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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, 2007
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 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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company 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 $40.9 billion based on the last sales price quoted as of June 29, 2007 on the New York Stock Exchange, the last business day of the registrant’s most recently completed second fiscal quarter.
As of January 31, 2008, 534,652,367 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 a definitive Proxy Statement for our Annual Meeting of Stockholders scheduled for May 1, 2008, at which directors will be elected. Portions of the 2008 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 2008 Proxy Statement where certain information required in Part III of Form 10-K may be found.
     
Form 10-K Item No. and Caption   Heading in 2008 Proxy Statement
 
   
10.     Directors, Executive Officers and Corporate Governance
  Information Regarding the Board of Directors, Independent Directors, Audit Committee, Governance Documents and Codes of Ethics, 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 Discussion and Analysis, Director Compensation, 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, and Director Independence
  Certain Relationships and Related Transactions and Independent Directors
 
   
14.     Principal Accountant Fees and Services
  KPMG Fees for Fiscal Year 2007, KPMG Fees for Fiscal Year 2006, 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, Senior Vice President-Corporate Law and Secretary, Valero Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-6000.

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CONTENTS
             
        PAGE
           
  Business, Risk Factors and Properties     1  
 
       Segments     1  
 
       Valero’s Operations     2  
 
       Risk Factors     11  
 
       Environmental Matters     13  
 
       Properties     13  
 
       Executive Officers of the Registrant     14  
  Unresolved Staff Comments     14  
  Legal Proceedings     15  
  Submission of Matters to a Vote of Security Holders     16  
 
           
           
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     17  
  Selected Financial Data     20  
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     21  
  Quantitative and Qualitative Disclosures About Market Risk     45  
  Financial Statements and Supplementary Data     50  
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     124  
  Controls and Procedures     124  
  Other Information     124  
 
           
           
  Directors, Executive Officers and Corporate Governance     125  
  Executive Compensation     125  
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     125  
  Certain Relationships and Related Transactions , and Director Independence     125  
  Principal Accountant Fees and Services     125  
 
           
           
  Exhibits and Financial Statement Schedules     125  
 
           
        130  

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PART I
The terms “Valero,” “we,” “our,” and “us,” as used in this report, may refer to Valero Energy Corporation, to one or more of our consolidated subsidiaries, or to all of them taken as a whole. In this Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources, under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. You should read our forward-looking statements together with our disclosures beginning on page 21 below 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 corporate 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, and our name was changed to Valero Energy Corporation on August 1, 1997. On January 31, 2008, we had 21,651 employees.
We own and operate 17 refineries located in the United States, Canada, and Aruba that produce conventional gasolines, distillates, jet fuel, asphalt, petrochemicals, lubricants, and other refined products as well as a slate of premium products including RBOB1, gasoline meeting the specifications of the California Air Resources Board (CARB), CARB diesel fuel, low-sulfur and ultra-low-sulfur diesel fuel, and oxygenates (liquid hydrocarbon compounds containing oxygen).
We 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 about 5,800 retail and wholesale branded outlets in the United States, Canada, and Aruba.
Available Information. Our internet website address is www.valero.com. Information contained on our website is not part of this annual report on Form 10-K. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K filed with (or furnished to) the Securities and Exchange Commission (SEC) are available on our internet website (in the “Investor Relations” section), free of charge, soon after we file or furnish such material. We also post our corporate governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers, and the charters of the committees of our board of directors in the same website location. Our governance documents are available in print to any stockholder that makes a written request to Jay D. Browning, Senior Vice President-Corporate Law and Secretary, Valero Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-6000.
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.
 
1   RBOB is a base unfinished reformulated gasoline mixture known as “reformulated gasoline blendstock for oxygenate blending” or “RBOB.”

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Our retail segment includes company-operated convenience stores, Canadian dealers/jobbers, truckstop facilities, cardlock facilities, and home heating oil operations. The retail segment is segregated into two geographic regions. Our retail operations in eastern Canada are referred to as Retail - Canada. Our retail operations in the United States are referred to as Retail - U.S. The financial information about our segments in Note 19 of Notes to Consolidated Financial Statements is incorporated herein by reference.
VALERO’S OPERATIONS
REFINING
On December 31, 2007, our refining operations included 17 refineries in the United States, Canada, and Aruba with a combined total throughput capacity of approximately 3.1 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, 2007.
             
As of December 31, 2007
        Throughput Capacity(a)
Refinery   Location   (barrels per day)
Gulf Coast:
           
Corpus Christi (b)
  Texas     315,000  
Port Arthur
  Texas     310,000  
Aruba
  Aruba     275,000  
St. Charles
  Louisiana     250,000  
Texas City
  Texas     245,000  
Houston
  Texas     145,000  
Three Rivers
  Texas     100,000  
Krotz Springs
  Louisiana       85,000  
 
           
 
        1,725,000  
 
           
 
           
West Coast:
           
Benicia
  California     170,000  
Wilmington
  California     135,000  
 
           
 
        305,000  
 
           
 
           
Mid-Continent:
           
Memphis
  Tennessee     195,000  
McKee
  Texas     170,000  
Ardmore
  Oklahoma       90,000  
 
           
 
        455,000  
 
           
 
           
Northeast:
           
Quebec City
  Quebec, Canada     215,000  
Delaware City
  Delaware     210,000  
Paulsboro
  New Jersey     195,000  
 
           
 
        620,000  
 
           
 
           
Total
        3,105,000  
 
           
 
(a)   “Throughput capacity” represents estimated capacity for processing crude oil, intermediates, and other feedstocks. Total estimated crude oil capacity is approximately 2.7 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 typically can be purchased at prices below West Texas Intermediate, a benchmark crude oil. In 2007, sour crude oils, acidic sweet crude oils, and resid represented 57% of our throughput volumes, sweet crude oils

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represented 26%, and the remaining 17% 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 prices below sweet crude oils.
In 2007, gasolines and blendstocks represented 46% of our refined product slate; distillates - such as home heating oil, diesel fuel, and jet fuel - represented 33%; 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, 2007. Total throughput volumes for the Gulf Coast refining region averaged 1,537,000 BPD for the 12 months ended December 31, 2007.
Combined Gulf Coast Region Charges and Yields
         
        Percentage
Charges:
   
 
  sour crude oil   54%
 
  sweet crude oil   14%
 
  residual fuel oil   13%
 
  other feedstocks   8%
 
  blendstocks   11%
Yields:
   
 
  gasolines and blendstocks   43%
 
  distillates   32%
 
  petrochemicals   4%
 
  other products (includes vacuum gas oil, No. 6 fuel oil, petroleum coke, asphalt, and other)   21%
Corpus Christi East and West Refineries. Our Corpus Christi East and West Refineries are located on the Texas Gulf Coast along the Corpus Christi Ship Channel. The West Refinery specializes in processing primarily lower-cost sour crude oil and resid into premium products such as RBOB. The East Refinery processes heavy, high-sulfur crude oil into conventional gasoline, diesel, jet fuel, asphalt, aromatics, and other light products. The East and West Refineries are substantially integrated allowing for the transfer of various feedstocks and blending components between the two refineries and the sharing of resources. The refineries typically receive and deliver feedstocks and products by tanker and barge via deepwater docking facilities along the Corpus Christi Ship Channel. Three truck racks with a total of 16 bays service local markets for gasoline, diesel, jet fuels, liquefied petroleum gases, and asphalt. The refineries distribute refined products using the Colonial, Explorer, Valley, and other major pipelines.
Port Arthur Refinery. Our Port Arthur Refinery is located on the Texas Gulf Coast approximately 90 miles east of Houston. The refinery processes primarily heavy sour crude oils and other feedstocks into conventional and premium gasoline and RBOB, as well as diesel, jet fuel, petrochemicals, petroleum coke, and sulfur. The refinery receives crude oil over marine docks and has access to the Sunoco and Oiltanking terminals at Nederland, Texas. Finished products are distributed into the Colonial, Explorer, and TEPPCO pipelines or across the refinery docks into ships or barges. The refinery also has truck-rack access.

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Aruba Refinery. Our Aruba Refinery is located on the island of Aruba in the Caribbean Sea. It processes primarily heavy sour crude oil and produces primarily intermediate feedstocks and finished distillate products. Significant amounts of the refinery’s intermediate feedstock production are transported and further processed in our other refineries in the Gulf Coast, West Coast, and Northeast regions. The refinery receives crude oil by ship at its two deepwater marine docks, which can berth ultra-large crude carriers. The refinery’s products are delivered by ship primarily into markets in the U.S. Gulf Coast, Florida, the New York Harbor, the Caribbean, and Europe.
St. Charles Refinery. Our St. Charles Refinery is located approximately 15 miles from New Orleans along the Mississippi River. The refinery processes sour crude oils and other feedstocks into gasoline, distillates, and other light products. The refinery receives crude oil over five marine docks and has access to the Louisiana Offshore Oil Port where it can receive crude oil through a 24-inch pipeline. Finished products can be shipped over these docks or by pipeline into either the Plantation or Colonial pipeline network for distribution to the eastern United States.
Texas City Refinery. Our Texas City Refinery is located southeast of Houston on the Texas City Ship Channel. The refinery processes primarily heavy sour crude oils into a wide slate of products. The refinery receives and delivers its feedstocks and products by tanker and barge via deepwater docking facilities along the Texas City Ship Channel and uses the Colonial, Explorer, and TEPPCO pipelines for distribution of its products.
Houston Refinery. Our Houston Refinery is located on the Houston Ship Channel. It processes primarily sour crude oils and low-sulfur resid into conventional gasoline and distillates. The refinery also produces roofing-grade asphalt. The refinery receives its feedstocks via tanker at deepwater docking facilities along the Houston Ship Channel and delivers its products through major refined-product pipelines, including the Colonial, Explorer, and TEPPCO pipelines.
Three Rivers Refinery. Our Three Rivers Refinery is located in South Texas between Corpus Christi and San Antonio. It processes primarily heavy sweet and sour crude oils into conventional gasoline and distillates. The refinery has access to crude oil from foreign sources delivered to the Texas Gulf Coast at Corpus Christi as well as crude oil from domestic sources through third-party pipelines. A 70-mile pipeline that can deliver 120,000 BPD of crude oil connects the Three Rivers Refinery to Corpus Christi. The refinery distributes its refined products primarily through pipelines owned by NuStar Energy L.P.
Krotz Springs Refinery. Our Krotz Springs Refinery is located between Baton Rouge and Lafayette, Louisiana on the Atchafalaya River. It processes light sweet crude oils (received by pipeline and barge) into conventional gasoline and distillates. The refinery’s location provides access to upriver markets on the Mississippi River, and its docking facilities along the Atchafalaya River are sufficiently deep to allow barge access. The facility also uses the Colonial pipeline to transport products to markets in the southeastern and northeastern United States.

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     West Coast
The following table presents the percentages of principal charges and yields (on a combined basis) for the two refineries in this region for the year ended December 31, 2007. Total throughput volumes for the West Coast refining region averaged approximately 289,000 BPD for the 12 months ended December 31, 2007.
Combined West Coast Region Charges and Yields
         
        Percentage
Charges:
   
 
  sour crude oil   63%
 
  high-acid sweet crude oil   5%
 
  sweet crude oil   4%
 
  other feedstocks   10%
 
  blendstocks   18%
Yields:
   
 
  gasolines and blendstocks   60%
 
  distillates   23%
 
  other products (includes vacuum gas oil, No. 6 fuel oil, petroleum coke, asphalt, and other)   17%
Benicia Refinery. Our Benicia Refinery is located northeast of San Francisco on the Carquinez Straits of San Francisco Bay. It processes sour crude oils into premium products, primarily CARBOB gasoline. (CARBOB is a reformulated gasoline mixture that meets the specifications of the California Air Resources Board when blended with ethanol.) The refinery receives crude oil supplies via a deepwater dock that can berth large crude oil carriers and a 20-inch crude oil pipeline connected to a southern California crude oil delivery system. Most of the refinery’s products are distributed via the Kinder Morgan pipeline in California.
Wilmington Refinery. Our Wilmington Refinery is located near Los Angeles, California. The refinery processes a blend of lower-cost heavy and high-sulfur crude oils. The refinery can produce all of its gasoline as CARBOB gasoline and produces both ultra-low-sulfur diesel and CARB diesel. The refinery is connected by pipeline to marine terminals and associated dock facilities that can move and store crude oil and other feedstocks. Refined products are distributed via the Kinder Morgan pipeline system and various third-party terminals in southern California, Nevada, and Arizona.

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     Mid-Continent
The following table presents the percentages of principal charges and yields (on a combined basis) for the three refineries in this region for the year ended December 31, 2007. Total throughput volumes for the Mid-Continent refining region averaged 402,000 BPD for the 12 months ended December 31, 2007. (The information presented below excludes the charges and yields of the Lima, Ohio refinery, which we sold effective July 1, 2007. The sale is more fully described in Note 2 of Notes to Consolidated Financial Statements.)
Combined Mid-Continent Region Charges and Yields
         
        Percentage
Charges:
   
 
  sour crude oil   10%
 
  sweet crude oil   81%
 
  other feedstocks   1%
 
  blendstocks   8%
Yields:
   
 
  gasolines and blendstocks   48%
 
  distillates   39%
 
  petrochemicals   3%
 
  other products (includes vacuum gas oil, No. 6 fuel oil, asphalt, and other)   10%
Memphis Refinery. Our Memphis Refinery is located in Tennessee along the Mississippi River’s Lake McKellar. It processes primarily light sweet crude oils. Almost all of its production is light products, including regular and premium gasoline, diesel, jet fuels, and petrochemicals. Crude oil is supplied to the refinery via the Capline pipeline and can also be received, along with other feedstocks, via barge. The refinery’s products are distributed via truck racks at our three product terminals, barges, and a pipeline directly to the Memphis airport.
McKee Refinery. Our McKee Refinery is located in the Texas Panhandle. It processes primarily sweet crude oils and produces conventional gasoline, RBOB, low-sulfur diesel, jet fuels, and asphalt. The refinery has access to crude oil from Texas, Oklahoma, Kansas, and Colorado through third-party pipelines. The refinery also has access at Wichita Falls, Texas to third-party pipelines that transport crude oil from the Texas Gulf Coast and West Texas to the Mid-Continent region. The refinery distributes its products primarily via NuStar Energy L.P.’s pipelines to markets in Texas, New Mexico, Arizona, Colorado, and Oklahoma.
Ardmore Refinery. Our Ardmore Refinery is located in Ardmore, Oklahoma, approximately 90 miles from Oklahoma City. It processes medium sour and light sweet crude oils into conventional gasoline, low-sulfur diesel, and asphalt. Crude oil is delivered to the refinery through NuStar Energy L.P.’s crude oil gathering and trunkline systems, other third-party pipelines, and trucking operations. Refined products are transported via pipelines, railcars, and trucks.

