issuance costs
          406       250  
Issuance of common stock in connection with employee benefit plans
    227       135       99  
Common and preferred stock dividends
    (106 )     (79 )     (51 )
Purchase of treasury stock
    (571 )     (318 )     (73 )
Other
    (2 )            
 
                 
Net cash provided by (used in) financing activities
    (1,331 )     207       (136 )
 
                 
Valero L.P.’s cash balance as of the date (March 18, 2003) that we ceased consolidation of Valero L.P. (Note 9)
                (336 )
 
                 
Effect of foreign exchange rate changes on cash
    4       15       40  
 
                 
Net increase (decrease) in cash and temporary cash investments
    (428 )     495       (10 )
Cash and temporary cash investments at beginning of year
    864       369       379  
 
                 
Cash and temporary cash investments at end of year
  $ 436     $ 864     $ 369  
 
                 
See Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of Dollars)
                         
    Year Ended December 31,  
    2005     2004     2003  
Net income
  $ 3,590     $ 1,804     $ 622  
 
                 
 
                       
Other comprehensive income (loss):
                       
Foreign currency translation adjustment
    54       111       163  
 
                 
 
                       
Minimum pension liability adjustment, net of income tax expense of $-, $- and $3
    (1 )           5  
 
                 
 
                       
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 $117, $90 and $(13)
    (218 )     (168 )     24  
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $(146), $(62) and $11
    271       116       (21 )
 
                 
Net gain (loss) on cash flow hedges
    53       (52 )     3  
 
                 
 
                       
Other comprehensive income
    106       59       171  
 
                 
 
                       
Comprehensive income
  $ 3,696     $ 1,863     $ 793  
 
                 
See Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
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, 2005 of approximately 3.3 million barrels per day. We market our refined products through an extensive bulk and rack marketing network and approximately 5,000 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 50% or less owned entities are accounted for using the equity method of accounting (see Note 9 for a discussion of the reporting change in 2003 for our investment in Valero L.P., a related party which was consolidated until March 2003).
Share and per share data (except par value) presented for all periods reflect the effect of two separate two-for-one stock splits, which were effected in the form of common stock dividends distributed on December 15, 2005 and October 7, 2004, as discussed in Note 15 under “Common Stock Splits.”
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 their estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.
Cash and Temporary Cash Investments
Our temporary cash investments are highly liquid, low-risk debt instruments which generally 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).

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)
Inventories
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. We use 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.
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 4 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 the annual impairment test.
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 notes receivable, long-term investments, 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

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2005 are recoverable.
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, 2005 are recoverable.
Taxes Other than Income Taxes
“Taxes other than income taxes” includes primarily liabilities for ad valorem, excise 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.
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 was no impact on our 2004 or 2005 consolidated financial statements as a result of adoption of Staff Position No. FAS 109-2.
Asset Retirement Obligations
Effective January 1, 2003, we adopted FASB Statement No. 143, “Accounting for Asset Retirement Obligations,” which established financial accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The provisions of this statement apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset, except for certain obligations of lessees. On January 1, 2003, we recognized an asset retirement obligation of $30 million which is included in “other long-term liabilities,” and an increase to net property, plant and equipment of $26 million. The implementation of Statement No. 143 resulted in a pre-tax loss of $4 million which, because of its insignificance, was included in the consolidated statements of income in “other income (expense), net” instead of being presented as a cumulative effect of an accounting change.
We record a liability 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,

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
which is referred to as an asset retirement obligation, when we have a legal obligation, as defined in Statement No. 143, 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 have recorded approximately $25 million and $16 million, respectively, in asset retirement obligations related to the retirement of component parts of our refineries as of December 31, 2005 and 2004.
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. We have recorded approximately $26 million and $25 million, respectively, in conditional asset retirement obligations related to the retirement of USTs and signage at our retail locations as of December 31, 2005 and 2004.
For the years ended December 31, 2005, 2004 and 2003, changes in our asset retirement obligations were as follows (in millions):
                         
    Year Ended December 31,  
    2005     2004     2003  
Balance as of beginning of year
  $ 41     $ 34     $ 30  
Additions to accrual
    9       17        
Accretion expense
    2       2       2  
Settlements
    (2 )     (2 )     (1 )
Changes in timing and amount of estimated cash flows
    1       (11 )     1  
Foreign currency translation
          1       2  
 
                 
Balance as of end of year
  $ 51     $ 41     $ 34  
 
                 

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In March 2005, the FASB issued 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. FIN 47 became effective for us for the year ended December 31, 2005, and did not affect our financial position or results of operations.
Foreign Currency Translation
The functional currencies of our Canadian and Aruba 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.
Through December 31, 2005, revenues included sales related to certain buy/sell arrangements, which involve linked purchases and sales related to crude oil contracts entered into to address location, quality or grade requirements. In some cases, to obtain crude oil of a specific grade and quantity for certain of our refineries, we must agree to sell crude oil of a different grade and quantity to our supplier at another location. We generally do not have the specific crude oil to satisfy our supplier’s needs and therefore must purchase that crude oil from a third party. We sell the crude oil acquired from the third party to our crude oil supplier and, through 2005, recognized revenue on the sale and cost of sales at that time. See “EITF Issue No. 04-13” under “New Accounting Pronouncements” below, which was adopted by us on January 1, 2006 and which requires us to cease recognizing revenues and cost of sales on our buy/sell arrangements.
We 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.
Environmental Matters
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

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 reported as a component of “other comprehensive income” and is recorded in income in the same period or periods during which the hedged forecasted transaction affects income. The remaining ineffective portion of the gain or loss on the cash flow derivative instrument, if any, is recognized currently in income. Gains and losses on trading instruments are reflected on a net basis in the consolidated statements of income within “cost of sales.” 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 performance awards granted to employees in connection with our stock compensation plans, as well as the 2% mandatory convertible preferred stock discussed in Note 15 and the PEPS Units prior to the settlement of the related purchase contract obligations 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, minimum pension liability adjustments and gains and losses related to certain derivative instruments.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.”
The weighted-average fair value of stock options granted during the years ended December 31, 2005, 2004 and 2003 was $18.80, $8.02 and $7.65 per stock option, respectively. The fair value of each stock option grant was estimated on the grant date using the Black-Scholes option-pricing model with the following assumptions:
                         
    Year Ended December 31,
    2005   2004   2003
Risk-free interest rate
    4.3 %     3.3 %     3.1 %
Expected volatility
    40.0 %     41.4 %     44.5 %
Expected dividend yield
    0.4 %     0.7 %     1.0 %
Expected life (years)
    5.0       5.0       4.9  
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, 2004 and 2003 would have been reduced to the pro forma amounts indicated in the following table (in millions, except per share amounts):

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
                         
    Year Ended December 31,  
    2005     2004     2003  
Net income applicable to common stock, as reported
  $ 3,577     $ 1,791     $ 617  
Deduct: Compensation expense on stock options determined under fair value method for all awards, net of related tax effects
    (19 )     (16 )     (16 )
 
                 
Pro forma net income applicable to common stock
  $ 3,558     $ 1,775     $ 601  
 
                 
 
                       
Earnings per common share:
                       
As reported
  $ 6.51     $ 3.51     $ 1.34  
Pro forma
  $ 6.48     $ 3.48     $ 1.31  
 
                       
Net income, as reported
  $ 3,590     $ 1,804     $ 622  
Deduct: Compensation expense on stock options determined under fair value method for all awards, net of related tax effects
    (19 )     (16 )     (16 )
 
                 
Pro forma net income
  $ 3,571     $ 1,788     $ 606  
 
                 
 
                       
Earnings per common share — assuming dilution:
                       
As reported
  $ 6.10     $ 3.27     $ 1.27  
Pro forma
  $ 6.07     $ 3.24     $ 1.24  
For stock-based compensation awards other than fixed stock option awards, the after-tax compensation cost reflected in net income for the years ended December 31, 2005, 2004 and 2003 was $50 million, $24 million and $8 million, respectively.
See “New Accounting Pronouncements” below for a discussion of FASB Statement No. 123 (revised 2004), which requires changes to our accounting for stock-based compensation beginning January 1, 2006.
New Accounting Pronouncements
FASB Statement No. 151
In November 2004, the FASB issued Statement No. 151, “Inventory Costs,” which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material and requires that those items be recognized as current-period charges. Statement No. 151 also requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. Statement No. 151 was effective for fiscal years beginning after June 15, 2005, and our adoption has not affected our financial position or results of operations.
FASB Statement No. 153
In December 2004, the FASB issued Statement No. 153, “Exchanges of Nonmonetary Assets,” which addresses the measurement of exchanges of nonmonetary assets. Statement No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets, which was previously provided by APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an

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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 has not affected our financial position or results of operations.
FASB Statement No. 123 (revised 2004)
In December 2004, the FASB issued Statement No. 123 (revised 2004), “Share-Based Payment” (Statement No. 123R), which requires the expensing of the fair value of stock options. Statement No. 123R eliminates the alternative to use APB Opinion No. 25’s intrinsic value method of accounting that was provided in Statement No. 123 as originally issued and requires entities to recognize the cost of employee services received in exchange for awards of equity instruments based on the grant-date fair value of those awards. Under Statement No. 123R, we will transition to the fair-value-based method using a modified prospective application. Under that transition method, compensation cost will be recognized commencing in 2006 for the portion of outstanding awards for which the requisite service has not yet been rendered. In April 2005, the Securities and Exchange Commission (SEC) amended Rule 4-01(a) of Regulation S-X to defer the required date for compliance with Statement No. 123R to the first interim or annual reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 if the registrant is not a small business issuer. We have adopted Statement No. 123R on January 1, 2006, which complies with the amended Rule 4-01(a).
Through December 31, 2005, we accounted for share-based payments to employees using Opinion No. 25’s intrinsic value method, and, as such, generally recognized no compensation cost for employee stock options. Accordingly, the adoption of Statement No. 123R’s fair value method will reduce our results of operations, but will not have a material impact on our overall financial position. The specific magnitude of the impact of adoption of Statement No. 123R cannot be predicted at this time because it will depend on levels of share-based incentive awards granted in the future. However, 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 pro forma net income and earnings per share in “Stock-Based Compensation” above.
Statement No. 123R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as previously required. This will reduce cash flows from operating activities and increase 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 amounts of operating cash flows recognized for such excess tax deductions were $270 million, $54 million and $15 million for the years ended December 31, 2005, 2004 and 2003, respectively.
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 have 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, as disclosed in “Stock-Based Compensation” above. Upon the adoption of Statement No. 123R on January 1, 2006, we changed our method of recognizing compensation cost to the non-substantive vesting period approach for any awards that are granted after the adoption of Statement No. 123R. Under the non-substantive vesting period approach, compensation cost will be recognized immediately for awards granted to retirement-eligible employees or over the period from the grant

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date to the date retirement eligibility is achieved if that date is expected to occur during the nominal vesting period. The estimated after-tax effect on the pro forma compensation expense related to stock options for the year ended December 31, 2005 reflected under “Stock-Based Compensation” above that is expected to result from the application of the non-substantive vesting period approach was $8 million.
EITF Issue No. 04-5
In June 2005, the FASB ratified its consensus on 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 guidance in EITF No. 04-5 was effective after June 29, 2005 for general partners of all new partnerships formed and for existing limited partnerships for which the partnership agreements are modified. For general partners in all other limited partnerships, the guidance in EITF No. 04-5 was effective no later than January 1, 2006. We have adopted
EITF No. 04-5 effective January 1, 2006, the adoption of which had no impact on the accounting for our investment in Valero L.P.
EITF Issue No. 04-13
As discussed under “Revenue Recognition” above, 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 for purposes of applying AICPA Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions” (APB No. 29). The guidance in EITF No. 04-13 is effective for transactions completed in reporting periods beginning after March 15, 2006, with early application permitted. We have 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 therefore should be viewed as one transaction when applying the principles of APB No. 29. 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, these buy/sell arrangements will be accounted for as one transaction in applying the principles of APB No. 29 and revenues and cost of sales will cease to be recognized in connection with these arrangements. This adoption will result in a reduction in our operating revenues in our consolidated statement of income and a corresponding reduction in cost of sales with no expected 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, 2004 and 2003, 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.
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:

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    permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation,
 
    clarifies which interest-only and principal-only strips are not subject to the requirements of Statement No. 133,
 
    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,
 
    clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives, and
 
    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.
Statement No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s fiscal year that begins after September 15, 2006. We are currently evaluating the impact, if any, of Statement No. 155 on our financial position or results of operations.
Reclassifications
Certain previously reported amounts in the 2004 and 2003 consolidated financial statements have been reclassified to conform to the 2005 presentation.
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 approximately $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

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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.
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.
The Premcor Acquisition is consistent with our general business strategy of increasing cash flow and earnings through the acquisition of assets or businesses that are a logical extension of our existing assets or businesses. The addition of Premcor’s assets has also increased the geographic diversity of our refining network by allowing us to expand into the midwestern United States with the addition of Premcor’s Lima and Memphis Refineries. We believe that Premcor’s assets provide profit improvement opportunities, which we believe we should be able to realize given our history of increasing the reliability, capacity and yields of previously acquired refineries.
The Premcor Acquisition purchase price has been preliminarily allocated based on estimated fair values of the assets acquired and liabilities assumed at the date of acquisition, pending the completion of an independent appraisal and other evaluations, including obtaining additional information related to certain legal and environmental contingencies that existed prior to the merger. The purchase price and the preliminary purchase price allocation as of December 31, 2005 were as follows (in millions):
         
Cash paid
  $ 3,377  
Transaction costs
    27  
Less unrestricted cash acquired
    (1,061 )
 
     
Premcor Acquisition, net of cash acquired, as reflected on the consolidated statement of cash flows
    2,343  
Common stock and stock options issued
    3,773  
 
     
Total purchase price, excluding unrestricted cash acquired
  $ 6,116  
 
     
 
       
Current assets, net of unrestricted cash acquired
  $ 3,438  
Property, plant and equipment
    5,873  
Intangible assets
    5  
Goodwill
    2,528  
Deferred charges and other assets
    30  
Current liabilities, less current portion of long-term debt and capital lease obligations
    (1,793 )
Long-term debt assumed, including current portion
    (1,912 )
Capital lease obligation, including current portion
    (14 )
Deferred income taxes
    (1,678 )
Other long-term liabilities
    (361 )
 
     
Purchase price, excluding unrestricted cash acquired
  $ 6,116  
 
     

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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 approximately $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, the purpose of which was to strengthen our geographic and product diversification, ensure a more secure supply of intermediate feedstocks and blendstocks to certain of our other refineries, and increase our potential ability to take advantage of positive heavy sour crude oil fundamentals, was funded with $200 million in existing cash, approximately $27 million in borrowings under our bank credit facilities and approximately $406 million in net proceeds from the sale of 31 million shares of our common stock through a public offering discussed in Note 15 under “Common Stock Offerings.” The amount paid to the third-party marketing firm described above was funded through borrowings under our bank credit facilities. The results of the Aruba Refinery’s operations are non-taxable in Aruba through December 31, 2010. During the first quarter of 2005, an independent appraisal was completed and the resulting final purchase price allocation for the Aruba Acquisition is summarized below (in millions):
         
Current assets
  $ 323  
Property, plant and equipment
    498  
Current liabilities
    (172 )
Capital lease obligation
    (3 )
Deferred income taxes
    9  
Other long-term liabilities
    (20 )
 
     
Total purchase price
    635  
Less cash acquired
    (94 )
 
     
Purchase price, excluding cash acquired
  $ 541  
 
     
St. Charles Acquisition
On July 1, 2003, we completed the acquisition of the St. Charles Refinery (St. Charles Acquisition) from Orion Refining Corporation (Orion). Total consideration for the purchase, including various transaction costs incurred and the release of certain escrowed amounts discussed below, was $529 million and included the issuance of 10 million shares of mandatory convertible preferred stock with a fair value of $22 per share. The purchase agreement required 844,000 shares of the mandatory convertible preferred stock to be held in escrow pending the satisfaction of certain conditions. The purchase agreement also provided for the assumption of certain environmental and regulatory obligations as well as for potential earn-out payments up to an aggregate of $175 million as discussed in Note 23 under “Contingent Earn-Out Agreements.” As of December 31, 2003, the escrowed shares had been converted to cash held in escrow. As of December 31, 2005, less than $1 million of the escrowed cash remains in “restricted cash” in the consolidated balance sheet.
The total potential earn-out payments of $175 million discussed above were recognized in “property, plant and equipment” (with $50 million recorded as a current liability in “accrued expenses” and $125 million recorded in “other long-term liabilities”) as part of the purchase price allocation since the fair value of the assets acquired less liabilities assumed exceeded the cost of the acquisition by an amount greater than the potential earn-out amount. During the second quarter of 2004, an independent appraisal was completed and the

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resulting final purchase price allocation for the St. Charles Acquisition is summarized below (in millions). The amounts reflected include the accrual of the potential earn-out payments.
         