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     Northeast
The following table presents the percentages of principal charges and yields (on a combined basis) for the three refineries in this region for the year ended December 31, 2007. Total throughput volumes for the Northeast refining region averaged 570,000 BPD for the 12 months ended December 31, 2007.
Combined Northeast Region Charges and Yields
         
        Percentage
Charges:
   
 
  sour crude oil   40%
 
  high-acid sweet crude oil   11%
 
  sweet crude oil   31%
 
  residual fuel oil   7%
 
  other feedstocks   3%
 
  blendstocks   8%
Yields:
   
 
  gasolines and blendstocks   45%
 
  distillates   38%
 
  petrochemicals   1%
 
  other products (includes vacuum gas oil, No. 6 fuel oil, petroleum coke, asphalt, and other)   16%
Quebec City Refinery. Our Quebec City Refinery is located in Lévis, Canada (near Quebec City). It processes sweet crude oils and lower-quality, sweet acidic crude oils into conventional gasoline, low-sulfur diesel, jet fuels, heating oil, and propane. The refinery receives crude oil by ship at its deepwater dock on the St. Lawrence River. We charter large ice-strengthened, double-hulled crude oil tankers that can navigate the St. Lawrence River year-round. The refinery transports its products to its primary terminals in Quebec and Ontario primarily by train, and also uses ships and trucks extensively throughout eastern Canada.
Delaware City Refinery. Our Delaware City Refinery is located along the Delaware River near Wilmington, Delaware. The refinery processes primarily sour crude oils into a wide slate of products including conventional gasoline, RBOB, petroleum coke, sulfur, low-sulfur diesel, and home heating oil. Feedstocks and refined products are transported via pipeline, barge, and truck-rack facilities. The refinery’s production is sold primarily in the U.S. Northeast.
Paulsboro Refinery. Our Paulsboro Refinery is located in Paulsboro, New Jersey, approximately 15 miles south of Philadelphia on the Delaware River. The refinery processes primarily sour crude oils into a wide slate of products including gasoline, distillates, lube oil basestocks, asphalt, petroleum coke, sulfur, and fuel oil. Feedstocks and refined products are typically transported by tanker and barge via refinery-owned dock facilities along the Delaware River, Buckeye Partners’ product distribution system, an onsite truck rack owned by NuStar Energy L.P., railcars, and the Colonial pipeline, which allows products to be sold into the New York Harbor market.

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     Feedstock Supply
Approximately 67% of our current crude oil feedstock requirements are purchased through term contracts while the remaining requirements are generally purchased on the spot market. Our term supply agreements include arrangements to purchase feedstocks at market-related prices directly or indirectly from various foreign national oil companies (including feedstocks originating in Saudi Arabia, Mexico, Iraq, Kuwait, Venezuela, Colombia, and Africa) as well as international and domestic oil companies. About 80% of these crude oil feedstocks are imported from foreign sources and about 20% are domestic. In the event we become unable to purchase crude oil from any one of these sources, we believe that adequate alternative supplies of crude oil would be available.
The U.S. network of crude oil pipelines and terminals allows us to acquire crude oil from producing leases, domestic crude oil trading centers, and ships delivering cargoes of foreign and domestic crude oil. Our Quebec City and Aruba Refineries rely on foreign crude oil that is delivered to the refineries’ dock facilities by ship. We use the futures market to manage a portion of the price risk inherent in purchasing crude oil in advance of our delivery date and holding inventories of crude oils and refined products.
     Refining Segment Sales
Our refining segment includes sales of refined products in both the wholesale rack and bulk markets. These sales include refined products that are manufactured in our refining operations as well as refined products purchased or received on exchange from third parties. Most of our refineries have access to deepwater transportation facilities and interconnect with common-carrier pipeline systems, allowing us to sell products in most major geographic regions of the United States and eastern Canada. No customer accounted for more than 10% of our total operating revenues in 2007.
          Wholesale Marketing
We market branded and unbranded transportation fuels on a wholesale basis in 45 states through an extensive rack marketing network. The principal purchasers of our transportation fuels from terminal truck racks are wholesalers, distributors, retailers, and truck-delivered end users throughout the United States.
The majority of our rack volume is sold through unbranded channels. The remainder is sold to distributors and dealers that are members of the Valero-brand family that operate approximately 3,850 branded sites. These sites are independently owned and are supplied by us under multi-year contracts. For wholesale branded sites, we promote our Valero® brand throughout the United States. In addition, we offer the Beacon® brand in California and the Shamrock® brand elsewhere in the United States. We are finalizing the process of converting the remaining 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 38,000 BPD of asphalt, which is sold to customers in the paving and roofing industries. We have the second largest asphalt production capacity in the United States. We produce asphalt at six refineries and market asphalt in 20 states through 20 truck-loading facilities. We also produce packaged roofing products at three manufacturing facilities, and modified paving asphalts at nine polymer modifying plants. We are a significant producer of petroleum coke in the United States, supplying primarily power generation customers and cement manufacturers. We are also a significant producer of sulfur in the United States with sales primarily to customers in the agricultural sector.

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We produce and market a variety of commodity petrochemicals including aromatic solvents (benzene, toluene, and xylene) and refinery- and chemical-grade propylene. Aromatic solvents and propylene are sold to customers in the chemical industry for further processing into such products as paints, plastics, and adhesives.
          Bulk Sales and Trading
We sell a significant portion of our gasoline and distillate production through bulk sales channels. Our bulk sales are made to various oil companies and traders as well as certain bulk end-users such as railroads, airlines, and utilities. Our bulk sales are transported primarily by pipeline, barges, and tankers to major tank farms and trading hubs.
We also enter into refined product exchange and purchase agreements. These agreements help to minimize transportation costs, optimize refinery utilization, balance refined product availability, broaden geographic distribution, and make sales to markets not connected to our refined product pipeline systems. Exchange agreements provide for the delivery of refined products by us to unaffiliated companies at our and third parties’ terminals in exchange for delivery of a similar amount of refined products to us by these unaffiliated companies at specified locations. Purchase agreements involve our purchase of refined products from third parties with delivery occurring at specified locations.

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RETAIL
Our retail segment operations include the following:
    sales of transportation fuels at retail stores and unattended self-service cardlocks,
 
    sales of convenience store merchandise in retail stores, and
 
    sales of home heating oil to residential customers.
We are one of the largest independent retailers of refined products in the central and southwest United States and eastern Canada. Our retail operations are segregated geographically into two groups: Retail - U.S. and Retail - Canada.
     Retail - U.S.
Sales in Retail - U.S. represent sales of transportation fuels and convenience store merchandise through our company-operated retail sites. For the year ended December 31, 2007, total sales of refined products through Retail - U.S.’s retail sites averaged approximately 113,500 BPD. In addition to transportation fuels, our company-operated convenience stores sell snacks, candy, beer, fast foods, cigarettes, and fountain drinks. On December 31, 2007, we had 953 company-operated sites in Retail - U.S. (of which 77% were owned and 23% were leased). Our company-operated stores are operated primarily under the brand names Corner Store® and Stop N Go®. Transportation fuels sold in our Retail - U.S. stores are sold primarily under the Valero® brand, with some sites selling under the Diamond Shamrock® brand pending their conversion to the Valero® brand.
     Retail - Canada
Sales in Retail - Canada include the following:
    sales of refined products and convenience store merchandise through our company-operated retail sites and cardlocks,
 
    sales of refined products through sites owned by independent dealers and jobbers, and
 
    sales of home heating oil to residential customers.
Retail - Canada includes retail operations in eastern Canada where we are a major supplier of refined products serving Quebec, Ontario, and the Atlantic Provinces of Newfoundland, Nova Scotia, New Brunswick, and Prince Edward Island. For the year ended December 31, 2007, total retail sales of refined products through Retail - Canada averaged approximately 77,000 BPD. Transportation fuels are sold under the Ultramar® brand through a network of 920 outlets throughout eastern Canada. On December 31, 2007, we owned or leased 432 retail stores in Retail - Canada and distributed gasoline to 488 dealers and independent jobbers. In addition, Retail - Canada operates 89 cardlocks, which are card- or key-activated, self-service, unattended stations that allow commercial, trucking, and governmental fleets to buy transportation fuel 24 hours a day. Retail - Canada operations also include a large home heating oil business that provides home heating oil to approximately 150,000 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 several 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 depend on, 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 we believe they will continue to be volatile in the future.
Compliance with and changes in environmental laws could adversely affect our performance.
The principal environmental risks associated with our operations are emissions into the air and releases into the soil, surface water, or groundwater. Our operations are subject to extensive federal, state, and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasoline and diesel fuels. If we violate or fail to comply with these laws and regulations, we could be fined or otherwise sanctioned. Because environmental laws and regulations are becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, such as those relating to greenhouse gas emissions and climate change (e.g., California’s AB-32 “Global Warming Solutions Act”), the level of expenditures required for environmental matters could increase in the future. Future legislative action and regulatory initiatives could result in changes to operating permits, additional remedial actions, or increased capital expenditures and operating costs that cannot be assessed with certainty at this time. In addition, any major upgrades in any of our refineries could require material additional expenditures to comply with environmental laws and regulations.
Disruption of our ability to obtain crude oil could adversely affect our operations.
A significant portion of our feedstock requirements is satisfied through supplies originating in Saudi Arabia, Mexico, Iraq, Kuwait, Venezuela, Colombia, and Africa. We are, therefore, subject to the political, geographic, and economic risks attendant to doing business with suppliers located in, and supplies originating from, those areas. If one or more of our supply contracts were terminated, or if political events disrupt our traditional crude oil supply, we believe that adequate alternative supplies of crude oil would be available, but it is possible that we would be unable to find alternative sources of supply. If we are unable to obtain adequate crude oil volumes or are able to obtain such volumes only at unfavorable prices, our results of operations could be materially adversely affected, including reduced sales volumes of refined products or reduced margins as a result of higher crude oil costs.
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 many 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.

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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 or mechanical failure, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs.
Our operations expose us to many operating risks, not all of which are insured.
Our refining and marketing operations are subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards, and uncontrollable flows of oil and gas. They are also subject to the additional hazards of loss from severe weather conditions. As protection against operating hazards, we maintain insurance coverage against some, but not all, such potential losses. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax liabilities, including federal, state, and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise, withholding, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Many of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties.

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ENVIRONMENTAL MATTERS
We incorporate by reference into this Item the environmental disclosures contained in the following sections of this report:
    Item 1 under the caption “Risk Factors - Compliance with and changes in environmental laws could adversely affect our performance,”
 
    Item 3 “Legal Proceedings” under the caption “Environmental Enforcement Matters,” and
 
    Item 8 “Financial Statements” in Note 23 of Notes to Consolidated Financial Statements.
Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2007, our capital expenditures attributable to compliance with environmental regulations were $614 million, and are currently estimated to be approximately $575 million for 2008 and approximately $665 million for 2009. The estimates for 2008 and 2009 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, 2007, we were the lessee under a number of cancelable and non-cancelable leases for certain properties. Our leases are discussed more fully in Note 22 of Notes to Consolidated Financial Statements.
Our patents relating to our refining operations are not material to us as a whole. The trademarks and tradenames under which we conduct our retail and branded wholesale business - including Valero®, Diamond Shamrock®, Shamrock®, Ultramar®, Beacon®, Corner Store®, and Stop N Go® - and other trademarks employed in the marketing of petroleum products are integral to our wholesale and retail marketing operations.

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EXECUTIVE OFFICERS OF THE REGISTRANT
                     
Name   Age*   Positions Held with Valero   Officer Since
William R. Klesse
    61     Chief Executive Officer, President, and Chairman of the Board     2001  
Michael S. Ciskowski
    50     Executive Vice President and Chief Financial Officer     1998  
S. Eugene Edwards
    51     Executive Vice President-Corporate Development and Strategic Planning     1998  
Joseph W. Gorder
    50     Executive Vice President-Marketing and Supply     2003  
Richard J. Marcogliese
    55     Executive Vice President and Chief Operating Officer     2001  
 
*   on January 31, 2008
Mr. Klesse was elected as Valero’s Chairman of the Board on January 18, 2007, and as Chief Executive Officer on December 31, 2005. He added the title of President on January 17, 2008. He was Valero’s Vice-Chairman of the Board from October 31, 2005 to January 18, 2007. He previously served as Executive Vice President and Chief Operating Officer since January 2003. He served as an Executive Vice President of Valero since the date of our acquisition of Ultramar Diamond Shamrock Corporation (UDS) on December 31, 2001.
Mr. Ciskowski was elected Executive Vice President and Chief Financial Officer on August 19, 2003. Before that, he served as Executive Vice President-Corporate Development since April 2003, and Senior Vice President in charge of business and corporate development since 2001.
Mr. Edwards was elected Executive Vice President-Corporate Development and Strategic Planning in December 2005. Prior to that he had served as Senior Vice President since December 2001 with responsibilities for product supply, trading, and wholesale marketing. 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.
Mr. Marcogliese was elected Executive Vice President and Chief Operating Officer on October 26, 2007. He previously held the title Executive Vice President-Operations since December 2005. Prior to that he served as Senior Vice President overseeing refining operations since July 2001.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 3. LEGAL PROCEEDINGS
     Litigation
For the legal proceedings listed below, we incorporate by reference into this Item our disclosures made in Part II, Item 8 of this report included in Note 24 of Notes to Consolidated Financial Statements under the caption “Litigation Matters.”
    MTBE Litigation
 
    Retail Fuel Temperature 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 us, we believe that there would be no material effect on our consolidated financial position or results of operations. We are reporting these proceedings to comply with SEC regulations, which require us to disclose certain information about 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 Department of Justice (DOJ)/ United States Environmental Protection Agency (EPA) (Corpus Christi West Refinery). The DOJ proposed a penalty of $2.4 million to resolve alleged violations of the Clean Water Act resulting from an oil spill at our Corpus Christi West Refinery in June 2006. We are pursuing settlement of this matter with the DOJ and EPA.
United States of America, et al. v. The Premcor Refining Group Inc., et al., United States District Court, Western District of Texas (Civil Action No. SA07CA0683RF, August 16, 2007). In the past several years, the EPA issued to a majority of refiners operating in the United States a series of information requests pursuant to Section 114 of the Clean Air Act as part of the EPA’s National Petroleum Refinery Initiative (Initiative) to reduce air emissions. Three refineries that we acquired in the Premcor Acquisition (the Port Arthur, Memphis, and Lima Refineries) had received information requests as part of this Initiative (the Delaware City Refinery was already subject to a separate Section 114 settlement). In August 2007, we reached an Initiative settlement with the EPA and the DOJ covering these three refineries. In the fourth quarter of 2007, a consent decree fully resolving this matter was entered in federal court.
Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery). In 2005, the BAAQMD issued 25 violation notices (VNs) for various incidents at our Benicia Refinery and asphalt plant, including alleged excess emissions, recordkeeping discrepancies, and other matters. In the fourth quarter of 2007, we settled 24 of these VNs. We do not believe that the remaining 2005 VN will result in monetary sanctions of $100,000 or more. In 2006, the BAAQMD issued 22 VNs, and in 2007, the BAAQMD issued 30 VNs for these facilities containing allegations similar to the 2005 VNs. We are pursuing settlement of the 2006 and 2007 VNs and the one remaining VN from 2005.
Delaware Department of Natural Resources and Environmental Control (DDNREC) (Delaware City Refinery). On October 11, 2007, the DDNREC issued a notice of violation (NOV) to our Delaware City Refinery alleging unauthorized emissions and failure to report emissions from the refinery’s frozen earth storage unit. We are pursuing settlement of this matter.