Inventories
  $ 155  
Property, plant and equipment
    574  
Accrued expenses
    (51 )
Other long-term liabilities
    (149 )
 
     
Total purchase price
  $ 529  
 
     
Unaudited Pro Forma Financial Information
The consolidated statements of income include the results of operations of the St. Charles Acquisition, the Aruba Acquisition and the Premcor Acquisition commencing on July 1, 2003, March 5, 2004 and September 1, 2005, respectively. The following unaudited pro forma financial information assumes that the Premcor Acquisition occurred on January 1, 2005 and 2004, the Aruba Acquisition occurred on January 1, 2004 and 2003 and the St. Charles Acquisition occurred on January 1, 2003 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;
 
    31 million shares of common stock were sold and approximately $36 million of debt was incurred in connection with the Aruba Acquisition on January 1, 2004 and 2003; and
 
    10 million shares of mandatory convertible preferred stock were issued in connection with the St. Charles Acquisition on January 1, 2003.
The unaudited pro forma financial information is not necessarily indicative of the results of future operations (in millions, except per share amounts):
                         
    Year Ended December 31,
    2005   2004   2003
Operating revenues
  $ 95,120     $ 69,695     $ 41,065  
Operating income
    6,434       3,759       1,026  
Net income
    4,160       2,165       450  
Net income applicable to common stock
    4,147       2,153       439  
Earnings per common share
    6.85       3.60       0.90  
Earnings per common share - assuming dilution
    6.40       3.36       0.85  
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. (Suncor) for $30 million plus approximately $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 (the Javelina Companies) to MarkWest Energy Partners, L.P. (MarkWest) for $78 million, recognizing a gain of approximately $55 million. Javelina Company processes refinery off-gas at a plant in Corpus Christi, Texas.

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3. RESTRICTED CASH
Restricted cash as of December 31, 2005 and 2004 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, 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):
                 
    December 31,  
    2005     2004  
Accounts receivable
  $ 3,572     $ 1,836  
Notes receivable
    4       5  
Other
    19       25  
 
           
 
    3,595       1,866  
Allowance for doubtful accounts
    (31 )     (27 )
 
           
Receivables, net
  $ 3,564     $ 1,839  
 
           
The changes in the allowance for doubtful accounts consisted of the following (in millions):
                         
    Year Ended December 31,  
    2005     2004     2003  
Balance as of beginning of year
  $ 27     $ 25     $ 23  
Increase in allowance charged to expense
    15       13       14  
Accounts charged against the allowance, net of recoveries
    (12 )     (12 )     (13 )
Foreign currency translation
    1       1       1  
 
                 
Balance as of end of year
  $ 31     $ 27     $ 25  
 
                 
As of December 31, 2004, we had an accounts receivable sales facility with a group of third-party financial institutions to sell on a revolving basis up to $600 million of eligible trade and credit card receivables, which was to mature in October 2005. In August 2005, we amended this agreement to, among other things: (i) remove the credit card receivables from the eligible pool of receivables, (ii) increase the size of the facility by $400 million to $1 billion, and (iii) extend the maturity date to 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 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

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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 $30 million, $12 million and $6 million for the years ended December 31, 2005, 2004 and 2003, respectively. Proceeds from collections under this facility of $24.1 billion, $17.6 billion and $12.4 billion for the years ended December 31, 2005, 2004 and 2003, 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 2005, 2004 or 2003.
As of December 31, 2005 and 2004, $2.6 billion and $1.4 billion, respectively, of our accounts receivable composed the designated pool of accounts receivable included in the program. Of these amounts, we sold $1 billion and $600 million, respectively, to the third-party financial institutions and retained the remaining amount.
5. INVENTORIES
Inventories consisted of the following (in millions):
                 
    December 31,  
    2005     2004  
Refinery feedstocks
  $ 1,826     $ 877  
Refined products and blendstocks
    1,960       1,200  
Convenience store merchandise
    91       84  
Materials and supplies
    162       157  
 
           
Inventories
  $ 4,039     $ 2,318  
 
           
Refinery feedstock and refined product and blendstock inventory volumes totaled 108 million barrels and 77 million barrels as of December 31, 2005 and 2004, respectively. There were no liquidations of LIFO inventories during the years ended December 31, 2005, 2004 and 2003.
As of December 31, 2005 and 2004, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $3.3 billion and $1.2 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):
                         
    Estimated     December 31,  
    Useful Lives     2005     2004  
Land
          $ 461     $ 436  
Crude oil processing facilities
  10 - 35 years     15,517       9,350  
Butane processing facilities
  30 years     244       244  
Pipeline and terminal facilities
  18 - 42 years     112       16  
Retail facilities
  2 - 22 years     637       545  
Buildings
  13 - 44 years     568       519  
Other
  2 - 44 years     592       446  
Construction in progress
            2,257       739  
 
                   
Property, plant and equipment, at cost
            20,388       12,295  
Accumulated depreciation
            (2,532 )     (1,978 )
 
                   
Property, plant and equipment, net
          $ 17,856     $ 10,317  
 
                   
As of December 31, 2005 and 2004, we had crude oil processing facilities, pipeline and terminal facilities, and certain buildings and other equipment under capital leases totaling $45 million and $8 million, respectively. Accumulated amortization on assets under capital leases was $3 million and $1 million, respectively, as of December 31, 2005 and 2004.
On February 28, 2003, we exercised our option under certain capital leases with El Paso Corporation to purchase the Corpus Christi East Refinery and related refined product logistics business, which we had operated since June 1, 2001. In connection with the exercise of the purchase option, the original purchase price for the assets was reduced by approximately $5 million to $289 million and the lease payment of approximately $5 million due in the first quarter of 2003 was avoided. No gain or loss was recorded on this transaction.
Depreciation expense for the years ended December 31, 2005, 2004 and 2003 was $594 million, $418 million and $341 million, respectively. 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. During 2003, net gains of $15 million were recorded as a reduction of depreciation expense on the disposition of various facilities, including the sale of certain retail stores and our home heating oil operations in the northeastern United States and southern Ontario in Canada for total proceeds of $85 million.
Our prior headquarters facility consisted of two buildings: One Valero Place (OVP) and Two Valero Place (TVP). In December 2003, our board of directors authorized the sale of OVP and TVP for $27 million. As a result, a $26 million impairment charge was recognized in December 2003 to write down the carrying amount of OVP and TVP to their fair values less selling costs. The impairment charge was reflected in “depreciation

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and amortization expense” in the consolidated statement of income for the year ended December 31, 2003, and was included in the corporate category for segment reporting purposes as shown in Note 21. On June 30, 2004, we completed the sale of both of our prior headquarters buildings for the sales price previously authorized by our board of directors, resulting in no incremental gain or loss in 2004.
See Note 23 under “Structured Lease Arrangements” for a discussion of our purchases during 2003 and 2004 of OVP, TVP, and other property, plant and equipment, which had been leased under structured lease arrangements.
7. INTANGIBLE ASSETS
Intangible assets consisted of the following (in millions):
                                 
    December 31, 2005     December 31, 2004  
    Gross     Accumulated     Gross     Accumulated  
    Cost     Amortization     Cost     Amortization  
Intangible assets subject to amortization:
                               
Customer lists
  $ 99     $ (25 )   $ 93     $ (18 )
Canadian retail operations
    133       (13 )     129       (10 )
U.S. retail store operations
    95       (47 )     91       (35 )
Air emission credits
    56       (24 )     56       (18 )
Royalties and licenses
    36       (15 )     36       (13 )
Other
    4       (1 )            
 
                       
Intangible assets subject to amortization
  $ 423     $ (125 )   $ 405     $ (94 )
 
                       
All of our intangible assets are subject to amortization. Amortization expense for intangible assets was $29 million, $26 million and $29 million for the years ended December 31, 2005, 2004 and 2003, respectively. The estimated aggregate amortization expense is approximately $27 million per year for the years ending December 31, 2006 through 2008 and $22 million and $19 million for the years ending December 31, 2009 and 2010, respectively.