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Los Angeles Regional Water Quality Control Board (LARWQCB) (Wilmington Marine Terminal). In December 2007, as part of the National Pollutant Discharge Elimination System Permit renewal process for our Wilmington marine terminal, the LARWQCB issued an NOV and Request for Information. The NOV alleges violations of acute toxicity effluent limits between 2000 and 2006 and reporting violations between 2001 and 2005. We are currently pursuing settlement of this NOV.
New Jersey Department of Environmental Protection (NJDEP) (Paulsboro Refinery). We were subject to 17 air-related Administrative Order and Notice of Civil Administrative Penalty Assessments (Notices) issued by the NJDEP in 2005 and 2006 relating to our Paulsboro Refinery. Additionally, in March 2007, the NJDEP issued a Notice to our Paulsboro Refinery alleging unauthorized air emissions and late reporting regarding a release and flaring event that occurred in February 2007. We are pursuing settlement of these Notices.
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.
South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). In 2007, the SCAQMD issued nine NOVs for various alleged violations at our Wilmington Refinery and asphalt plant including excess emissions, recordkeeping discrepancies, and other matters. We are currently pursuing settlement of the NOVs.
Texas Commission on Environmental Quality (TCEQ) (McKee Refinery). We received a proposed Agreed Order from the TCEQ for $115,728 on November 26, 2007, to resolve three outstanding notices of enforcement pertaining to alleged violations of state and federal air regulations at our McKee Refinery. We are currently in settlement discussions with the TCEQ to resolve this matter.
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 had originally proposed penalties of $880,240 for these events. In 2007, these enforcement actions were referred to the Texas Attorney General’s office and consolidated with TCEQ Docket No. 2005-1596-AIR-E, which assessed an additional penalty of $130,563. The Texas Attorney General has made a demand of $4 million to resolve these matters. The federal consent decree related to the Section 114 Initiative described above (see United States of America, et al. v. The Premcor Refining Group, Inc., et al.) proposes to resolve the violations addressed by the TCEQ’s enforcement actions. We are in discussions with the Texas Attorney General to clarify what, if any, remaining issues must be resolved.
TCEQ (Texas City Refinery). On July 11, 2007, we received a Notice of Enforcement from the TCEQ for excess air emissions that began in 2005 at our Texas City Refinery relating to a partially open flare valve. On September 25, 2007, the TCEQ issued a proposed Agreed Order with a proposed administrative penalty of $228,900. We settled this matter with the TCEQ in the fourth quarter of 2007.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.

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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 trades on the New York Stock Exchange under the symbol “VLO.”
As of January 31, 2008, there were 8,253 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 2007 and 2006.
                         
    Sales Prices of the   Dividends
    Common Stock   Per
Quarter Ended   High   Low   Common Share
2007:
                       
December 31
  $ 75.75     $ 60.80     $ 0.12  
September 30
    78.68       60.00       0.12  
June 30
    77.89       63.53       0.12  
March 31
    66.02       47.66       0.12  
 
                       
2006:
                       
December 31
  $ 57.09     $ 47.52     $ 0.08  
September 30
    68.83       46.84       0.08  
June 30
    70.75       55.19       0.08  
March 31
    63.70       47.99       0.06  
On January 17, 2008, our board of directors declared a quarterly cash dividend of $0.12 per common share payable March 12, 2008 to holders of record at the close of business on February 13, 2008.
Dividends are considered quarterly by the board of directors and may be paid only when approved by the board.

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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 2007.
                                         
                                    Maximum Number (or
                    Total Number of           Approximate Dollar
                    Shares Not   Total Number of   Value) of Shares
                    Purchased as Part   Shares Purchased as   that May Yet Be
                    of Publicly   Part of Publicly   Purchased Under the
    Total Number of   Average Price Paid   Announced Plans or   Announced Plans or   Plans or Programs
Period   Shares Purchased   per Share   Programs (1)   Programs   (2)(3)
October 2007
    1,128,269     $ 68.55       1,128,269       0     $2.05 billion
November 2007
    7,739,092     $ 66.89       459,244       7,279,848     $1.57 billion
December 2007
    6,550,192     $ 67.52       25,092       6,525,100     $1.13 billion
Total
    15,417,553     $ 67.28       1,612,605       13,804,948     $1.13 billion
 
(1)   The shares reported in this column represent purchases settled in the fourth quarter of 2007 relating to (a) our purchases of shares in open-market transactions to meet our obligations under employee benefit plans, and (b) our purchases of shares 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 in accordance with the terms of our incentive compensation plans.
 
(2)   On April 26, 2007, we publicly announced an increase in our common stock purchase program from $2 billion to $6 billion, as authorized by our board of directors on April 25, 2007. The $6 billion common stock purchase program has no expiration date. The $6 billion common stock purchase program is more fully described in Note 14 of Notes to Consolidated Financial Statements, and we hereby incorporate by reference into this Item our disclosures made in Note 14.
 
(3)   On February 28, 2008, our board of directors approved a new $3 billion stock purchase program. This program is in addition to the $6 billion program discussed in note (2) above. This new $3 billion program has no expiration date.

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The following Performance Graph is not “soliciting material,” is not deemed filed with the SEC, and is not to be incorporated by reference into any of Valero’s filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended, respectively.
The following line graph compares the cumulative total return* on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (selected by us) for the five-year period commencing December 31, 2002 and ending December 31, 2007. The peer group consists of the following ten companies that are engaged in the domestic energy industry: Chevron Corporation, ConocoPhillips, Exxon Mobil Corporation, Frontier Oil Corporation, Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Occidental Petroleum Corporation, Sunoco, Inc., and Tesoro Corporation.
COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN*
Among Valero Energy Corporation, The S&P 500 Index,
and a Peer Group
(PERFORMANCE GRAPH)
                                                 
    12/2002   12/2003   12/2004   12/2005   12/2006   12/2007
Valero Common Stock
  $ 100     $ 126.79     $ 250.58     $ 572.48     $ 570.61     $ 786.90  
S&P 500
    100       128.68       142.69       149.70       173.34       182.87  
Peer Group
    100       127.33       164.65       196.08       262.97       341.28  
This Performance Graph and the related textual information are based on historical data and are not indicative of future performance.
 
*   Assumes that an investment in Valero common stock and each index was $100 on December 31, 2002. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from December 31, 2002 through December 31, 2007.

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ITEM 6. SELECTED FINANCIAL DATA
The selected financial data for the five-year period ended December 31, 2007 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,
    2007 (a)   2006 (a)   2005 (a) (b)   2004 (c)   2003 (d)
Operating revenues (e)
  $ 95,327     $ 87,640     $ 80,616     $ 54,589     $ 37,951  
Operating income
    6,918       7,722       5,268       2,979       1,222  
Income from continuing operations
    4,565       5,287       3,473       1,804       622  
Earnings per common share from continuing operations - assuming dilution
    7.72       8.36       5.90       3.27       1.27  
Dividends per common share
    0.48       0.30       0.19       0.145       0.105  
Property, plant and equipment, net
    21,709       20,180       17,378       10,317       8,195  
Goodwill
    4,061       4,103       4,837       2,401       2,402  
Total assets
    42,722       37,753       32,798       19,392       15,664  
Long-term debt and capital lease obligations (less current portion)
    6,470       4,619       5,156       3,901       4,245  
Stockholders’ equity
    18,507       18,605       15,050       7,798       5,735  
 
(a)   Effective July 1, 2007, we sold our Lima Refinery to Husky Refining Company. Therefore, the assets and liabilities related to the sale are presented as “assets held for sale” and “liabilities related to assets held for sale,” respectively, in the consolidated balance sheets as of December 31, 2006 and 2005. In addition, the results of operations of the Lima Refinery are reported as discontinued operations in the consolidated statements of income for the years ended December 31, 2007, 2006, and 2005 and therefore are not included in the statement of income information presented in this table.
 
(b)   Includes the operations related to the Premcor Acquisition beginning September 1, 2005.
 
(c)   Includes the operations related to the acquisition of the Aruba Refinery and related businesses beginning March 5, 2004.
 
(d)   Includes the operations of the St. Charles Refinery beginning July 1, 2003.
 
(e)   Operating revenues reported for 2005, 2004, and 2003 include approximately $7.8 billion, $4.9 billion, and $3.9 billion, respectively, related to crude oil buy/sell arrangements.

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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.
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,” “could,” “should,” “may,” and similar expressions.
These forward-looking statements include, among other things, statements regarding:
    future refining margins, including gasoline and distillate margins;
 
    future retail margins, including gasoline, diesel, home heating oil, and convenience store merchandise margins;
 
    expectations regarding feedstock costs, including crude oil differentials, and operating expenses;
 
    anticipated levels of crude oil and refined product inventories;
 
    our anticipated level of capital investments, including deferred refinery turnaround and catalyst costs and capital expenditures for environmental and other purposes, and the effect of those capital investments on our results of operations;
 
    anticipated trends in the supply of and demand for crude oil and other feedstocks and refined products in the United States, Canada, and elsewhere;
 
    expectations regarding environmental, tax, and other regulatory initiatives; and
 
    the effect of general economic and other conditions on refining and retail industry fundamentals.
We based our forward-looking statements on our current expectations, estimates, and projections about ourselves and our industry. We caution that these statements are not guarantees of future performance and involve risks, uncertainties, and assumptions that we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual results may differ materially from the future performance that we have expressed or forecast in the forward-looking statements. Differences between actual results and any future performance suggested in these forward-looking statements could result from a variety of factors, including the following:
    acts of terrorism aimed at either our facilities or other facilities that could impair our ability to produce or transport refined products or receive feedstocks;
 
    political and economic conditions in nations that consume refined products, including the United States, and in crude oil producing regions, including the Middle East and South America;
 
    the domestic and foreign supplies of refined products such as gasoline, diesel fuel, jet fuel, home heating oil, and petrochemicals;
 
    the domestic and foreign supplies of crude oil and other feedstocks;
 
    the ability of the members of the Organization of Petroleum Exporting Countries (OPEC) to agree on and to maintain crude oil price and production controls;
 
    the level of consumer demand, including seasonal fluctuations;
 
    refinery overcapacity or undercapacity;

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    the actions taken by competitors, including both pricing and the expansion and retirement of refining capacity in response to market conditions;
 
    environmental, tax, and other regulations at the municipal, state, and federal levels and in foreign countries;
 
    the level of foreign imports of refined products;
 
    accidents or other unscheduled shutdowns affecting our refineries, machinery, pipelines, or equipment, or those of our suppliers or customers;
 
    changes in the cost or availability of transportation for feedstocks and refined products;
 
    the price, availability, and acceptance of alternative fuels and alternative-fuel vehicles;
 
    delay of, cancellation of, or failure to implement planned capital projects and realize the various assumptions and benefits projected for such projects or cost overruns in constructing such planned capital projects;
 
    earthquakes, hurricanes, tornadoes, and irregular weather, which can unforeseeably affect the price or availability of natural gas, crude oil and other feedstocks, and refined products;
 
    rulings, judgments, or settlements in litigation or other legal or regulatory matters, including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;
 
    legislative or regulatory action, including the introduction or enactment of federal, state, municipal, or foreign legislation or rulemakings, which may adversely affect our business or operations;
 
    changes in the credit ratings assigned to our debt securities and trade credit;
 
    changes in currency exchange rates, including the value of the Canadian dollar relative to the U.S. dollar; and
 
    overall economic conditions.
Any one of these factors, or a combination of these factors, could materially affect our future results of operations and whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.
All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

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OVERVIEW
In this overview, we discuss the major transactions of our business during the year ended December 31, 2007 and describe some of the primary factors that we believe affected our results of operations during the year. Although we reported strong earnings from continuing operations for 2007, they decreased from comparable earnings reported in 2006. We reported income from continuing operations of $4.6 billion, or $7.72 per share, for the year ended December 31, 2007 compared to $5.3 billion, or $8.36 per share, for the year ended December 31, 2006. 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.” Gasoline and distillate margins in 2007 improved compared to such margins in 2006 primarily due to supply limitations caused by industry-wide refinery downtime, both planned and unplanned, lower imports into the United States, and tighter product specifications. However, rapidly rising crude oil prices resulted in lower margins for certain of our secondary products, such as asphalt, fuel oils, petroleum coke, and sulfur, the prices of which did not increase nearly as much as the cost of the feedstocks used to produce them.
In addition, our contribution to earnings resulting from processing sour crude oil rather than sweet crude oil at many of our refineries decreased compared to 2006. Since more than 60% of our total crude oil throughput represents sour crude oil and acidic sweet crude oil feedstocks that are purchased at prices less than sweet crude oil, our profitability is significantly affected by the spread between sweet crude oil and sour crude oil prices, referred to as the “sour crude oil differential.” Sour crude oil differentials relative to WTI crude oil for 2007, although good, decreased compared to the strong differentials in 2006.
The fourth quarter of 2007 demonstrated the advantages of our complex and geographically diverse refining system. While refined product margins were reduced due to a significant increase in feedstock costs relative to product prices, our complex refineries were able to mitigate this unfavorable effect by benefiting from wide sour crude oil differentials. In addition, while product margins in the West Coast region were low, we were able to compensate somewhat for the effect of the low West Coast margins with earnings in the other geographic regions in which we operate.
On February 16, 2007, our McKee Refinery was shut down due to a fire originating in its propane deasphalting unit, which reduced operating income by approximately $325 million during the year ended December 31, 2007. The refinery recommenced operations in April at a reduced throughput rate, with run rates increasing to near full capacity by the end of the third quarter of 2007. All repairs have now been completed and the refinery is running at normal capacity as of February 2008.
Effective July 1, 2007, we sold our refinery in Lima, Ohio to Husky Refining Company (Husky), a wholly owned subsidiary of Husky Energy Inc. The sales price was approximately $2.4 billion, including approximately $550 million from the sale of working capital to Husky, primarily related to the sale of inventory by our marketing and supply subsidiary. The sale resulted in a pre-tax gain of $827 million. During 2007, we also recognized a pre-tax gain of $91 million related to a foreign currency exchange rate gain resulting from the repayment of a loan by a foreign subsidiary. In the second quarter of 2007, we entered into an accelerated share repurchase program under which we purchased 42.1 million shares of our common stock, which was subsequently funded mainly with proceeds from our issuance of $2.25 billion of new debt during 2007.
During 2007, we continued our ongoing effort to increase shareholder value by using a balanced approach to allocating our cash flow. For the year ended December 31, 2007, we generated $5.3 billion of net cash from operating activities, using portions of that cash to increase our 2007 common stock dividends from $0.08 per share to $0.12 per share and to purchase 42.2 million shares of our common stock in addition to the 42.1 million shares purchased under the accelerated share repurchase program discussed above. During 2007, we repurchased 14% of our shares that were outstanding at the beginning of 2007. We also invested $2.8 billion of capital into our refining system and other assets.

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RESULTS OF OPERATIONS
2007 Compared to 2006
Financial Highlights
(millions of dollars, except per share amounts)
                         
    Year Ended December 31,  
    2007 (a)     2006 (a)     Change  
Operating revenues (b)
  $ 95,327     $ 87,640     $ 7,687  
 
                 
 
                       
Costs and expenses:
                       
Cost of sales (b)
    81,645       73,863       7,782  
Refining operating expenses
    4,016       3,622       394  
Retail selling expenses (b)
    750       719       31  
General and administrative expenses
    638       598       40  
Depreciation and amortization expense:
                       
Refining
    1,222       985       237  
Retail
    90       87       3  
Corporate
    48       44       4  
 
                 
Total costs and expenses
    88,409       79,918       8,491  
 
                 
 
                       
Operating income
    6,918       7,722       (804 )
Equity in earnings of NuStar Energy L.P (c)
    -       45       (45 )
Other income, net
    167       350       (183 )
Interest and debt expense:
                       
Incurred
    (466 )     (377 )     (89 )
Capitalized
    107       165       (58 )
Minority interest in net income of NuStar GP Holdings, LLC (c)
    -       (7 )     7  
 
                 
 
                       
Income from continuing operations before income tax expense
    6,726       7,898       (1,172 )
Income tax expense
    2,161       2,611       (450 )
 
                 
 
                       
Income from continuing operations
    4,565       5,287       (722 )
Income from discontinued operations, net of income tax expense (a)
    669       176        493  
 
                 
 
                       
Net income
    5,234       5,463       (229 )
Preferred stock dividends
    -       2       (2 )
 
                 
 
                       
Net income applicable to common stock
  $ 5,234     $ 5,461     $ (227 )
 
                 
 
                       
Earnings per common share - assuming dilution:
                       
Continuing operations
  $ 7.72     $ 8.36     $ (0.64 )
Discontinued operations
    1.16       0.28       0.88  
 
                 
Total
  $ 8.88     $ 8.64     $ 0.24  
 
                 
 
See the footnote references on page 27.