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8. GOODWILL
The changes in the carrying amount of goodwill were as follows (in millions):
                 
    Year Ended December 31,  
    2005     2004  
Balance as of beginning of year
  $ 2,401     $ 2,402  
Preliminary purchase price allocation related to the Premcor Acquisition
    2,528        
Acquisition earn-out payments not previously accrued (see Note 23)
    35       35  
Settlements and adjustments related to tax contingencies assumed in the UDS Acquisition and other
    (38 )     (36 )
 
           
Balance as of end of year
  $ 4,926     $ 2,401  
 
           
Settlements and adjustments related to tax contingencies reflected in the table above relate primarily to various income tax contingencies assumed in the UDS Acquisition, 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. upon ceasing consolidation of 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, 2005 and 2004. These tests confirmed that no impairment of goodwill had occurred in any of our reporting units.
9. INVESTMENT IN AND TRANSACTIONS WITH VALERO L.P.
As of December 31, 2004, we owned approximately 45.7% of Valero L.P., a limited partnership that owns and operates crude oil and refined product pipeline, terminalling and storage tank assets. One of our wholly owned subsidiaries serves as the general partner of Valero L.P. Prior to March 18, 2003 and the transactions discussed below, we owned 73.6% of Valero L.P. and therefore consolidated the financial statements of Valero L.P. through that date.
Effective March 18, 2003, Valero L.P. issued 5,750,000 common units to the public for aggregate proceeds of $211 million and completed a private placement of $250 million of debt. The net proceeds, after issuance costs, of $200 million and $247 million, respectively, combined with borrowings under Valero L.P.’s credit facility and a contribution of $4 million we made to maintain our 2% general partner interest in Valero L.P., were used to fund a redemption of common units from us and the acquisition of certain storage tanks and a pipeline system from us discussed further below.
Subsequent to Valero L.P.’s equity and debt offerings, Valero L.P. redeemed 3.8 million of its common units from us for $137 million, including $3 million representing the redemption of a proportionate amount of our general partner interest. The proceeds from the redemption are reflected as a reduction to our investment in Valero L.P. This redemption, combined with the common unit issuance discussed above, reduced our ownership of Valero L.P. to 49.5% as of March 18, 2003. At the same time, Valero L.P. amended its

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
partnership agreement to reduce the minimum vote required to remove the general partner from 66-2/3% to 58% of Valero L.P.’s outstanding common and subordinated units, excluding the units held by our affiliates (see discussion below for subsequent revisions to this minimum vote which were effective on March 11, 2004). As a result of the issuance and redemption of Valero L.P. common units and the partnership agreement changes, effective March 18, 2003, we ceased consolidation of Valero L.P. and began using the equity method to account for our investment.
Subsequent to the equity and debt offerings and the common unit redemption by Valero L.P. discussed above, we sold to Valero L.P. 58 crude oil and intermediate feedstock storage tanks located at our Corpus Christi West, Texas City and Benicia Refineries for $200 million. We also sold to Valero L.P. a refined products pipeline system for $150 million. This three-pipeline system connects our Corpus Christi East, Corpus Christi West and Three Rivers Refineries to markets in Houston, San Antonio and the Texas Rio Grande Valley. The sale of the storage tank assets and the pipeline system resulted in proceeds in excess of the carrying amounts of those assets of $181 million. No immediate gain was recognized as a result of these transactions. Because of our continuing equity ownership interest in Valero L.P., $90 million of this excess was recorded as a reduction to our investment in Valero L.P. and is being amortized over the lives of the assets sold. The remaining $91 million was deferred and recorded in “other long-term liabilities” and is being amortized over the life of certain throughput, handling, terminalling and service agreements discussed in “Related-Party Transactions” below, which was approximately 10 years from the date of these asset sales.
On April 16, 2003, 581,000 additional common units of Valero L.P. were issued as a result of the exercise by the underwriters of a portion of their overallotment option related to the March 18, 2003 common unit issuance, reducing our ownership interest from 49.5% to 48.2%.
In August 2003, Valero L.P. closed on a public offering of common units, selling 1,236,250 common units to the public at $41.15 per unit, before underwriter’s discount of $1.85 per unit. Net proceeds from this common unit offering, which further reduced our ownership interest in Valero L.P. to slightly below 46%, were partially used by Valero L.P. to fund its purchase from us of the Southlake refined products pipeline for $30 million. Our gain on this sale of $2 million was deferred and is being recognized over future periods, with $1 million recorded as a reduction to our investment in Valero L.P. and $1 million recorded as a deferred credit in “other long-term liabilities.”
Effective March 11, 2004, Valero L.P. amended its partnership agreement as follows:
    capped the general partner’s distribution, including incentive distributions, at 25% for all distributions in excess of $0.66 per unit per quarter and
 
    reduced the minimum vote required to remove the general partner from 58% to a simple majority of Valero L.P.’s outstanding common and subordinated units, excluding the units held by our affiliates.
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 and a 21.4% limited partner interest represented by 622,772 common units and 9,599,322 subordinated units of Valero L.P.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Valero L.P. has issued common units to the public, which have diluted our ownership percentage, on three separate occasions. Such issuances have resulted in increases 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. 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 directly in equity.
As of December 31, 2004, prior to Valero L.P.’s Kaneb Acquisition, we had $7 million in accumulated pre-tax SAB 51 credits related to our investment in Valero L.P. On July 1, 2005, the issuance of common units by Valero L.P. in connection with the Kaneb Acquisition generated an additional pre-tax SAB 51 credit of $151 million for us. We have not recognized any SAB 51 credits in our consolidated financial statements through December 31, 2005 and are not permitted to do so until our subordinated units convert to common units, which is expected to occur in the second quarter of 2006. We expect to adopt our accounting policy and recognize all of our cumulative SAB 51 credits at that time.
Summary Financial Information
Financial information reported by Valero L.P. is summarized below (in millions):
                 
    December 31,  
    2005     2004  
Current assets
  $ 295     $ 40  
Property and equipment, net
    2,160       785  
Other long-term assets
    912       32  
 
           
Total assets
  $ 3,367     $ 857  
 
           
 
               
Current liabilities
  $ 206     $ 34  
Long-term debt, less current portion
    1,170       384  
Other long-term liabilities
    90       1  
 
           
Total liabilities
    1,466       419  
Partners’ equity
    1,901       438  
 
           
Total liabilities and partners’ equity
  $ 3,367     $ 857  
 
           
                         
    Year Ended December 31,
    2005   2004   2003
Revenues
  $ 660     $ 221     $ 181  
Operating income
    154       98       83  
Net income
    111       78       70  
Related-Party Transactions
In connection with the sale of the crude oil and intermediate feedstock storage tanks and the three-pipeline system discussed above, we entered into certain throughput, handling, terminalling and service agreements with Valero L.P. In addition, we have other related-party transactions with Valero L.P. for the use of Valero L.P.’s pipelines, terminals and crude oil storage tank facilities. Under various agreements, we have agreed to use Valero L.P.’s pipelines to transport crude oil shipped to and refined products shipped from certain of our