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Operating Highlights
(millions of dollars, except per barrel and per gallon amounts)
                         
    Year Ended December 31,  
    2007     2006     Change  
Refining (a):
                       
Operating income
  $ 7,355     $ 8,182     $ (827 )
Throughput margin per barrel (d)
  $ 12.33     $ 12.47     $ (0.14 )
Operating costs per barrel:
                       
Refining operating expenses
  $ 3.93     $ 3.53     $ 0.40  
Depreciation and amortization
    1.20       0.96       0.24  
 
                 
Total operating costs per barrel
  $ 5.13     $ 4.49     $ 0.64  
 
                 
 
                       
Throughput volumes (thousand barrels per day):
                       
Feedstocks:
                       
Heavy sour crude
    638       697       (59 )
Medium/light sour crude
    635       618       17  
Acidic sweet crude
    80       65       15  
Sweet crude
    724       752       (28 )
Residuals
    247       234       13  
Other feedstocks
     173        147       26  
 
                 
Total feedstocks
    2,497       2,513       (16 )
Blendstocks and other
     301        298       3  
 
                 
Total throughput volumes
    2,798       2,811       (13 )
 
                 
 
                       
Yields (thousand barrels per day):
                       
Gasolines and blendstocks
    1,285       1,348       (63 )
Distillates
    919       891       28  
Petrochemicals
    82       80       2  
Other products (e)
     507        491       16  
 
                 
Total yields
    2,793       2,810       (17 )
 
                 
 
                       
Retail - U.S.:
                       
Operating income
  $ 154     $ 113     $ 41  
Company-operated fuel sites (average)
    957       982       (25 )
Fuel volumes (gallons per day per site)
    4,979       4,985       (6 )
Fuel margin per gallon
  $ 0.174     $ 0.162     $ 0.012  
Merchandise sales
  $ 1,024     $ 960     $ 64  
Merchandise margin (percentage of sales)
    29.7 %     29.6 %     0.1 %
Margin on miscellaneous sales (b)
  $ 101     $ 85     $ 16  
Retail selling expenses (b)
  $ 494     $ 485     $ 9  
Depreciation and amortization expense
  $ 59     $ 60     $ (1 )
 
                       
Retail - Canada:
                       
Operating income
  $ 95     $ 69     $ 26  
Fuel volumes (thousand gallons per day)
    3,234       3,176       58  
Fuel margin per gallon
  $ 0.248     $ 0.217     $ 0.031  
Merchandise sales
  $ 187     $ 167     $ 20  
Merchandise margin (percentage of sales)
    27.8 %     27.4 %     0.4 %
Margin on miscellaneous sales
  $ 37     $ 32     $ 5  
Retail selling expenses
  $ 256     $ 234     $ 22  
Depreciation and amortization expense
  $ 31     $ 27     $ 4  
 
See the footnote references on page 27.

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Refining Operating Highlights by Region (f)
(millions of dollars, except per barrel amounts)
                         
    Year Ended December 31,  
    2007     2006     Change  
 
                       
Gulf Coast:
                       
Operating income
  $ 4,505     $ 5,109     $ (604 )
Throughput volumes (thousand barrels per day)
    1,537       1,532       5  
Throughput margin per barrel (d)
  $ 12.81     $ 13.23     $ (0.42 )
Operating costs per barrel:
                       
Refining operating expenses
  $ 3.70     $ 3.26     $ 0.44  
Depreciation and amortization
    1.08       0.84       0.24  
 
                 
Total operating costs per barrel
  $ 4.78     $ 4.10     $ 0.68  
 
                 
 
                       
Mid-Continent (a):
                       
Operating income
  $ 910     $ 1,041     $ (131 )
Throughput volumes (thousand barrels per day)
    402       410       (8 )
Throughput margin per barrel (d)
  $ 11.66     $ 11.32     $ 0.34  
Operating costs per barrel:
                       
Refining operating expenses
  $ 4.13     $ 3.36     $ 0.77  
Depreciation and amortization
    1.33       1.00       0.33  
 
                 
Total operating costs per barrel
  $ 5.46     $ 4.36     $ 1.10  
 
                 
 
                       
Northeast:
                       
Operating income
  $ 1,084     $ 944     $ 140  
Throughput volumes (thousand barrels per day)
    570       563       7  
Throughput margin per barrel (d)
  $ 10.46     $ 9.80     $ 0.66  
Operating costs per barrel:
                       
Refining operating expenses
  $ 3.98     $ 4.10     $ (0.12 )
Depreciation and amortization
    1.27       1.11       0.16  
 
                 
Total operating costs per barrel
  $ 5.25     $ 5.21     $ 0.04  
 
                 
 
                       
West Coast:
                       
Operating income
  $ 856     $ 1,088     $ (232 )
Throughput volumes (thousand barrels per day)
    289       306       (17 )
Throughput margin per barrel (d)
  $ 14.41     $ 15.07     $ (0.66 )
Operating costs per barrel:
                       
Refining operating expenses
  $ 4.82     $ 4.04     $ 0.78  
Depreciation and amortization
    1.49       1.27       0.22  
 
                 
Total operating costs per barrel
  $ 6.31     $ 5.31     $ 1.00  
 
                 
 
See the footnote references on page 27.

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Average Market Reference Prices and Differentials (g)
(dollars per barrel)
                         
    Year Ended December 31,
    2007   2006   Change
Feedstocks:
                       
West Texas Intermediate (WTI) crude oil
  $ 72.27     $ 66.00     $ 6.27  
WTI less sour crude oil at U.S. Gulf Coast (h)
    4.95       7.01       (2.06 )
WTI less Mars crude oil
    5.61       7.12       (1.51 )
WTI less Alaska North Slope (ANS) crude oil
    0.58       2.47       (1.89 )
WTI less Maya crude oil
    12.41       14.80       (2.39 )
 
                       
Products:
                       
U.S. Gulf Coast:
                       
Conventional 87 gasoline less WTI
    13.78       11.34       2.44  
No. 2 fuel oil less WTI
    11.94       9.80       2.14  
Ultra-low-sulfur diesel less WTI (i)
    17.76       N.A.       N.A.  
Propylene less WTI
    11.05       8.78       2.27  
U.S. Mid-Continent:
                       
Conventional 87 gasoline less WTI
    18.02       12.16       5.86  
Low-sulfur diesel less WTI
    21.30       18.59       2.71  
U.S. Northeast:
                       
Conventional 87 gasoline less WTI
    13.98       10.62       3.36  
No. 2 fuel oil less WTI
    12.96       9.60       3.36  
Lube oils less WTI
    48.29       55.56       (7.27 )
U.S. West Coast:
                       
CARBOB 87 gasoline less ANS
    23.80       21.52       2.28  
CARB diesel less ANS
    22.66       23.96       (1.30 )
 
The following notes relate to references on pages 24 through 27.
 
(a)   Effective July 1, 2007, we sold our Lima Refinery to Husky. Therefore, the results of operations of the Lima Refinery are reported as discontinued operations, and all refining operating highlights, both consolidated and for the Mid-Continent region, exclude the Lima Refinery.
 
(b)   Certain amounts previously reported in 2006 for operating revenues, cost of sales, retail selling expenses, and margin on miscellaneous sales have been reclassified for comparability with amounts reported in 2007.
 
(c)   On December 22, 2006, we sold our remaining ownership interest in NuStar GP Holdings, LLC (formerly Valero GP Holdings, LLC), which indirectly owned the general partner interest, the incentive distribution rights, and a 21.4% limited partner interest in NuStar Energy L.P. (formerly Valero L.P.) As a result, the financial highlights reflect no equity in earnings of NuStar Energy L.P. or minority interest in net income of NuStar GP Holdings, LLC subsequent to December 21, 2006.
 
(d)   Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.
 
(e)   Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
 
(f)   The regions reflected herein contain the following refineries: 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, and Memphis Refineries; the Northeast refining region includes the Quebec City, Paulsboro, and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.
 
(g)   The average market reference prices and differentials, with the exception of the propylene and lube oil differentials, are based on posted prices from Platts 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.
 
(h)   The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.
 
(i)   The market reference differential for ultra-low-sulfur diesel was not available prior to May 1, 2006, and therefore no market reference differential is presented for the year ended December 31, 2006.

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General
Operating revenues increased 9% for the year ended December 31, 2007 compared to the year ended December 31, 2006 primarily as a result of higher refined product prices. Operating income decreased $804 million, or 10%, and income from continuing operations decreased $722 million, or 14%, for the year ended December 31, 2007 compared to the year ended December 31, 2006 primarily due to an $827 million decrease in refining segment operating income. The refining segment operating income and income from continuing operations exclude the operations of the Lima Refinery which are classified as discontinued operations due to our sale of that refinery as discussed in Note 2 of Notes to Consolidated Financial Statements.
Refining
Operating income for our refining segment decreased from $8.2 billion for the year ended December 31, 2006 to $7.4 billion for the year ended December 31, 2007 resulting mainly from increased refining operating expenses (including depreciation and amortization expense) of $631 million. In addition, total throughput margin for the refining segment declined by $196 million due to a $0.14 per barrel decrease in refining throughput margin and lower throughput volumes.
Refining operating expenses, excluding depreciation and amortization expense, increased $0.40 per barrel, or 11%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. Operating expenses increased mainly due to increases in maintenance expense, employee compensation and related benefits, outside services, and energy costs, as well as increased accruals for sales and use taxes. Refining depreciation and amortization expense increased 24% from 2006 to 2007 primarily due to the implementation of new capital projects, increased turnaround and catalyst amortization, and the write-off of costs related to the McKee Refinery as a result of a fire originating in its propane deasphalting unit in February 2007.
Total refining throughput margins for 2007 compared to 2006 were impacted by the following factors:
    Overall, gasoline and distillate margins relative to WTI increased in 2007 compared to 2006 due to a decline in refined product inventory levels resulting from unplanned refinery outages, lower imports, more stringent product specifications and regulations, and heavy industry turnaround activity, as well as moderately stronger demand.
 
    Sour crude oil feedstock differentials to WTI crude oil during 2007 decreased from the strong differentials in 2006. However, other light, sweet crude oils priced at a premium to WTI in 2007; thus, sour crude oil feedstock differentials relative to those other light, sweet crude oils in 2007 were comparable to the wide differentials experienced in 2006. These wide differentials are attributable to continued ample supplies of sour crude oils and heavy sour residual fuel oils on the world market. Differentials on sour crude oil feedstocks also continued to benefit from increased demand for sweet crude oil resulting from lower sulfur specifications for gasoline and diesel and a global increase in refined product demand.
 
    Margins on various secondary refined products such as asphalt, fuel oils, petroleum coke, and sulfur were lower in 2007 as prices for these products did not increase in proportion to the costs of the feedstocks used to produce them.
 
    Throughput volumes decreased 13,000 barrels per day during 2007 compared to 2006 primarily due to a reduction in throughput volumes at our McKee Refinery as a result of the fire discussed above.
Retail
Retail operating income was $249 million for the year ended December 31, 2007 compared to $182 million for the year ended December 31, 2006. This 37% increase in operating income was primarily attributable to

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increased in-store sales and improved retail fuel margins in our U.S. and Canadian retail operations, partially offset by higher selling expenses related mainly to retail reorganization expenses and an increase in the Canadian dollar exchange rate relative to the U.S. dollar.
Corporate Expenses and Other
General and administrative expenses, including corporate depreciation and amortization expense, increased $44 million for the year ended December 31, 2007 compared to the year ended December 31, 2006. This increase was primarily due to 2007 executive retirement expenses, an increase in employee compensation and benefits, including incentive compensation, a $13 million termination fee paid in 2007 for the cancellation of our services agreement with NuStar Energy L.P., and increased charitable contributions, partially offset by 2006 expenses attributable to Premcor headquarters personnel that were not incurred during 2007.
“Other income, net” for the year ended December 31, 2007 included a $91 million pre-tax gain related to a foreign currency exchange rate gain resulting from the repayment of a loan by a foreign subsidiary. “Other income, net” for the year ended December 31, 2006 included a pre-tax gain of $328 million related to the sale of our ownership interest in NuStar GP Holdings, LLC, as discussed in Note 9 of Notes to Consolidated Financial Statements. Excluding these effects, “other income, net” increased $54 million from 2006 to 2007 primarily due to increased interest income related to our significantly higher cash balance during 2007.
Interest and debt expense increased primarily due to the issuance of $2.25 billion of notes in June 2007 to fund the accelerated share repurchase program (as discussed in Note 12 of Notes to Consolidated Financial Statements), increased interest on tax liabilities, and reduced capitalized interest due to a reduced balance of capital projects under construction.
Income tax expense decreased $450 million from 2006 to 2007 mainly as a result of lower income from continuing operations before income tax expense. Our effective tax rate for the year ended December 31, 2007 decreased from the year ended December 31, 2006 primarily due to an increase in the percentage of pre-tax income contributed by the Aruba Refinery, the profits of which are non-taxable in Aruba through December 31, 2010, combined with favorable tax law changes.
Income from discontinued operations, net of income tax expense, increased $493 million from the year ended December 31, 2006 to the year ended December 31, 2007 due primarily to a pre-tax gain of $827 million, or $426 million after tax, on the sale of the Lima Refinery in July 2007 combined with a $67 million increase in net income from the operations of the Lima Refinery between the two years. The increase in net income from the operations of the Lima Refinery was mainly attributable to a 94% increase in the refinery’s throughput margin per barrel, from $8.99 per barrel for the year ended December 31, 2006 to $17.41 per barrel for the six months ended June 30, 2007, which more than offset the effect of a decline in throughput volumes resulting from only six months of operations in 2007 prior to its sale.