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
refineries and to use Valero L.P.’s refined product terminals for certain terminalling services. In addition, we provide personnel to Valero L.P. to perform operating and maintenance services with respect to certain assets for which we receive reimbursement from Valero L.P. We have indemnified Valero L.P. for certain environmental liabilities related to assets we 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. Beginning March 18, 2003, the date we ceased consolidating 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.
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 annual fee (Administrative Fee). Effective January 1, 2006, the Administrative Fee was amended and now provides 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 new services agreement provides for an annual fee of approximately $2 million for 2006. The annual fee will increase to approximately $3 million for 2007 and will remain at approximately $3 million through the initial term of the agreement, which expires in December 2010. The annual fee may be adjusted for changed service levels. The Administrative Fee is recorded as a reduction of “general and administrative expenses.”
As of December 31, 2005 and 2004, our “receivables, net” included $13 million and $4 million, respectively, from Valero L.P., representing amounts due for employee costs, insurance costs, operating expenses, administrative costs and rentals. As of December 31, 2005 and 2004, our “accounts payable” included $22 million and $19 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):
                         
    Year Ended December 31,
    2005   2004   2003
Expenses charged by us to Valero L.P.
  $ 80     $ 42     $ 30  
Fees and expenses charged to us by Valero L.P.
    234       218       179  
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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Other
As of December 31, 2005 and 2004, 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 (2005) and 664,119 (2004) of Valero L.P.’s common units) reconciles to Valero L.P.’s total partners’ equity as follows (in millions):
                 
    December 31,  
    2005     2004  
Valero L.P. total partners’ equity
  $ 1,901     $ 438  
Valero’s ownership interest in Valero L.P.
    23.4 %     45.7 %
 
           
Valero’s equity in Valero L.P.’s partners’ equity
    445       200  
Unrecognized SAB 51 gains
    (158 )     (7 )
Excess of proceeds over carrying amount of our retained interest in assets sold to Valero L.P., net
    (82 )     (85 )
Step-up in basis related to Valero L.P.’s assets and liabilities, including equity method goodwill
    122       157  
 
           
Investment in Valero L.P.
  $ 327     $ 265  
 
           
As reflected above, as of December 31, 2005 and 2004, our investment in Valero L.P. included 622,772 and 664,119 publicly traded common units, respectively, which had an aggregate market value of $32 million and $40 million, respectively. A quoted market price is not available for our 2% general partner interest, the incentive distribution rights and the 9,599,322 subordinated units we hold.
10. DEFERRED CHARGES AND OTHER ASSETS
Cameron Highway Oil Pipeline Project
Effective July 10, 2003, we became a 50% interest owner 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 sheet. In June 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, 2005 and 2004, our investment in the Cameron Highway Oil Pipeline Project totaled $87 million and $140 million, respectively.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 21. During 2005, no additional costs were incurred by us in connection with the termination of our participation in the Clear Lake joint venture.
Sale of Equity Interest in Javelina Joint Venture
As discussed in Note 2, in November 2005 we sold our 20% equity interests in the Javelina Companies for $78 million, recognizing a gain of $55 million. As of December 31, 2004, our investment in the Javelina Companies was $25 million.
Tesoro Notes Receivable
In conjunction with the UDS Acquisition, the Federal Trade Commission approved a consent decree requiring the divestiture of certain UDS assets. Those assets and their related operations were referred to as the Golden Eagle Business and included the 168,000 barrel-per-day Golden Eagle Refinery, the related wholesale marketing business and branded retail stores located in northern California.
In May 2002, the Golden Eagle Business was sold to Tesoro Refining and Marketing Company (Tesoro). We received cash proceeds of $925 million and two ten-year junior subordinated notes with face amounts totaling $150 million. In November 2003, the Tesoro notes were sold to various investors. We received net proceeds of $90 million. The net book value of the notes at the time of sale was $73 million, resulting in a gain of $17 million which was reported in “other income (expense), net” in the consolidated statement of income for the year ended December 31, 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. ACCRUED EXPENSES
Accrued expenses consisted of the following (in millions):
                 
    December 31,  
    2005     2004  
Accrued employee wage and benefit costs
  $ 212     $ 150  
Accrued interest expense
    91       63  
Contingent earn-out payments
    75       50  
Derivative liabilities
    68       142  
Accrued environmental costs
    39       23  
Other
    96       91  
 
           
Accrued expenses
  $ 581     $ 519  
 
           
The increase in accrued employee wage and benefit costs is due mainly to year-end bonus and retention bonus accruals as of December 31, 2005 resulting from the Premcor Acquisition. The decrease in derivative liabilities resulted from a decrease in unrealized losses on cash flow hedge derivative activity primarily related to forward sales of distillates and associated forward purchases of crude oil. The increase in accrued interest expense is due primarily to the debt assumed in the Premcor Acquisition. Accrued expenses for contingent earn-out payments resulted from the purchase price allocation for the Premcor and St. Charles Acquisitions as discussed in Notes 2 and 23. Included in other accrued expenses are accruals for capital expenditures, legal and regulatory liabilities, insurance, operating leases and miscellaneous accruals for refining and retail operations.

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12. DEBT
Long-term debt balances, at stated values, consisted of the following (in millions):
                         
            December 31,  
    Maturity     2005     2004  
Industrial revenue bonds:
                       
Tax-exempt Revenue Refunding Bonds (a):
                       
Series 1997A, 5.45%
    2027     $ 24     $ 24  
Series 1997B, 5.40%
    2018       33       33  
Series 1997C, 5.40%
    2018       33       33  
Series 1997D, 5.125%
    2009       9       9  
Tax-exempt Waste Disposal Revenue Bonds:
                       
Series 1997, 5.6%
    2031       25       25  
Series 1998, 5.6%
    2032       25       25  
Series 1999, 5.7%
    2032       25       25  
Series 2001, 6.65%
    2032       19       19  
CORE notes, 6.311%
    2007       50       50  
3.50% notes
    2009       200       200  
4.75% notes
    2013       300       300  
4.75% notes
    2014       200       200  
6.125% notes
    2007       230       272  
6.797% notes
    2005             14  
6.875% notes
    2012       750       750  
7.375% notes
    2006       220       259  
7.50% notes
    2032       750       750  
8.375% notes
    2005             200  
8.75% notes
    2030       200       200  
Medium-term Notes:
                       
7.44% (average rate)
    2005             46  
8.0%
    2005             150  
Debentures:
                       
7.25% (non-callable)
    2010       25       25  
7.65% (putable July 1, 2006)
    2026       100       100  
8.75% (non-callable)
    2015       75       75  
Senior Notes:
                       
6.125% notes
    2011       200        
6.70% notes
    2013       180       180  
6.75% notes
    2011       210        
6.75% notes
    2014       200        
6.75% (putable October 15, 2009; callable thereafter)
    2037       100       100  
7.20% (callable)
    2017       200       200  
7.45% (callable)
    2097       100       100  
7.50% notes
    2015       300        
9.25% notes
    2010       175        
9.50% notes
    2013       350        
Other
  Various     14       13  
Net unamortized premium (discount), including fair market value adjustments
            6       (73 )
 
                   
Total debt
            5,328       4,304  
Less current portion, including unamortized (discount) premium of $(1) and $1
            (219 )     (411 )
 
                   
Long-term debt, less current portion
          $ 5,109     $ 3,893  
 
                   
 
(a)   The maturity dates reflected for the Series 1997A, 1997B, and 1997C tax-exempt revenue refunding bonds represent their final maturity dates; however, principal payments on these bonds commence in 2010.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Revolving Bank Credit Facilities
As of December 31, 2004, 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. During the year ended December 31, 2005, we borrowed and repaid $40 million under these revolving bank credit facilities. As of December 31, 2004, there were no borrowings outstanding under these two revolving credit facilities and outstanding letters of credit issued under the facilities totaled $279 million.
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 matures in August 2010. Borrowings under the Revolver bear interest at LIBOR plus a margin, or an alternate base rate as defined under the agreement. We will also be 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 includes certain restrictive covenants including a coverage ratio and a debt-to-capitalization ratio. As of December 31, 2005, there were no borrowings outstanding under the Revolver and outstanding letters of credit issued under this facility totaled $254 million.
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, 2005 and 2004, we had no borrowings outstanding and Cdn. $8 million of letters of credit issued under this credit facility.
We also have various uncommitted short-term bank credit facilities. As of December 31, 2005 and 2004, we had no borrowings outstanding under our uncommitted short-term bank credit facilities; however, there were $232 million and $218 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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:
                         
    Maturity     Par     Fair Value  
Senior notes:
                       
6.125%
    2011     $ 200     $ 201  
6.75%
    2011       210       218  
6.75%
    2014       200       204  
7.5%
    2015       300       317  
9.25%
    2010       175       192  
9.5%
    2013       350       396  
12.5%
    2009       161       182  
7.75% senior subordinated notes
    2012       175       192  
Ohio Water Development Authority Environmental Facilities Revenue Bonds
    2031       10       10  
 
                   
 
                       
Debt assumed
          $ 1,781     $ 1,912  
 
                   
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.
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
In December 2004, we repurchased $41 million of the 7.375% notes due in March 2006 and $28 million of the 6.125% notes due in April 2007. A premium of $4 million was paid and expensed in the fourth quarter of 2004 as a result of the early redemption of these notes. 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.
On March 29, 2004, we borrowed $200 million under a five-year term loan, with a maturity date of March 31, 2009 and bearing interest based on our debt rating. Principal payments were scheduled to begin March 2007

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with a $50 million principal payment due at that time and semi-annual payments of $38 million due thereafter until maturity. The net proceeds from this borrowing were used to repay borrowings under our revolving bank credit facilities. In December 2004, we repaid the entire outstanding balance of the term loan.
On March 22, 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 under our prior shelf registration statement (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.
In August 2003, $14 million of 6.797% notes became outstanding as a result of the cash settlement of certain purchase contract obligations associated with our PEPS Units. See Note 14 below for a further discussion of the PEPS Units and the resulting $14 million of outstanding notes.
On June 4, 2003, we issued $300 million of 4.75% notes due June 15, 2013 under our prior shelf registration statement. Interest is payable semi-annually. The notes are unsecured and are redeemable, in whole or in part, at our option. The net proceeds from this offering of $297 million were used to redeem $200 million of TOPrS discussed below in Note 14 and $100 million of 8% debentures due 2023. A premium of $4 million was paid and expensed in the second quarter of 2003 as a result of the early redemption of the 8% debentures.
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, 2005 were as follows (in millions):
         
2006
  $ 220  
2007
    287  
2008
    6  
2009
    209  
2010
    208  
Thereafter
    4,392  
Net unamortized premium and fair value adjustments
    6  
 
     
Total
  $ 5,328  
 
     
As of December 31, 2005 and 2004, the estimated fair value of our long-term debt, including current portion, was as follows (in millions):
                 
    December 31,
    2005   2004
Carrying amount
  $ 5,328     $ 4,304  
Fair value
    5,735       4,790  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. OTHER LONG-TERM LIABILITIES
Other long-term liabilities consisted of the following (in millions):
                 
    December 31,  
    2005     2004  
Employee benefit plan liabilities
  $ 722     $ 450  
Environmental liabilities
    255       182  
Insurance liabilities
    113       80  
Contingent earn-out payments
    100       125  
Deferred gain on sale of assets to Valero L.P.
    66       76  
Unfavorable lease obligations
    52       45  
Asset retirement obligations
    51       41  
Tax liabilities other than income taxes
    50       33  
Other
    193       116  
 
           
Other long-term liabilities
  $ 1,602     $ 1,148  
 
           
Employee benefit plan liabilities include the long-term obligation for our pension and other postretirement benefit plans as discussed in Note 22. Environmental liabilities reflect the long-term portion of our estimated remediation costs for environmental matters as discussed in Note 24. 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. The liability for contingent earn-out payments resulted from the purchase price allocation for the Premcor and St. Charles Acquisitions. Deferred gain reflects the unamortized balance of a portion of the proceeds in excess of the carrying amount of assets we sold to Valero L.P. as discussed in Note 9. See Note 1 under “Asset Retirement Obligations” for a discussion of the liability related to asset retirement obligations reflected in the table above. 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.
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. In June 2003, we purchased certain convenience stores which were subject to structured lease arrangements for $215 million, of which $88 million was recorded as a reduction of the unfavorable lease obligation recorded in connection with the UDS Acquisition. Included in “other” are liabilities for various matters including legal and regulatory liabilities, derivative obligations and various contractual obligations. The increase in other long-term liabilities from December 31, 2004 to December 31, 2005 is primarily attributable to $361 million of long-term liabilities assumed in the Premcor Acquisition, as reflected in Note 2.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. COMPANY-OBLIGATED PREFERRED SECURITIES OF SUBSIDIARY TRUSTS
TOPrS
In conjunction with the UDS Acquisition, we assumed $200 million of 8.32% Trust Originated Preferred Securities (TOPrS) (8,000,000 units at $25.00 per unit), which were issued by UDS Capital I (the Trust). Distributions on the TOPrS were cumulative and payable quarterly in arrears if and when the Trust had funds available for distribution. In June 2003, the TOPrS were redeemed with proceeds from the issuance of $300 million of 4.75% notes as described in Note 12.
PEPS Units
In June 2000, we issued $173 million of Premium Equity Participating Securities (PEPS Units) under a shelf registration statement (6,900,000 units at $25.00 per unit). Upon issuance, each PEPS Unit consisted of a trust preferred security issued by VEC Trust I and an associated purchase contract obligating the holder of the PEPS Unit to purchase on August 18, 2003 a number of shares of common stock from us for $25 per purchase contract. The number of shares of common stock issuable for each purchase contract was to be determined at a price based on the average price of our common stock for the relevant 20-day trading period. Under the original agreement, holders of PEPS Units could settle their purchase contracts by paying us cash or by remarketing their pledged trust preferred securities and using the proceeds from the remarketing to settle the purchase contracts. In accordance with the original agreement, the distribution rate on the trust preferred securities, which was 7.75% on date of issuance, was to be reset on August 18, 2003 based on the price for which the trust preferred securities were remarketed. In accordance with the terms of the trust, on August 12, 2003, we dissolved the trust and substituted our senior deferrable notes for the trust preferred securities. As a result, our senior deferrable notes were scheduled to be remarketed in place of the trust preferred securities, with the interest rate on the senior deferrable notes to be reset on August 18, 2003 based upon the price for which the senior deferrable notes were remarketed.
The remarketing of the senior deferrable notes was scheduled for August 13, 2003. The holders of approximately 6.36 million PEPS Units opted to settle their purchase contract obligations by remarketing the senior deferrable notes (totaling $159 million), while holders of approximately 0.54 million PEPS Units elected to settle their purchase contract obligations with cash and retain their senior deferrable notes (totaling $14 million) in lieu of participating in the remarketing. On August 13, we received notice from the remarketing agent that a failed remarketing (as defined in the prospectus supplement related to the PEPS Units) of the senior deferrable notes was deemed to have occurred. The $159 million of senior deferrable notes surrendered to us to satisfy the holders’ purchase contract obligations were retained by us in full satisfaction of the holders’ obligations under the purchase contracts and were canceled on August 18, 2003. The remaining $14 million of senior deferrable notes matured and were repaid on August 18, 2005 and bore interest at a rate of 6.797%. We, in turn, issued 20 million shares of our common stock at a price of $8.74 per share in settlement of the 6.9 million purchase contracts.
Prior to the issuance of shares of our common stock upon settlement of the purchase contract obligations, the number of shares of our common stock included in the calculation of “earnings per common share – assuming dilution” for each reporting period was calculated using the treasury stock method. For this purpose, the number of shares to be issued pursuant to the purchase contract obligations was based on the applicable conversion formula in the PEPS Unit agreement, using the average closing price of our common stock over the 20-day trading period ending on the third trading day prior to the end of the reporting period.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. STOCKHOLDERS’ EQUITY
Share Activity
For the years ended December 31, 2005, 2004 and 2003, activity in the number of shares of preferred stock, common stock and treasury stock was as follows (in millions):
                         