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2006 Compared to 2005
Financial Highlights
(millions of dollars, except per share amounts)
                         
    Year Ended December 31,  
    2006 (a)     2005 (a) (b)     Change  
Operating revenues (c) (d)
  $ 87,640     $ 80,616     $ 7,024  
 
                 
 
                       
Costs and expenses:
                       
Cost of sales (b) (c) (d)
    73,863       70,438       3,425  
Refining operating expenses
    3,622       2,816       806  
Retail selling expenses (c)
    719       700       19  
General and administrative expenses
    598       558       40  
Depreciation and amortization expense:
                       
Refining
    985       716       269  
Retail
    87       83       4  
Corporate
    44       37       7  
 
                 
Total costs and expenses
    79,918       75,348       4,570  
 
                 
 
                       
Operating income
    7,722       5,268       2,454  
Equity in earnings of NuStar Energy L.P.
    45       41       4  
Other income, net
    350       53       297  
Interest and debt expense:
                       
Incurred
    (377 )     (334 )     (43 )
Capitalized
    165       66       99  
Minority interest in net income of NuStar GP Holdings, LLC
    (7 )     -       (7 )
 
                 
 
                       
Income from continuing operations before income tax expense
    7,898       5,094       2,804  
Income tax expense
    2,611       1,621        990  
 
                 
 
Income from continuing operations
    5,287       3,473       1,814  
Income from discontinued operations, net of income tax expense (a)
    176       117       59  
 
                 
 
                       
Net income
    5,463       3,590       1,873  
Preferred stock dividends
    2       13       (11 )
 
                 
 
                       
Net income applicable to common stock
  $ 5,461     $ 3,577     $ 1,884  
 
                 
 
                       
Earnings per common share - assuming dilution:
                       
Continuing operations
  $ 8.36     $ 5.90     $ 2.46  
Discontinued operations
    0.28       0.20       0.08  
 
                 
Total
  $ 8.64     $ 6.10     $ 2.54  
 
                 
 
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,  
    2006     2005 (b)     Change  
Refining (a):
                       
Operating income (b)
  $ 8,182     $ 5,709     $ 2,473  
Throughput margin per barrel (e)
  $ 12.47     $ 11.10     $ 1.37  
Operating costs per barrel:
                       
Refining operating expenses
  $ 3.53     $ 3.17     $ 0.36  
Depreciation and amortization
    0.96       0.81       0.15  
 
                 
Total operating costs per barrel
  $ 4.49     $ 3.98     $ 0.51  
 
                 
 
                       
Throughput volumes (thousand barrels per day):
                       
Feedstocks:
                       
Heavy sour crude
    697       548       149  
Medium/light sour crude
    618       610       8  
Acidic sweet crude
    65       103       (38 )
Sweet crude
    752       620       132  
Residuals
    234       181       53  
Other feedstocks
     147       132       15  
 
                 
Total feedstocks
    2,513       2,194       319  
Blendstocks and other
      298       241       57  
 
                 
Total throughput volumes
    2,811       2,435       376  
 
                 
 
                       
Yields (thousand barrels per day):
                       
Gasolines and blendstocks
    1,348       1,144       204  
Distillates
    891       745       146  
Petrochemicals
    80       70       10  
Other products (f)
     491       477       14  
 
                 
Total yields
    2,810       2,436       374  
 
                 
 
                       
Retail - U.S.:
                       
Operating income
  $ 113     $ 81     $ 32  
Company-operated fuel sites (average)
    982       1,024       (42 )
Fuel volumes (gallons per day per site)
    4,985       4,830       155  
Fuel margin per gallon
  $ 0.162     $ 0.154     $ 0.008  
Merchandise sales
  $ 960     $ 934     $ 26  
Merchandise margin (percentage of sales)
    29.6 %     29.7 %     (0.1 )%
Margin on miscellaneous sales (c)
  $ 85     $ 68     $ 17  
Retail selling expenses (c)
  $ 485     $ 482     $ 3  
Depreciation and amortization expense
  $ 60     $ 60     $ -  
 
                       
Retail - Canada:
                       
Operating income
  $ 69     $ 73     $ (4 )
Fuel volumes (thousand gallons per day)
    3,176       3,204       (28 )
Fuel margin per gallon
  $ 0.217     $ 0.211     $ 0.006  
Merchandise sales
  $ 167     $ 150     $ 17  
Merchandise margin (percentage of sales)
    27.4 %     25.6 %     1.8 %
Margin on miscellaneous sales
  $ 32     $ 30     $ 2  
Retail selling expenses
  $ 234     $ 218     $ 16  
Depreciation and amortization expense
  $ 27     $ 23     $ 4  
 
See the footnote references on pages 33 and 34.

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Refining Operating Highlights by Region (g)
(millions of dollars, except per barrel amounts)
                         
    Year Ended December 31,  
    2006     2005 (b)     Change  
 
                       
Gulf Coast:
                       
Operating income
  $ 5,109     $ 3,962     $ 1,147  
Throughput volumes (thousand barrels per day) (h)
    1,532       1,364       168  
Throughput margin per barrel (e)
  $ 13.23     $ 11.73     $ 1.50  
Operating costs per barrel:
                       
Refining operating expenses
  $ 3.26     $ 3.03     $ 0.23  
Depreciation and amortization
    0.84       0.74       0.10  
 
                 
Total operating costs per barrel
  $ 4.10     $ 3.77     $ 0.33  
 
                 
 
                       
Mid-Continent (a) (i):
                       
Operating income
  $ 1,041     $ 665     $ 376  
Throughput volumes (thousand barrels per day) (h)
    410       311       99  
Throughput margin per barrel (e)
  $ 11.32     $ 10.01     $ 1.31  
Operating costs per barrel:
                       
Refining operating expenses
  $ 3.36     $ 3.42     $ (0.06 )
Depreciation and amortization
    1.00       0.74       0.26  
 
                 
Total operating costs per barrel
  $ 4.36     $ 4.16     $ 0.20  
 
                 
 
                       
Northeast:
                       
Operating income
  $ 944     $ 725     $ 219  
Throughput volumes (thousand barrels per day) (h)
    563       448       115  
Throughput margin per barrel (e)
  $ 9.80     $ 8.33     $ 1.47  
Operating costs per barrel:
                       
Refining operating expenses
  $ 4.10     $ 3.11     $ 0.99  
Depreciation and amortization
    1.11       0.78       0.33  
 
                 
Total operating costs per barrel
  $ 5.21     $ 3.89     $ 1.32  
 
                 
 
                       
West Coast:
                       
Operating income
  $ 1,088     $ 978     $ 110  
Throughput volumes (thousand barrels per day)
    306       312       (6 )
Throughput margin per barrel (e)
  $ 15.07     $ 13.42     $ 1.65  
Operating costs per barrel:
                       
Refining operating expenses
  $ 4.04     $ 3.59     $ 0.45  
Depreciation and amortization
    1.27       1.23       0.04  
 
                 
Total operating costs per barrel
  $ 5.31     $ 4.82     $ 0.49  
 
                 
 
                       
Operating income for regions above
  $ 8,182     $ 6,330     $ 1,852  
LIFO charge (b)
    -       (621 )     621  
 
                 
Total refining operating income
  $ 8,182     $ 5,709     $ 2,473  
 
                 
 
See the footnote references on pages 33 and 34.

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Average Market Reference Prices and Differentials (j)
(dollars per barrel)
                         
    Year Ended December 31,
    2006   2005   Change
Feedstocks:
                       
WTI crude oil
  $ 66.00     $ 56.44     $ 9.56  
WTI less sour crude oil at U.S. Gulf Coast (k)
    7.01       6.88       0.13  
WTI less Mars crude oil
    7.12       6.45       0.67  
WTI less ANS crude oil
    2.47       3.06       (0.59 )
WTI less Maya crude oil
    14.80       15.58       (0.78 )
 
                       
Products:
                       
U.S. Gulf Coast:
                       
Conventional 87 gasoline less WTI
    11.34       10.60       0.74  
No. 2 fuel oil less WTI
    9.80       11.57       (1.77 )
Propylene less WTI
    8.78       10.11       (1.33 )
U.S. Mid-Continent:
                       
Conventional 87 gasoline less WTI
    12.16       10.39       1.77  
Low-sulfur diesel less WTI
    18.59       15.54       3.05  
U.S. Northeast:
                       
Conventional 87 gasoline less WTI
    10.62       8.95       1.67  
No. 2 fuel oil less WTI
    9.60       11.60       (2.00 )
Lube oils less WTI
    55.56       33.68       21.88  
U.S. West Coast:
                       
CARBOB 87 gasoline less ANS
    21.52       19.42       2.10  
CARB diesel less ANS
    23.96       21.91       2.05  
 
The following notes relate to references on pages 30 through 33.
(a)   Effective July 1, 2007, we sold our Lima Refinery to Husky. Therefore, the results of operations of the Lima Refinery are reported as discontinued operations, and all refining operating highlights, both consolidated and for the Mid-Continent region, exclude the Lima Refinery.
 
(b)   Includes the operations related to the Premcor Acquisition commencing on September 1, 2005. Cost of sales and refining operating income presented for the year ended December 31, 2005 include the effect of 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 in applying Valero’s LIFO accounting policy. This charge 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.
 
(c)   Certain amounts previously reported in 2006 and 2005 for operating revenues, cost of sales, retail selling expenses, and margin on miscellaneous sales have been reclassified for comparability with amounts reported in 2007.
 
(d)   Operating revenues and cost of sales both include approximately $7.8 billion for the year ended December 31, 2005 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. Commencing January 1, 2006, we adopted EITF Issue No. 04-13 which requires that such buy/sell arrangements be accounted for as one transaction, thereby resulting in no recognition of revenues and cost of sales for these transactions.
 
(e)   Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.
 
(f)   Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
 
(g)   The regions reflected herein contain the following refineries: 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, and Memphis Refineries; the Northeast refining region includes the Quebec City, Paulsboro, and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.
 
(h)   Throughput volumes for the Gulf Coast, Mid-Continent, and Northeast regions for the year ended December 31, 2006 include 287,000, 155,000, and 201,000 barrels per day, respectively, related to the operations of the refineries acquired from Premcor on September 1, 2005. Throughput volumes for the Gulf Coast, Mid-Continent, and Northeast regions for the year ended

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    December 31, 2005 include 78,000, 53,000, 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, 157,000, 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 for the year ended December 31, 2005 includes the operations of the Denver Refinery, which was sold on May 31, 2005 to Suncor Energy (U.S.A.) Inc. Throughput volumes for the Mid-Continent region for the year ended December 31, 2005 include 15,000 barrels per day related to the Denver Refinery.
 
(j)   The average market reference prices and differentials, with the exception of the propylene and lube oil differentials, are based on posted prices from Platts 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 9% for the year ended December 31, 2006 compared to the year ended December 31, 2005 primarily as a result of higher refined product prices combined with additional throughput volumes from the former Premcor refinery operations. Operating income and income from continuing operations for the year ended December 31, 2006 increased significantly compared to the year ended December 31, 2005. Operating income increased $2.5 billion, or 47%, from 2005 to 2006 due to a $2.5 billion increase in the refining segment. The refining segment operating income and income from continuing operations exclude the operations of the Lima Refinery which are classified as discontinued operations due to our sale of that refinery as discussed in Note 2 of Notes to Consolidated Financial Statements.
Refining
Operating income for our refining segment increased from $5.7 billion for the year ended December 31, 2005 to $8.2 billion for the year ended December 31, 2006 resulting from a 15% increase in throughput volumes and an increase in refining throughput margin of $1.37 per barrel, or 12%, partially offset by increased refining operating expenses (including depreciation and amortization expense) of $1.1 billion. In addition, the increase in the 2006 results was partially attributable to the unfavorable impact in 2005 of a $621 million pre-tax LIFO charge related to the difference between the fair market value recorded for the inventories acquired in the Premcor Acquisition under purchase accounting and the amounts required to be recorded in applying Valero’s LIFO accounting policy.
The change in refining throughput margin for 2006 compared to 2005 was impacted by the following factors:
    Throughput volumes increased 376,000 barrels per day during 2006 compared to 2005 due to 449,000 barrels per day of incremental throughput from the three former Premcor refineries, offset to some extent by the sale of the Denver Refinery in 2005 and significant planned and unplanned downtime at several of our refineries in 2006.
 
    Overall, gasoline and distillate margins increased in 2006 compared to 2005 due to significantly improved margins in the first half of 2006 attributable to increased foreign and U.S. demand, limited capacity additions, major industry turnaround activity, and continuing outages from the 2005 hurricanes. However, the 2006 increase in gasoline and distillate margins was somewhat diminished in the second half of 2006 due to excess refined product supply and the higher margins experienced in September and October of 2005 due to the impact of Hurricanes Katrina and Rita.
 
    Differentials on sour crude oil feedstocks during 2006 were essentially unchanged from the strong differentials in 2005, and remained wide due to continued ample supplies of sour crude oils and heavy sour residual fuel oils on the world market. Differentials on sour crude oil feedstocks also continued to benefit from increased demand for sweet crude oil resulting from lower sulfur specifications for

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      gasoline and diesel and a global increase in refined product demand, particularly in Asia, which resulted in higher utilization rates by refineries that require sweet crude oil as feedstock.
 
    Throughput margin improved in 2006 due to the negative impact in 2005 of pre-tax losses of approximately $525 million on hedges related to forward sales of distillates and associated forward purchases of crude oil.
 
    Margins on secondary refined products such as petroleum coke and sulfur were lower in 2006 due to an increase in the price of crude oil from 2005 to 2006.
Refining operating expenses, excluding depreciation and amortization expense, were 29% higher for the year ended December 31, 2006 compared to the year ended December 31, 2005, primarily due to the Premcor Acquisition on September 1, 2005. Excluding the effect of the Premcor Acquisition, operating expenses increased 5% due mainly to increases in maintenance expense, employee compensation and related benefits, outside services, and catalyst and chemicals, partially offset by reduced energy costs. Refining depreciation and amortization expense increased 38% from 2005 to 2006 primarily due to the Premcor Acquisition, the implementation of new capital projects, and increased turnaround and catalyst amortization.
Retail
Retail operating income was $182 million for the year ended December 31, 2006 compared to $154 million for the year ended December 31, 2005. This 18% increase in operating income was primarily attributable to improved retail fuel margins and increased in-store sales in the U.S. system.
Corporate Expenses and Other
General and administrative expenses, including corporate depreciation and amortization expense, increased $47 million for the year ended December 31, 2006 compared to the year ended December 31, 2005. The increase was primarily due to increases in employee compensation and benefits, stock-based compensation expense, environmental expenses, and charitable contributions as well as the favorable resolution of a California excise tax dispute in 2005. These increases were partially offset by a decrease in variable compensation expense and 2005 nonrecurring expenses attributable to Premcor headquarters personnel.
“Other income, net” for the year ended December 31, 2006 included a pre-tax gain of $328 million related to the sale of our ownership interest in NuStar GP Holdings, LLC, as discussed in Note 9 of Notes to Consolidated Financial Statements.
Interest and debt expense incurred increased from 2005 to 2006 due to the effect of a full year of interest incurred in 2006 on the debt assumed in the Premcor Acquisition, partially offset by a reduction in other debt outstanding. Capitalized interest increased due to an increase in capital projects, including projects at the three former Premcor refineries.
Income tax expense increased $990 million from 2005 to 2006 mainly as a result of a 55% increase in income from continuing operations before income tax expense. Our effective tax rate for the year ended December 31, 2006 increased from the year ended December 31, 2005 as a lower percentage of our pre-tax income was contributed by the Aruba Refinery, the profits of which are non-taxable in Aruba through December 31, 2010. This increase in the effective tax rate was partially offset by the effects of new tax legislation in both Texas and Canada in 2006.

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OUTLOOK
Based on current forward market indicators, our outlook for refined product margins for the remainder of 2008 is positive. With respect to the gasoline market, winter-grade gasoline inventories increased in late 2007 and early 2008 in anticipation of the normal cycle of industry-wide plant maintenance that occurs in the first quarter. As spring maintenance activities occur, refined product supplies are expected to decline. In addition, the industry will soon be making the transition from winter-grade gasoline to summer-grade gasoline, which is more difficult and costly to produce due to more stringent specifications and thus generally contributes to a decline in inventories. Furthermore, we expect strong diesel margins to continue and provide an incentive to refiners to maximize diesel production, thereby further limiting gasoline supplies. These anticipated supply constraints, combined with a typical seasonal increase in demand, are expected to result in higher gasoline margins as the summer driving season approaches.
Our outlook for on-road diesel margins is also favorable as on-road diesel demand continues to be good and on-road diesel inventory levels in 2008 are below 2007 levels on a days-of-supply basis. As a result, we expect on-road diesel margins to remain strong.
In regard to feedstocks, sour crude oil differentials are expected to remain favorable during 2008. Residual fuel oil prices have not increased as much as crude oil prices, which should support wider differentials for sour crude oil since complex refiners can substitute residual fuel oil for a portion of their sour crude oil requirements if residual fuel oil becomes more economic to process than crude oil. In addition, new supplies of medium sour crude oil from the Gulf of Mexico in 2008 should contribute to continuing wide sour crude oil differentials.
On January 25, 2008, our Aruba Refinery experienced a fire in its vacuum unit. We are in the process of making the necessary repairs and we resumed partial operation of the refinery in mid-February. We expect to resume full operations in the second quarter of 2008. Although we have not completed our assessment of the extent of damages, we do not believe that this incident will have a material adverse effect on our results of operations for 2008.
Regarding other operations for 2008, we began scheduled maintenance on our coker drums at our Port Arthur Refinery in the first quarter that will reduce throughput volumes in the Gulf Coast region for about three months beginning in early February. Otherwise, our turnaround schedule for 2008 is relatively light, which should benefit our results of operations during the year.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows for the Year Ended December 31, 2007
Net cash provided by operating activities for the year ended December 31, 2007 was $5.3 billion compared to $6.3 billion for the year ended December 31, 2006. The decrease in cash generated from operating activities was due primarily to the decrease in operating income discussed above under “Results of Operations” and a $900 million decrease in the eligible trade receivables sold under our accounts receivable sales facility, as discussed in Note 4 of Notes to Consolidated Financial Statements. Other changes in cash provided by or used for working capital during the years ended December 31, 2007 and 2006 are shown in Note 16 of Notes to Consolidated Financial Statements. Both receivables and accounts payable increased in 2007 due to a significant increase in gasoline, distillate, and crude oil prices at December 31, 2007 compared to such prices at the end of 2006.
Cash flows related to the discontinued operations of the Lima Refinery have been combined with the cash flows from continuing operations within each category in the consolidated statement of cash flows for each period presented. Cash provided by operating activities related to our discontinued operations was $260 million and

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$215 million for the years ended December 31, 2007 and 2006, respectively. Cash used in investing activities related to the Lima Refinery was $14 million and $133 million for the years ended December 31, 2007 and 2006, respectively.
The net cash generated from operating activities during the year ended December 31, 2007, combined with $2.2 billion of proceeds from the issuance of long-term notes, $2.4 billion of proceeds from the sale of our Lima Refinery, a $311 million benefit from tax deductions in excess of recognized stock-based compensation cost, and $159 million of proceeds from the issuance of common stock related to our employee benefit plans, were used mainly to:
    fund $2.8 billion of capital expenditures and deferred turnaround and catalyst costs;
 
    purchase 84.3 million shares of our common stock at a cost of $5.8 billion;
 
    make an early long-term note redemption of $183 million and scheduled long-term note repayments of $280 million;
 
    fund capital contributions, net of distributions, of $209 million to the Cameron Highway Oil Pipeline Project mainly to enable the joint venture to redeem all of its outstanding debt;
 
    fund contingent earn-out payments in connection with the acquisition of the St. Charles Refinery and the Delaware City Refinery of $50 million and $25 million, respectively;
 
    pay common stock dividends of $271 million; and
 
    increase available cash on hand by $874 million.
Cash Flows for the Year Ended December 31, 2006
Net cash provided by operating activities for the year ended December 31, 2006 was $6.3 billion compared to $5.9 billion for the year ended December 31, 2005. The increase in cash generated from operating activities was primarily due to the significant increase in operating income discussed above under “Results of Operations,” partially offset by a $1.2 billion decrease from an unfavorable change in working capital between the years and a $1.0 billion increase in current income tax expense. Changes in cash provided by or used for working capital during the years ended December 31, 2006 and 2005 are shown in Note 16 of Notes to Consolidated Financial Statements. The primary difference in the working capital changes between the two years resulted from a favorable working capital change in 2005 attributable to 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 in 2006 due mainly to higher prices for gasoline and crude oil at December 31, 2006 compared to such prices at the end of 2005.
Cash provided by operating activities related to our discontinued operations was $215 million and $121 million for the years ended December 31, 2006 and 2005, respectively. Cash used in investing activities related to the Lima Refinery was $133 million and $42 million for the years ended December 31, 2006 and 2005, respectively.
The net cash generated from operating activities during the year ended December 31, 2006, combined with $880 million of proceeds from the sale of our ownership interest in NuStar GP Holdings, LLC, a $206 million benefit from tax deductions in excess of recognized stock-based compensation cost, and $122 million of proceeds from the issuance of common stock related to our employee benefit plans, were used mainly to:
    fund $3.8 billion of capital expenditures and deferred turnaround and catalyst costs;
 
    purchase 34.6 million shares of our common stock at a cost of $2.0 billion;
 
    make long-term note repayments of $249 million;
 
    fund $101 million of contingent earn-out payments in connection with the acquisition of Basis Petroleum, Inc., the St. Charles Refinery, and the Delaware City Refinery;
 
    terminate our interest rate swap contracts for $54 million;

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    pay common and preferred stock dividends of $184 million; and
 
    increase available cash on hand by $1.2 billion.
Capital Investments
During the year ended December 31, 2007, we expended $2.3 billion for capital expenditures and $518 million for deferred turnaround and catalyst costs. Capital expenditures for the year ended December 31, 2007 included $614 million of costs related to environmental projects. In addition, we expended $75 million for amounts due under contingent earn-out agreements.
In connection with our acquisition of the St. Charles Refinery in 2003, the seller was entitled to receive payments in any of the seven years following this acquisition if certain average refining margins during any of those years exceeded a specified level (see the discussion in Note 22 of Notes to Consolidated Financial Statements). In connection with the Premcor Acquisition, we assumed Premcor’s obligation under a contingent earn-out agreement related to Premcor’s acquisition of the Delaware City Refinery from Motiva Enterprises LLC. Payments due under these earn-out arrangements were limited based on annual and aggregate limits. During 2007, we made earn-out payments of $50 million related to the acquisition of the St. Charles Refinery and $25 million related to the acquisition of the Delaware City Refinery (the maximum remaining payment based on the aggregate limitation under that agreement). In January 2008, we made a $25 million earn-out payment related to the St. Charles Refinery, which was the final payment based on the aggregate limitation under that agreement.
For 2008, we expect to incur approximately $4.5 billion for capital investments, including approximately $4.1 billion for capital expenditures (approximately $575 million of which is for environmental projects) and approximately $400 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes anticipated expenditures related to strategic acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.
In May and June of 2007, we made cash capital contributions of $190 million and $25 million, respectively, to the Cameron Highway Oil Pipeline Project, representing our 50% portion of the amount required for the Cameron Highway Oil Pipeline joint venture to redeem its fixed-rate notes and variable-rate debt, respectively. Our capital contributions, along with equal capital contributions from the other 50% joint venture partner, were used to redeem all of the joint venture’s outstanding debt.
Lima Refinery Disposition
Effective July 1, 2007, we sold our Lima Refinery to Husky. Proceeds from the sale were approximately $2.4 billion, including approximately $550 million from the sale of working capital to Husky, primarily related to the sale of inventory by our marketing and supply subsidiary. The sale resulted in a pre-tax gain of $827 million, or $426 million after tax, which is presented in “income from discontinued operations, net of income tax expense” in the consolidated statement of income for the year ended December 31, 2007. In connection with the sale, we entered into a transition services agreement with Husky under which we agreed to provide certain accounting and administrative services to Husky, with the services terminating by July 31, 2008. A significant portion of these services has been transitioned to Husky as of February 27, 2008.

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Contractual Obligations
Our contractual obligations as of December 31, 2007 are summarized below (in millions).
                                                         
    Payments Due by Period        
    2008     2009     2010     2011     2012     Thereafter     Total  
Long-term debt and capital lease obligations
  $ 362     $ 215     $ 39     $ 424     $ 765     $ 5,114     $ 6,919  
Operating lease obligations
    384       282       188       110       54       190       1,208  
Purchase obligations
    27,378       7,056       858       707       540       2,113       38,652  
Other long-term liabilities
    -       197        185       177       176       1,075       1,810  
 
                                         
Total
  $ 28,124     $ 7,750     $ 1,270     $ 1,418     $ 1,535     $ 8,492     $ 48,589  
 
                                         
Long-Term Debt and Capital Lease Obligations
Payments for long-term debt and capital lease obligations in the table above reflect stated values and minimum rental payments, respectively.
During February 2007, we redeemed our 9.25% senior notes that were scheduled to mature in 2010 for $183 million. In addition, during the year ended December 31, 2007, we made scheduled debt repayments of $280 million related to various notes as discussed in Note 12 of Notes to Consolidated Financial Statements.
In April 2007, we borrowed $3 billion under a 364-day term credit agreement with a financial institution to fund the accelerated share repurchase program discussed in Note 14 of Notes to Consolidated Financial Statements. In May 2007, we repaid $500 million of the borrowings under the 364-day term credit agreement. The remaining balance of $2.5 billion was repaid in June 2007 using available cash and proceeds from the issuance of $2.25 billion of notes, as discussed in Note 12 of Notes to Consolidated Financial Statements.
As of December 31, 2007, “current portion of long-term debt and capital lease obligations” as reflected in the consolidated balance sheet consisted primarily of our 9.5% senior notes with a stated value of $350 million and a maturity date of February 2013, which were redeemed in February 2008 as discussed in Note 12 of Notes to Consolidated Financial Statements.
Our agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt to below investment grade ratings by Moody’s Investors Service and Standard & Poor’s Ratings Services, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. As of December 31, 2007, all of our ratings on our senior unsecured debt are at or above investment grade level as follows:
     
Rating Agency   Rating
Standard & Poor’s Ratings Services
  BBB (stable outlook)
Moody’s Investors Service
  Baa3 (positive outlook)
Fitch Ratings
  BBB (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. The operating lease obligations reflected in the table above have been reduced by related obligations that are included in “other long-term liabilities.”

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Purchase Obligations
A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum, or variable price provisions, and (iii) the approximate timing of the transaction. We have various purchase obligations including industrial gas and chemical supply arrangements (such as hydrogen supply arrangements), crude oil and other feedstock supply arrangements, and various throughput and terminalling agreements. We enter into these contracts to ensure an adequate supply of utilities and feedstock and adequate storage capacity 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, 2007, our short-term and long-term purchase obligations increased by $7.0 billion from the amount reported as of December 31, 2006. The increase is primarily attributable to higher crude oil and other feedstock prices at December 31, 2007 compared to December 31, 2006.
Other Long-term Liabilities
Our “other long-term liabilities” are described in Note 13 of Notes to Consolidated Financial Statements. For purposes of reflecting amounts for other long-term liabilities in the table above, we have made our best estimate of expected payments for each type of liability based on information available as of December 31, 2007.
Other Commercial Commitments
As of December 31, 2007, our committed lines of credit were as follows:
         
    Borrowing    
    Capacity   Expiration
Revolving credit facility
  $2.5 billion   November 2012
Canadian revolving credit facility
  Cdn. $115 million   December 2012
As of December 31, 2007, we had $502 million of letters of credit outstanding under uncommitted short-term bank credit facilities, $292 million of letters of credit outstanding under our committed revolving credit facility, and Cdn. $11 million of letters of credit outstanding under our Canadian committed revolving credit facility. These letters of credit expire during 2008 and 2009.
Stock Purchase Programs
During the first quarter of 2007, we had two stock purchase programs that had been previously approved by our board of directors. One program authorized our purchase of our common stock in open market transactions to satisfy employee benefit plan requirements and the other was a $2 billion common stock purchase program. Stock purchases under the programs are made from time to time at prevailing prices as permitted by securities laws and other legal requirements, subject to market conditions and other factors. The programs do not have a scheduled expiration date.
On April 25, 2007, our board of directors approved an amendment to our $2 billion common stock purchase program to increase the authorized purchases under the program to $6 billion. In conjunction with the increase in our common stock purchase program, we entered into an agreement with a financial institution to purchase $3 billion of our shares under an accelerated share repurchase program, and in late April 2007, 42.1 million shares were purchased under this agreement. The purchase of these shares was funded with a short-term bridge loan, which we subsequently replaced with longer-term financing as described in Note 12 of Notes to Consolidated Financial Statements. The cost of the shares purchased under the accelerated share repurchase program was to be adjusted, with the final purchase cost based on a discount to the average trading price of our

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common stock, weighted by the daily volume of shares traded, during the program period. Any adjustment to the cost could be paid in cash or stock, at our option.
The accelerated share repurchase program was completed on July 23, 2007, and we elected to pay in cash an additional $94 million for the shares purchased. This cash payment had a dilutive effect on our computation of earnings per common share from continuing operations assuming dilution for the year ended December 31, 2007 (see Note 15 of Notes to Consolidated Financial Statements).
During 2007, we purchased 70.5 million shares of our common stock for $4.9 billion under our $6 billion common stock purchase program, including shares purchased under the accelerated share repurchase program discussed above, and 13.8 million shares for $915 million in connection with the administration of our employee benefit plans. These purchases represented approximately 14% of our outstanding shares of common stock as of December 31, 2006. During 2008 (through February 22), we have purchased 4.9 million shares of our common stock for $317 million under our two stock purchase programs.
On February 28, 2008, our board of directors approved a new $3 billion stock purchase program. This program is in addition to the $6 billion program discussed above. This new $3 billion program has no expiration date.
Pension Plan Funded Status
During 2007, we contributed $143 million to our qualified pension plans. Based on a 6.00% discount rate and fair values of plan assets as of December 31, 2007, the fair value of the assets in our qualified pension plans was equal to approximately 120% of the projected benefit obligation under those plans as of the end of 2007.
Although we have only $2 million of minimum required contributions to our qualified pension plans during 2008 under the Employee Retirement Income Security Act, we expect to use expected available cash to contribute approximately $100 million to our qualified plans during 2008.
Environmental Matters
As discussed in Note 23 of Notes to Consolidated Financial Statements, we are subject to extensive federal, state, and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our refineries could require material additional expenditures to comply with environmental laws and regulations.
Tax Matters
As discussed in Note 22 of Notes to Consolidated Financial Statements, we are subject to extensive tax liabilities. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Many of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties.
Effective January 1, 2007, the Government of Aruba (GOA) enacted a turnover tax on revenues from the sale of goods produced and services rendered in Aruba. The turnover tax, which is 3% for on-island sales and services and 1% on export sales, is being assessed by the GOA on sales by our Aruba Refinery. However, due to a previous tax holiday that was granted to our Aruba Refinery by the GOA through December 31, 2010 as well as other reasons, we believe that exports by our Aruba Refinery should not be subject to this turnover tax. No amounts have been accrued on exports with respect to this turnover tax. We have commenced arbitration

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proceedings with the Netherlands Arbitration Institute pursuant to which we will seek to enforce our rights under the tax holiday. We have also filed protests of these assessments through proceedings in Aruba.
Other
During the first quarter of 2007, our McKee Refinery was shut down due to a fire originating in its propane deasphalting unit, resulting in business interruption losses for which we have submitted claims to our insurance carriers under our insurance policies. In the fourth quarter of 2007, we received an immaterial initial payment from the insurance carriers on our claims, the proceeds from which were recorded as a reduction to “cost of sales.” No additional amount has been accrued related to these claims pending future settlements with the insurance carriers.
In November 2007, we announced our plan to explore strategic alternatives related to our Aruba Refinery. In January 2008, we announced our plan to explore strategic alternatives related to our Memphis and Krotz Springs Refineries.
Our refining and marketing operations have a concentration of customers in the refining industry and customers who are refined product wholesalers and retailers. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively, in that these customers may be similarly affected by changes in economic or other conditions. However, we believe that our portfolio of accounts receivable is sufficiently diversified to the extent necessary to minimize potential credit risk. Historically, we have not had any significant problems collecting our accounts receivable.
We believe that we have sufficient funds from operations and, to the extent necessary, from the public and private capital markets and bank markets, to fund our ongoing operating requirements. We expect that, to the extent necessary, we can raise additional funds from time to time through equity or debt financings. However, there can be no assurances regarding the availability of any future financings or whether such financings can be made available on terms that are acceptable to us.
OFF-BALANCE SHEET ARRANGEMENTS
Accounts Receivable Sales Facility
As of December 31, 2007, 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. During the third quarter of 2007, we reduced the amount of eligible receivables sold to the third-party financial institutions by $900 million. Therefore, as of December 31, 2007, the amount of eligible receivables sold to the third-party financial institutions was $100 million. 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, 2007, the termination of this program would not have had a material effect on our liquidity, particularly considering the reduction in the utilization of the program during 2007 as discussed above, 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.