    Preferred Stock     Common Stock     Treasury Stock  
Balance as of December 31, 2002
          433       (4 )
Sale of common stock
          25        
Issuance of preferred stock in connection with St. Charles Acquisition
    10              
Settlement of stock purchase contracts under PEPS Units
          20        
Shares repurchased and shares issued in connection with employee stock plans and other
          7       1  
 
                 
Balance as of December 31, 2003
    10       485       (3 )
Sale of common stock
          31        
Shares repurchased and shares issued in connection with employee stock plans and other
          6       (8 )
 
                 
Balance as of December 31, 2004
    10       522       (11 )
Conversion of preferred stock
    (7 )     14        
Issuance of common stock in connection with Premcor Acquisition
          85        
Shares repurchased and shares issued in connection with employee stock plans and other
                7  
 
                 
Balance as of December 31, 2005
    3       621       (4 )
 
                 
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 $21 million preferred stock discount is being amortized as additional preferred stock dividends through June 30, 2006, the day before the mandatory conversion of the preferred stock as discussed below.
The mandatory convertible preferred stock will automatically convert to our common stock on July 1, 2006, unless converted sooner. We pay annual dividends of $0.50 for each share of convertible preferred stock when and if declared by our board of directors. Dividends are paid quarterly, provided that dividends will not accrue or be payable with respect to a particular calendar quarter if we do not declare a dividend on our common stock during that calendar quarter. The convertible preferred stock ranks with respect to dividend rights and rights upon our liquidation, winding-up or dissolution as follows:
  (i)   senior to all common stock and to all other capital stock issued by us in the future that ranks junior to the convertible preferred stock;

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  (ii)   on a parity with any of our capital stock issued in the future the terms of which expressly provide that it will rank on a parity with the convertible preferred stock; and
 
  (iii)   junior to all of our capital stock the terms of which expressly provide that such capital stock will rank senior to the convertible preferred stock.
The holders of the convertible preferred stock will generally be entitled to vote with our common stock and not as a separate class and have a number of votes equal to the mandatory conversion ratio that would be in effect if the mandatory conversion date was the record date of such vote. The affirmative vote of holders of 66-2/3% of the convertible preferred stock is necessary to make any change to the certificate of incorporation or the bylaws that would adversely affect any power, preference or special right of the convertible preferred stock.
Upon automatic conversion of the convertible preferred stock on July 1, 2006, the number of shares of common stock to be received for each share of convertible preferred stock shall be calculated based on the “applicable market value” (as defined) of our common stock, which, as a result of the two common stock splits discussed in Note 15, is four times 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, as follows:
    2.676 shares if the applicable market value is less than or equal to $37.37;
 
    a number of shares having a value of $25 if the applicable market value is between $37.37 and $50.45; or
 
    1.982 shares if the applicable market value is greater than $50.45.
Each share of convertible preferred stock is convertible, at the option of the holder, at any time before July 1, 2006 into 1.982 shares of our common stock. The number of shares to be received upon conversion of a share of the convertible preferred stock is subject to adjustment upon the occurrence of certain events. During the third quarter of 2003, we filed a registration statement to register the mandatory convertible preferred stock and the common stock issuable upon the conversion of the convertible preferred stock. The registration statement was declared effective on October 16, 2003. During 2005, 6,835,849 shares of the preferred stock were converted into 13,548,636 shares of our common stock. During January and February of 2006, 712,960 additional shares of the preferred stock were converted into 1,413,085 shares of our common stock.
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 will be based on the above conversion formula using 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.
On January 19, 2006, our board of directors declared a dividend on the mandatory convertible preferred stock of $0.125 per share payable on March 31, 2006 to holders of record on March 30, 2006.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 under our prior shelf registration statement to partially fund the Aruba Acquisition discussed in Note 2.
On March 28, 2003, we sold in a public offering 25 million shares of our common stock at a price of $10.06 per share and received net proceeds of $250 million. These shares were issued under our prior shelf registration statement. The proceeds were used to repay borrowings under our revolving bank credit facilities.
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.
All share and per share data (except par value) have been adjusted to reflect the effect of the stock splits for all periods presented. 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.
Common Stock Purchases
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, 2005, 2004 and 2003, we expended $571 million, $318 million and $73 million, respectively, for the purchase of 13 million, 19 million and 7 million shares of our common stock, respectively. Through February 24, 2006, we purchased in the open market an additional 3.7 million common shares at a cost of $199 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Common Stock Dividends
On January 19, 2006, our board of directors declared a regular quarterly cash dividend of $0.06 per common share payable March 15, 2006 to holders of record at the close of business on February 15, 2006.
Accumulated Other Comprehensive Income
Accumulated balances for each component of accumulated other comprehensive income (loss) were as follows (in millions):
                                 
    Foreign     Minimum     Net Gain     Accumulated  
    Currency     Pension     (Loss) On     Other  
    Translation     Liability     Cash Flow     Comprehensive  
    Adjustment     Adjustment     Hedges     Income (Loss)  
Balance as of December 31, 2002
  $ 13     $ (14 )   $     $ (1 )
2003 change
    163       5       3       171  
 
                       
Balance as of December 31, 2003
    176       (9 )     3       170  
2004 change
    111             (52 )     59  
 
                       
Balance as of December 31, 2004
    287       (9 )     (49 )     229  
2005 change
    54       (1 )     53       106  
 
                       
Balance as of December 31, 2005
  $ 341     $ (10 )   $ 4     $ 335  
 
                       

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
16. EARNINGS PER SHARE
Earnings per common share amounts were computed as follows (dollars and shares in millions, except per share amounts):
                         
    Year Ended December 31,  
    2005     2004     2003  
Earnings per Common Share:
                       
Net income
  $ 3,590     $ 1,804     $ 622  
Preferred stock dividends
    13       13       5  
 
                 
Net income applicable to common stock
  $ 3,577     $ 1,791     $ 617  
 
                 
 
                       
Weighted-average common shares outstanding
    549       510       459  
 
                 
 
                       
Earnings per common share
  $ 6.51     $ 3.51     $ 1.34  
 
                 
 
                       
Earnings per Common Share — Assuming Dilution:
                       
Net income applicable to common equivalent shares
  $ 3,590     $ 1,804     $ 622  
 
                 
 
                       
Weighted-average common shares outstanding
    549       510       459  
Effect of dilutive securities:
                       
Stock options
    21       16       12  
Performance awards and other benefit plans
    6       6       5  
PEPS Units
                1  
Mandatory convertible preferred stock
    12       20       11  
 
                 
Weighted-average common equivalent shares outstanding
    588       552       488  
 
                 
 
                       
Earnings per common share — assuming dilution
  $ 6.10     $ 3.27     $ 1.27  
 
                 
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):
                         
    Year Ended December 31,
    2005   2004   2003
Stock options
    3       5       7  
Based on the average market price of our common stock during January 2006, all stock options outstanding as of December 31, 2005 subsequently have become dilutive.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. 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):
                         
    Year Ended December 31,  
    2005     2004     2003  
Decrease (increase) in current assets:
                       
Restricted cash
  $ 192     $ 19     $ 7  
Receivables, net
    (834 )     (419 )     262  
Inventories
    372       (211 )     (270 )
Prepaid expenses and other
    217       (2 )     (5 )
Increase (decrease) in current liabilities:
                       
Accounts payable
    1,126       495       416  
Accrued expenses
    (116 )     15       32  
Taxes other than income taxes
    28       98       (27 )
Income taxes payable
    97       208       14  
 
                 
Changes in current assets and current liabilities
  $ 1,082     $ 203     $ 429  
 
                 
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;
 
    the amounts shown above exclude the current assets and current liabilities acquired in connection with the Premcor Acquisition and certain minor acquisitions in 2005, the Aruba Acquisition in 2004 and the St. Charles Acquisition in 2003, 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, and the effect of certain noncash investing and financing activities discussed below; 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, 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 15, and
 
    the recognition of a $28 million capital lease obligation and related capital lease asset pertaining to certain equipment at our Texas City Refinery.
Noncash investing activities for the years ended December 31, 2005 and 2004 included various 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 also included adjustments to property, plant and equipment and certain

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 discussed in Note 2). There were no significant noncash financing activities for the year ended December 31, 2004.
Noncash investing and financing activities for the year ended December 31, 2003 included:
    the issuance of 18 million shares of common stock in exchange for the settlement of 6.36 million PEPS Unit purchase contracts under the remarketing election;
 
    the issuance of 2% mandatory convertible preferred stock with a fair value of $220 million as partial consideration for the acquisition of the St. Charles Refinery from Orion;
 
    the recognition of a $30 million asset retirement obligation and associated asset retirement cost in accordance with FASB Statement No. 143; and
 
    adjustments to property, plant and equipment, goodwill, and certain current and noncurrent assets and liabilities associated with the change to cease consolidation of Valero L.P. and use the equity method to account for our investment in Valero L.P. effective March 18, 2003.
Cash flows related to interest and income taxes were as follows (in millions):
                         
    Year Ended December 31,
    2005   2004   2003
Interest paid (net of amount capitalized)
  $ 251     $ 246     $ 257  
Income taxes paid, net of tax refunds received
    1,345       352       64  
18. 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.
Interest Rate Risk
We are exposed to market risk for changes in interest rates related to certain of our long-term debt obligations. Interest rate swap agreements are used to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
On March 25, 2004, we entered into interest rate swap contracts with a total notional amount of $200 million to hedge against changes in interest rates. These interest rate swap contracts have the effect of converting the $200 million of 4.75% Senior Notes from fixed-rate 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 are accounted for as fair value hedges.
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, 2005, we had commitments to purchase $303 million of U.S. dollars. These commitments matured on or before January 27, 2006, resulting in a loss of less than $1 million.
Current Period Disclosures
The net gain (loss) recognized in income representing the amount of hedge ineffectiveness was as follows (in millions):
                         
    Year Ended December 31,
    2005   2004   2003
Fair value hedges
  $ 16     $ (1 )   $ 5  
Cash flow hedges
    21       (10 )     4  
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. We also recognized in “cost of sales” $6 million of pre-tax losses associated with trading activities.
For cash flow hedges, gains and losses currently reported in “accumulated other comprehensive income” in the consolidated balance sheets will be reclassified into “cost of sales” when the forecasted transactions affect income. During the years ended December 31, 2005 and 2004, we recognized in “accumulated other comprehensive income” unrealized after-tax losses of $218 million and $168 million, respectively, on certain cash flow hedges, primarily related to forward sales of distillates and associated forward purchases of crude oil, with $4 million and $49 million, respectively, of deferred after-tax gains on cash flow hedges remaining in “accumulated other comprehensive income” as of December 31, 2005 and 2004. These deferred gains at December 31, 2005 will be reclassified into “cost of sales” in 2006 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, 2005, 2004 and 2003, there were no amounts reclassified from “accumulated other comprehensive income” into income as a result of the discontinuance of cash flow hedge accounting.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
19. 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.
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).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
20. INCOME TAXES
Components of income tax expense (benefit) were as follows (in millions):
                         
    Year Ended December 31,  
    2005     2004     2003  
Current:
                       
U.S. federal
  $ 1,151     $ 361     $ (28 )
U.S. state
    102       41       8  
Canada
    187       159       98  
Aruba
    2              
 
                 
Total current
    1,442       561       78  
 
                 
 
                       
Deferred:
                       
U.S. federal
    308       343       241  
U.S. state
    (19 )     26       31  
Canada
    (35 )     (24 )     15  
Aruba
    1              
 
                 
Total deferred
    255       345       287  
 
                 
 
                       
Income tax expense
  $ 1,697     $ 906     $ 365  
 
                 
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):
                         
    Year Ended December 31,  
    2005     2004     2003  
Federal income tax expense at the U.S. statutory rate
  $ 1,851     $ 949     $ 345  
U.S. state income tax expense, net of U.S. federal income tax effect
    54       43       26  
Canadian operations
    (7 )     (10 )     (9 )
Aruban operations
    (193 )     (88 )      
Other, net
    (8 )     12       3  
 
                 
Income tax expense
  $ 1,697     $ 906     $ 365  
 
                 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Aruba Refinery’s results of operations 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 $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, 2005 and December 31, 2004, respectively.
Income before income tax expense from domestic and foreign operations was as follows (in millions):
                         
    Year Ended December 31,  
    2005     2004     2003  
U.S. operations
  $ 4,274     $ 2,041     $ 640  
Canadian operations
    452       416       347  
Aruban operations
    561       253        
 
                 
Income before income tax expense
  $ 5,287     $ 2,710     $ 987  
 
                 
The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows (in millions):
                 
    December 31,  
    2005     2004  
Deferred income tax assets:
               
Tax credit carryforwards
  $ 50     $ 186  
Net operating losses (NOL)
    72       46  
Compensation and employee benefit liabilities
    242       144  
Environmental
    98       55  
Inventories
    135       64  
Excess of tax basis over book basis in property, plant and equipment
    9        
Other assets
    307       115  
 
           
Total deferred income tax assets
    913       610  
Less: Valuation allowance
    (86 )     (83 )
 
           
Net deferred income tax assets
    827       527  
 
           
 
               
Deferred income tax liabilities:
               
Turnarounds
    (177 )     (109 )
Excess of book basis over tax basis in property, plant and equipment
    (3,844 )     (2,108 )
Inventories
    (372 )     (44 )
Other
    (212 )     (102 )
 
           
Total deferred income tax liabilities
    (4,605 )     (2,363 )
 
           
 
               
Net deferred income tax liabilities
  $ (3,778 )   $ (1,836 )
 
           

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2005, we had the following U.S. federal and state income tax credit and loss carryforwards (in millions):
             
    Amount   Expiration
U.S. state income tax credits
  $ 29     2006 through 2013
Foreign tax credit
    31     2011
U.S. state NOL
    1,790     2006 through 2025
We have recorded a valuation allowance as of December 31, 2005 and 2004, 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, 2005 is dependent upon our ability to generate future taxable income in the United States, Canada and Aruba.
Subsequently recognized tax benefits related to the valuation allowance for deferred tax assets as of December 31, 2005 will be allocated as follows (in millions):
         
Income tax benefit in consolidated statement of income
  $ 33  
Goodwill
    48  
Additional paid-in capital
    5  
 
       
Total
  $ 86  
 
       
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, 2005, the cumulative undistributed earnings of these subsidiaries were approximately $1.9 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. However, 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 are currently under examination. 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.
21. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
                                 
    Refining   Retail   Corporate   Total
    (in millions)
Year ended December 31, 2005:
                               
Operating revenues from external customers
  $ 74,710     $ 7,452     $     $ 82,162  
Intersegment revenues
    4,971                   4,971  
Depreciation and amortization expense
    722       83       70       875  
Operating income (loss)
    5,846       141       (528 )     5,459  
Total expenditures for long-lived assets
    2,384       106       87       2,577  
 
                               
Year ended December 31, 2004:
                               
Operating revenues from external customers
    48,371       6,248             54,619  
Intersegment revenues
    3,782                   3,782  
Depreciation and amortization expense
    518       58       42       618  
Operating income (loss)
    3,225       175       (421 )     2,979  
Total expenditures for long-lived assets
    1,396       167       35       1,598  
 
                               
Year ended December 31, 2003:
                               
Operating revenues from external customers
    32,455       5,514             37,969  
Intersegment revenues
    2,958                   2,958  
Depreciation and amortization expense
    417       40       54       511  
Operating income (loss)
    1,363       212       (353 )     1,222  
Total expenditures for long-lived assets
    999       109       28       1,136  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Our principal products include conventional, reformulated and CARB gasolines, 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. All revenues related to crude oil buy/sell arrangements have been included in the refining segment in the “other product revenues” line in the table below. 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, 2005, 2004 and 2003 were as follows (in millions):
                         
    Year Ended December 31,  
    2005     2004     2003  
Refining:
                       
Gasolines and blendstocks
  $ 34,314     $ 21,984     $ 15,705  
Distillates
    22,904       12,874       7,851  
Petrochemicals
    2,768       1,636       905  
Lubes and asphalts
    1,575       1,156       1,046  
Other product revenues
    13,149       10,721       6,948  
 
                 
Total refining operating revenues
    74,710       48,371       32,455  
 
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