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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, and is not expected to have, a material effect on our consolidated financial statements.
CRITICAL ACCOUNTING POLICIES INVOLVING CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The following summary provides further information about our critical accounting policies that involve critical accounting estimates, and should be read in conjunction with Note 1 of Notes to Consolidated Financial Statements, which summarizes our significant accounting policies. The following accounting policies involve estimates that are considered critical due to the level of sensitivity and judgment involved, as well as the impact on our consolidated financial position and results of operations. We believe that all of our estimates are reasonable.
Impairment of Assets
Long-lived assets (excluding goodwill, intangible assets with indefinite lives, equity method investments, and deferred tax assets) are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. An impairment loss should be recognized only if the carrying amount of the asset is not recoverable and exceeds its fair value. Goodwill and intangible assets that have indefinite useful lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. An impairment loss should be recognized if the carrying amount of the asset exceeds its fair value. We evaluate our equity method investments for impairment when there is evidence that we may not be able to recover the carrying amount of our investments or the investee is unable to sustain an earnings capacity that justifies the carrying amount. A loss in the value of an investment that is other than a temporary decline is recognized currently in earnings, and is based on the difference between the estimated current fair value of the investment and its carrying amount.
In order to test for recoverability, management must make estimates of projected cash flows related to the asset being evaluated which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment. Due to the significant subjectivity of the assumptions used to test for recoverability and to determine fair value, changes in market conditions could result in significant impairment charges in the future, thus affecting our earnings. Our impairment evaluations are based on assumptions that are consistent with our business plans. However, providing sensitivity analysis if other assumptions were used in performing the impairment evaluations is not practicable due to the significant number of assumptions involved in the estimates.
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,

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additional remedial actions, or increased capital expenditures and operating costs that cannot be assessed with certainty at this time.
Accruals for environmental liabilities are based on best estimates of probable undiscounted future costs assuming currently available remediation technology and applying current regulations, as well as our own internal environmental policies. However, environmental liabilities are difficult to assess and estimate due to uncertainties related to the magnitude of possible remediation, the timing of such remediation, and the 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, 2007, 2006, and 2005 is included in Note 23 of Notes to Consolidated Financial Statements. We believe that we have adequately accrued for our environmental exposures.
Pension and Other Postretirement Benefit Obligations
We have significant pension and other postretirement benefit liabilities and costs that are developed from actuarial valuations. Inherent in these valuations are key assumptions including discount rates, expected return on plan assets, future compensation increases, and health care cost trend rates. Changes in these assumptions are primarily influenced by factors outside of 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, 2007 and net periodic benefit cost for the year ending December 31, 2008 (in millions):
                 
            Other
    Pension   Postretirement
    Benefits   Benefits
Increase in projected benefit obligation resulting from:
               
Discount rate decrease
  $ 56     $ 15  
Compensation rate increase
    23       -  
Health care cost trend rate increase
    -       9  
 
               
Increase in expense resulting from:
               
Discount rate decrease
    7       1  
Expected return on plan assets decrease
    3       -  
Compensation rate increase
    5       -  
Health care cost trend rate increase
    -       1  
Tax Liabilities
Our operations are subject to extensive tax liabilities, including federal, state, and foreign income taxes. We are also subject to various transactional taxes such as excise, sales/use, payroll, franchise, withholding, and ad

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valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed, and the implementation of future legislative and regulatory tax initiatives could result in increased tax liabilities that cannot be predicted at this time. In addition, we have received claims from various jurisdictions related to certain tax matters. Tax liabilities include potential assessments of penalty and interest amounts.
We record tax liabilities based on our assessment of existing tax laws and regulations. A contingent loss related to a transactional tax claim is recorded if the loss is both probable and estimable. The recording of our tax liabilities requires significant judgments and estimates. Actual tax liabilities can vary from our estimates for a variety of reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due. In addition, in determining our income tax provision, we must assess the likelihood that our deferred tax assets, primarily consisting of net operating loss and tax credit carryforwards, will be recovered through future taxable income. Significant judgment is required in estimating the amount of valuation allowance, if any, that should be recorded against those deferred income tax assets. If our actual results of operations differ from such estimates or our estimates of future taxable income change, the valuation allowance may need to be revised. However, an estimate of the sensitivity to earnings that would result from changes in the assumptions and estimates used in determining our tax liabilities is not practicable due to the number of assumptions and tax laws involved, the various potential interpretations of the tax laws, and the wide range of possible outcomes.
Legal Liabilities
A variety of claims have been made against us in various lawsuits. Although we have been successful in defending litigation in the past, we cannot be assured of similar success in future litigation due to the inherent uncertainty of litigation and the individual fact circumstances in each case. We record a liability related to a loss contingency attributable to such legal matters if we determine the loss to be both probable and estimable. The recording of such liabilities requires judgments and estimates, the results of which can vary significantly from actual litigation results due to differing interpretations of relevant law and differing opinions regarding the degree of potential liability and the assessment of reasonable damages. However, an estimate of the sensitivity to earnings if other assumptions were used in recording our legal liabilities is not practicable due to the number of contingencies that must be assessed and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss.
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 $3.9 billion and $3.7 billion as of December 31, 2007 and 2006, respectively, and the fair value of such inventories was $10.1 billion and $6.6 billion as of December 31, 2007 and 2006, respectively. From time to time, we use derivative commodity instruments to hedge the price risk of forecasted transactions such as forecasted feedstock and product purchases, refined product sales, and natural gas purchases (cash flow hedges). We also use derivative commodity instruments that do not receive hedge accounting treatment to manage our exposure to price volatility on a portion of our refinery feedstock and refined product inventories and on certain forecasted feedstock and product purchases, refined product sales, and natural gas purchases. These derivative instruments are considered economic hedges for which changes in their fair value are recorded currently in cost of sales. Finally, we enter into derivative commodity instruments based on our fundamental and technical analysis of

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market conditions that we mark to market for accounting purposes. See “Derivative Instruments” in Note 1 of Notes to Consolidated Financial Statements for a discussion of our accounting for the various types of derivative transactions.
The types of instruments used in our hedging and trading activities described above include swaps, futures, and options. Our positions in derivative commodity instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy which has been approved by our board of directors.
The following tables provide information about our derivative commodity instruments as of December 31, 2007 and 2006 (dollars in millions, except for the weighted-average pay and receive prices as described below), including:
    fair value hedges, which are used to hedge our recognized refining inventories and unrecognized firm commitments (i.e., binding agreements to purchase inventories in the future);
 
    cash flow hedges, which are used to hedge our forecasted feedstock and product purchases, refined product sales, and natural gas purchases;
 
    economic hedges (hedges not designated as fair value or cash flow hedges), which are used to:
    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
    derivative commodity instruments held or issued for trading purposes.
The gain or loss on a derivative instrument designated and qualifying as a fair value hedge and the offsetting loss or gain on the hedged item are recognized currently in income in the same period. The effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is initially reported as a component of “other comprehensive income” and is then recorded in income in the period or periods during which the hedged forecasted transaction affects income. The ineffective portion of the gain or loss on the cash flow derivative instrument, if any, is recognized in income as incurred. For our economic hedges and for derivative instruments entered into by us for trading purposes, the derivative instrument is recorded at fair value and changes in the fair value of the derivative instrument are recognized currently in income.
The following tables include only open positions at the end of the indicated reporting period, and therefore do not include amounts related to closed cash flow hedges for which the gain or loss remains in “accumulated other comprehensive income” pending consummation of the forecasted transactions.
Contract volumes are presented in thousands of barrels (for crude oil and refined products) or in billions of British thermal units (for natural gas). The weighted-average pay and receive prices represent amounts per barrel (for crude oil and refined products) or amounts per million British thermal units (for natural gas). Volumes shown for swaps represent notional volumes, which are used to calculate amounts due under the agreements. For futures, the contract value represents the contract price of either the long or short position multiplied by the derivative contract volume, while the market value amount represents the period-end market price of the commodity being hedged multiplied by the derivative contract volume. The pre-tax fair value for futures, swaps, and options represents the fair value of the derivative contract. The pre-tax fair value for swaps represents the excess of the receive price over the pay price multiplied by the notional contract volumes. For futures and options, the pre-tax fair value represents (i) the excess of the market value amount over the contract amount for long positions, or (ii) the excess of the contract amount over the market value amount for short positions. Additionally, for futures and options, the weighted-average pay price represents the contract price for long positions and the weighted-average receive price represents the contract price for short positions. The weighted-average pay price and weighted-average receive price for options represents their strike price.

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    December 31, 2007  
            Wtd Avg     Wtd Avg                     Pre-tax  
    Contract     Pay     Receive     Contract     Market     Fair  
    Volumes     Price     Price     Value     Value     Value  
Fair Value Hedges:
                                               
Futures - long:
                                               
2008 (crude oil and refined products)
    68,873     $ 97.69       N/A     $ 6,728     $ 6,961     $ 233  
Futures - short:
                                               
2008 (crude oil and refined products)
    79,188       N/A     $ 96.89       7,673       8,005       (332 )
 
                                               
Cash Flow Hedges:
                                               
Swaps - long:
                                               
2008 (crude oil and refined products)
    18,175       81.44       98.50       N/A       310       310  
Swaps - short:
                                               
2008 (crude oil and refined products)
    18,175       102.55       86.25       N/A       (296 )     (296 )
Futures - long:
                                               
2008 (crude oil and refined products)
    80,960       103.50       N/A       8,379       8,596       217  
Futures - short:
                                               
2008 (crude oil and refined products)
    73,735       N/A       103.62       7,640       7,826       (186 )
 
                                               
Economic Hedges:
                                               
Swaps - long:
                                               
2008 (crude oil and refined products)
    12,012       33.16       39.48       N/A       76       76  
Swaps - short:
                                               
2008 (crude oil and refined products)
    7,397       63.91       54.25       N/A       (71 )     (71 )
Futures - long:
                                               
2008 (crude oil and refined products)
    77,902       96.20       N/A       7,494       7,802       308  
Futures - short:
                                               
2008 (crude oil and refined products)
    76,426       N/A       96.18       7,351       7,663       (312 )
Options - long:
                                               
2008 (crude oil and refined products)
    89       47.72       N/A       -       1       1  
 
                                               
Trading Activities:
                                               
Swaps - long:
                                               
2008 (crude oil and refined products)
    14,677       11.77       12.98       N/A       18       18  
Swaps - short:
                                               
2008 (crude oil and refined products)
    15,952       12.47       11.56       N/A       (15 )     (15 )
Futures - long:
                                               
2008 (crude oil and refined products)
    28,801       98.01       N/A       2,823       2,923       100  
Futures - short:
                                               
2008 (crude oil and refined products)
    28,766       N/A       98.20       2,824       2,920       (96 )
Options - short:
                                               
2008 (crude oil and refined products)
    66       N/A       49.00       1       1       -  
 
                                             
 
Total pre-tax fair value of open positions
                                          $ (45 )
 
                                             

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    December 31, 2006  
            Wtd Avg     Wtd Avg                     Pre-tax  
    Contract     Pay     Receive     Contract     Market     Fair  
    Volumes     Price     Price     Value     Value     Value  
Fair Value Hedges:
                                               
Futures - long:
                                               
2007 (crude oil and refined products)
    15,261     $ 63.66       N/A     $ 972     $ 949     $ (23 )
Futures - short:
                                               
2007 (crude oil and refined products)
    22,091       N/A     $ 64.56       1,426       1,379       47  
 
Cash Flow Hedges:
                                               
Swaps - long:
                                               
2007 (crude oil and refined products)
    39,125       70.14       65.16       N/A       (195 )     (195 )
Swaps - short:
                                               
2007 (crude oil and refined products)
    39,125       69.66       76.30       N/A       260       260  
Futures - long:
                                               
2007 (crude oil and refined products)
    21,087       64.75       N/A       1,365       1,336       (29 )
Futures - short:
                                               
2007 (crude oil and refined products)
    18,356       N/A       64.82       1,190       1,161       29  
 
Economic Hedges:
                                               
Swaps - long:
                                               
2007 (crude oil and refined products)
    13,244       12.02       11.02       N/A       (13 )     (13 )
2007 (natural gas)
    893       0.76       0.78       N/A       -       -  
Swaps - short:
                                               
2007 (crude oil and refined products)
    7,605       26.47       27.66       N/A       9       9  
2007 (natural gas)
    833       0.85       0.89       N/A       -       -  
Futures - long:
                                               
2007 (crude oil and refined products)
    50,442       64.28       N/A       3,242       3,171       (71 )
2007 (natural gas)
    400       7.33       N/A       3       3       -  
Futures - short:
                                               
2007 (crude oil and refined products)
    51,623       N/A       64.15       3,312       3,252       60  
2007 (natural gas)
    400       N/A       8.21       3       3       -  
Options - long:
                                               
2007 (crude oil and refined products)
    31       84.29       N/A       -       -       -  
Options - short:
                                               
2007 (crude oil and refined products)
    1,478       N/A       61.94       -       (6 )     6  
 
Trading Activities:
                                               
Futures - long:
                                               
2007 (crude oil and refined products)
    801       77.29       N/A       62       59       (3 )
Futures - short:
                                               
2007 (crude oil and refined products)
    801       N/A       84.87       68       58       10  
 
                                             
 
Total pre-tax fair value of open positions
                                          $ 87  
 
                                             

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INTEREST RATE RISK
In general, 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-rate and floating-rate debt. In addition, we sometimes utilize interest rate swap agreements to manage a portion of our exposure to changing interest rates by converting certain fixed-rate debt to floating rate. These interest rate swap agreements are generally accounted for as fair value hedges. The gain or loss on the derivative instrument and the gain or loss on the debt that is being hedged are recorded in interest expense. The recorded amounts of the derivative instrument and long-term debt balances are adjusted accordingly. We had no interest rate derivative instruments outstanding as of December 31, 2007 and 2006.
The following table provides information about our long-term debt instruments (dollars in millions), the fair value of which is sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented.
                                                                 
    December 31, 2007
    Expected Maturity Dates        
                        There-       Fair
    2008   2009   2010   2011   2012   after   Total   Value
Long-term Debt:
                                                               
Fixed rate
  $ 356     $ 209     $ 33     $ 418     $ 759     $ 5,086     $ 6,861     $ 7,109  
Average interest rate
    9.4 %     3.6 %     6.8 %     6.4 %     6.9 %     6.7 %     6.8 %        
                                                                 
    December 31, 2006
    Expected Maturity Dates        
                        There-       Fair
    2007   2008   2009   2010   2011   after   Total   Value
Long-term Debt:
                                                               
Fixed rate
  $ 462     $ 6     $ 209     $ 33     $ 418     $ 3,946     $ 5,074     $ 5,361  
Average interest rate
    7.3 %     6.0 %     3.6 %     6.8 %     6.4 %     7.1 %     6.9 %        
FOREIGN CURRENCY RISK
We enter into foreign currency exchange and purchase contracts to manage our exposure to exchange rate fluctuations on transactions related to our Canadian operations. Changes in the fair value of these contracts are recognized currently in income and are intended to offset the income effect of translating the foreign currency denominated transactions that they are intended to hedge.
As of December 31, 2007, we had commitments to purchase $507 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before January 29, 2008, resulting in a 2008 loss of $2 million.

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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, 2007. 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, 2007, our internal control over financial reporting was effective based on those criteria.
Our independent registered public accounting firm has issued an attestation report on the effectiveness 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, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity, cash flows and comprehensive income for each of the years in the three-year period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) (the PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Valero Energy Corporation and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, the Company adopted the provisions of Emerging Issues Task Force Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, and Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment, effective January 1, 2006.
We also have audited, in accordance with the standards of the PCAOB, the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2008, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
San Antonio, Texas
February 27, 2008

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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 Valero Energy Corporation and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2007, 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, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) (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, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Valero Energy Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by COSO.

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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, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity, cash flows and comprehensive income for each of the years in the three-year period ended December 31, 2007, and our report dated February 27, 2008 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
San Antonio, Texas
February 27, 2008

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)
                 
    December 31,  
    2007     2006  
ASSETS
               
Current assets:
               
Cash and temporary cash investments
  $ 2,464     $ 1,590  
Restricted cash
    31       31  
Receivables, net
    7,691       4,384  
Inventories
    4,184       3,979  
Income taxes receivable
    -       32  
Deferred income taxes
    247       143  
Prepaid expenses and other
    175       145  
Assets held for sale
    -       1,527  
 
           
Total current assets
    14,792       11,831  
 
           
 
               
Property, plant and equipment, at cost
    25,787       23,421  
Accumulated depreciation
    (4,078 )     (3,241 )
 
           
Property, plant and equipment, net
    21,709       20,180  
 
           
 
               
Intangible assets, net
    290       303  
Goodwill
    4,061       4,103  
Deferred charges and other assets, net
    1,870       1,336  
 
           
Total assets
  $ 42,722     $ 37,753  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Current portion of long-term debt and capital lease obligations
  $ 392     $ 475  
Accounts payable
    9,596       6,841  
Accrued expenses
    502       507  
Taxes other than income taxes
    632       584  
Income taxes payable
    499       23  
Deferred income taxes
    293       363  
Liabilities related to assets held for sale
    -       67  
 
           
Total current liabilities
    11,914       8,860  
 
           
 
               
Long-term debt and capital lease obligations, less current portion
    6,470       4,619  
 
           
Deferred income taxes
    4,021       4,047  
 
           
Other long-term liabilities
    1,810       1,622  
 
           
Commitments and contingencies
               
 
               
Stockholders’ equity:
               
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 627,501,593 and 627,501,593 shares issued
    6       6  
Additional paid-in capital
    7,111       7,779  
Treasury stock, at cost; 90,841,602 and 23,738,162 common shares
    (6,097 )     (1,396 )
Retained earnings
    16,914       11,951  
Accumulated other comprehensive income
    573       265  
 
           
Total stockholders’ equity
    18,507       18,605  
 
           
Total liabilities and stockholders’ equity
  $ 42,722     $ 37,753  
 
           
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,  
    2007     2006     2005  
 
Operating revenues (1) (2)
  $ 95,327     $ 87,640     $ 80,616  
 
                 
 
                       
Costs and expenses:
                       
Cost of sales (1)
    81,645       73,863       70,438  
Refining operating expenses
    4,016       3,622       2,816  
Retail selling expenses
    750       719       700  
General and administrative expenses
    638       598       558  
Depreciation and amortization expense
    1,360       1,116       836  
 
                 
Total costs and expenses
    88,409       79,918       75,348  
 
                 
 
                       
Operating income
    6,918       7,722       5,268  
Equity in earnings of NuStar Energy L.P.
    -       45       41  
Other income, net
    167       350       53  
Interest and debt expense:
                       
Incurred
    (466 )     (377 )     (334 )
Capitalized
    107       165       66  
Minority interest in net income of NuStar GP Holdings, LLC
    -       (7 )     -  
 
                 
 
                       
Income from continuing operations before income tax expense
    6,726       7,898       5,094  
Income tax expense
    2,161       2,611       1,621  
 
                 
 
                       
Income from continuing operations
    4,565       5,287       3,473  
Income from discontinued operations, net of income tax expense
    669       176       117  
 
                 
 
                       
Net income
    5,234       5,463       3,590  
Preferred stock dividends
    -       2       13  
 
                 
 
                       
Net income applicable to common stock
  $ 5,234     $ 5,461     $ 3,577  
 
                 
Earnings per common share:
                       
Continuing operations
  $ 8.08     $ 8.65     $ 6.30  
Discontinued operations
    1.19       0.29       0.21  
 
                 
Total
  $ 9.27     $ 8.94     $ 6.51  
 
                 
Weighted-average common shares outstanding (in millions)
    565       611       549  
 
Earnings per common share - assuming dilution:
                       
Continuing operations
  $ 7.72     $ 8.36     $ 5.90  
Discontinued operations
    1.16       0.28       0.20  
 
                 
Total
  $ 8.88     $ 8.64     $ 6.10  
 
                 
Weighted-average common shares outstanding - assuming dilution (in millions)
    579       632       588  
 
Dividends per common share
  $ 0.48     $ 0.30     $ 0.19  
 
Supplemental information (billions of dollars):
                       
(1) Includes amounts related to crude oil buy/sell arrangements:
                       
Operating revenues
    N/A       N/A     $ 7.8  
Cost of sales
    N/A       N/A       7.8  
(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, 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       -       -       -  
Stock-based compensation expense
    -       -       51       -       -       -  
Shares issued, net of shares repurchased, in connection with employee stock plans and other
    -       -       (165 )     3       -       -  
Other comprehensive income
    -       -       -       -       -       106  
 
                                   
 
                                               
Balance as of December 31, 2005
    68       6       8,164       (196 )     6,673       335  
Net income
    -       -       -       -       5,463       -  
Dividends on common stock
    -       -       -       -       (183 )     -  
Dividends on and accretion of preferred stock
    1       -       -       -       (2 )     -  
Conversion of preferred stock
    (69 )     -       69       -       -       -  
Credits from subsidiary stock sales, net of tax
    -       -       101       -       -       -  
Stock-based compensation expense
    -       -       81       -       -       -  
Shares repurchased, net of shares issued, in connection with employee stock plans and other
    -       -       (636 )     (1,200 )     -       -  
Other comprehensive income
    -       -       -       -       -       29  
Adjustment to initially apply FASB Statement No. 158, net of tax
    -       -       -       -       -       (99 )
 
                                   
 
                                               
Balance as of December 31, 2006
    -       6       7,779       (1,396 )     11,951       265  
Net income
    -       -       -       -       5,234       -  
Dividends on common stock
    -       -       -       -       (271 )     -  
Stock-based compensation expense
    -       -       89       -       -       -  
Shares repurchased under $6 billion common stock purchase program
    -       -       -       (4,873 )     -       -  
Shares issued, net of shares repurchased, in connection with employee stock plans and other
    -       -       (757 )     172       -       -  
Other comprehensive income
    -       -       -       -       -       308  
 
                                   
Balance as of December 31, 2007
  $ -     $ 6     $ 7,111     $ (6,097 )   $ 16,914     $ 573  
 
                                   
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,  
    2007     2006     2005  
Cash flows from operating activities:
                       
Net income
  $ 5,234     $ 5,463     $ 3,590  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization expense
    1,376       1,155       840  
Gain on sale of Lima Refinery
    (827 )     -       -  
Minority interest in net income of NuStar GP Holdings, LLC
    -       7       -  
Gain on sale of NuStar GP Holdings, LLC
    -       (328 )     -  
Gain on sale of investment in Javelina joint venture
    -       -       (55 )
Noncash interest expense and other income, net
    (10 )     24       31  
Stock-based compensation expense
    100       108       80  
Deferred income tax expense (benefit)
    (131 )     290       255  
Changes in current assets and current liabilities
    (469 )     (144 )     1,082  
Changes in deferred charges and credits and other operating activities, net
    (15 )     (263 )     27  
 
                 
Net cash provided by operating activities
    5,258       6,312       5,850  
 
                 
 
                       
Cash flows from investing activities:
                       
Capital expenditures
    (2,260 )     (3,187 )     (2,133 )
Deferred turnaround and catalyst costs
    (518 )     (569 )     (441 )
Proceeds from sale of Lima Refinery
    2,428       -       -  
Premcor Acquisition, net of cash acquired
    -       -       (2,343 )
Proceeds from sale of NuStar GP Holdings, LLC
    -       880       -  
Proceeds from sale of Denver Refinery
    -       -       45  
Proceeds from sale of investment in Javelina joint venture
    -       -       78  
General partner contribution to NuStar Energy L.P
    -       -       (29 )
Contingent payments in connection with acquisitions
    (75 )     (101 )     (85 )
(Investment) return of investment in Cameron Highway Oil Pipeline Project, net
    (209 )     (26 )     38  
Distributions in excess of equity in earnings of NuStar Energy L.P
    -       8       -  
Proceeds from minor dispositions of property, plant and equipment
    63       64       30  
Minor acquisitions and other investing activities, net
    (11 )     (40 )     (60 )
 
                 
Net cash used in investing activities
    (582 )     (2,971 )     (4,900 )
 
                 
 
                       
Cash flows from financing activities:
                       
Long-term notes:
                       
Borrowings
    2,245       -       -  
Repayments
    (463 )     (249 )     (874 )
Bank credit agreements:
                       
Borrowings
    3,000       830       1,617  
Repayments
    (3,000 )     (830 )     (1,617 )
Termination of interest rate swaps
    -       (54 )     -  
Purchase of treasury stock
    (5,788 )     (2,020 )     (571 )
Issuance of common stock in connection with employee benefit plans
    159       122       182  
Benefit from tax deduction in excess of recognized stock-based compensation cost
    311       206       -  
Common and preferred stock dividends
    (271 )     (184 )     (106 )
Cash distributions to minority interest in NuStar GP Holdings, LLC
    -       (4 )     -  
Other financing activities
    (24 )     (5 )     (13 )
 
                 
Net cash used in financing activities
    (3,831 )     (2,188 )     (1,382 )
 
                 
Effect of foreign exchange rate changes on cash
    29       1       4  
 
                 
Net increase (decrease) in cash and temporary cash investments
    874       1,154       (428 )
Cash and temporary cash investments at beginning of year
    1,590        436       864  
 
                 
Cash and temporary cash investments at end of year
  $ 2,464     $ 1,590     $ 436  
 
                 
See Notes to Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of Dollars)
                         
    Year Ended December 31,  
    2007     2006     2005  
Net income
  $ 5,234     $ 5,463     $ 3,590  
 
                 
 
                       
Other comprehensive income (loss):
                       
Foreign currency translation adjustment
     250       (11 )     54  
 
                 
 
                       
Pension and other postretirement benefits:
                       
Net gain (loss) arising during the year, net of income tax (expense) benefit of $(55), $-, and $-
    80       (1 )     (1 )
Net loss reclassified into income, net of income tax benefit of $4, $-, and $-
    6       -       -  
 
                 
Net gain (loss) on pension and other postretirement benefits
    86       (1 )     (1 )
 
                 
 
                       
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 $6, $(38), and $117
    (11 )     70       (218 )
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $9, $15, and $(146)
    (17 )     (29 )      271  
 
                 
Net gain (loss) on cash flow hedges
    (28 )     41       53  
 
                 
 
                       
Other comprehensive income
     308       29        106  
 
                 
 
                       
Comprehensive income
  $ 5,542     $ 5,492     $ 3,696  
 
                 
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 17 refineries (seven in Texas, two each in California and Louisiana, and one each in Delaware, Oklahoma, New Jersey, Tennessee, Aruba, and Quebec, Canada) with a combined total throughput capacity as of December 31, 2007 of approximately 3.1 million barrels per day. We market our refined products through an extensive bulk and rack marketing network and approximately 5,800 retail and wholesale branded outlets in the United States and eastern Canada under various brand names including 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 significant noncontrolled entities are accounted for using the equity method of accounting.
As discussed in Note 2, the assets and liabilities of the Lima Refinery, as well as inventory sold by our marketing and supply subsidiary associated with this transaction, have been reclassified as held for sale as of December 31, 2006, and the results of operations of the Lima Refinery have been presented as discontinued operations in the consolidated statements of income for all periods presented.
On July 19, 2006, we sold a 40.6% interest in NuStar GP Holdings, LLC (formerly Valero GP Holdings, LLC), which indirectly owned the general partner interest, incentive distribution rights, and a 21.4% limited partner interest in NuStar Energy L.P. (formerly Valero L.P.) On December 22, 2006, we sold our remaining interest in NuStar GP Holdings, LLC. These financial statements consolidate NuStar GP Holdings, LLC through December 21, 2006, with net income attributable to the 40.6% interest held by public unitholders from July 19, 2006 through December 21, 2006 presented as a minority interest in the consolidated statement of income. See Note 9 under “Sale of NuStar GP Holdings, LLC” for a discussion of the sale of NuStar GP Holdings, LLC.
The term UDS Acquisition refers to the merger of Ultramar Diamond Shamrock Corporation (UDS) into Valero effective December 31, 2001.
Use of Estimates
The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires our management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, management reviews its estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cash and Temporary Cash Investments
Our temporary cash investments are highly liquid, low-risk debt instruments that have a maturity of three months or less when acquired. Cash and temporary cash investments exclude cash that is not available to us due to restrictions related to its use. Such amounts are segregated in the consolidated balance sheets in “restricted cash” (see Note 3).
Inventories
Inventories are carried at the lower of cost or market. The cost of refinery feedstocks purchased for processing and refined products are determined under the last-in, first-out (LIFO) method using the dollar-value LIFO method, with any increments valued based on average purchase prices during the year. The cost of feedstocks and products purchased for resale and the cost of materials, supplies, and convenience store merchandise are determined principally under the weighted-average cost method.
Effective January 1, 2006, we adopted the provisions of Financial Accounting Standards Board (FASB) 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. The adoption of Statement No. 151 did not affect our financial position or results of operations.
Property, Plant and Equipment
Additions to property, plant and equipment, including capitalized interest and certain costs allocable to construction and property purchases, are recorded at cost.
The costs of minor property units (or components of property units), net of salvage value, retired or abandoned are charged or credited to accumulated depreciation under the composite method of depreciation. Gains or losses on sales or other dispositions of major units of property are recorded in income and are reported in “depreciation and amortization expense” in the consolidated statements of income.
Depreciation of property, plant and equipment is recorded on a straight-line basis over the estimated useful lives of the related facilities primarily using the composite method of depreciation. Leasehold improvements and assets acquired under capital leases are amortized using the straight-line method over the shorter of the lease term or the estimated useful life of the related asset.
Goodwill and Intangible Assets
Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over 1 to 40 years. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. We use October 1 of each year as our valuation date for annual impairment testing purposes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 entities that we do not control; and
 
    other noncurrent assets such as long-term investments, convenience store dealer incentive programs, pension plan assets, debt issuance costs, and various other costs.
We evaluate our equity method investments for impairment when there is evidence that we may not be able to recover the carrying amount of our investments or the investee is unable to sustain an earnings capacity that justifies the carrying amount. A loss in the value of an investment that is other than a temporary decline is recognized currently in earnings, and is based on the difference between the estimated current fair value of the investment and its carrying amount. We believe that the carrying amounts of our equity method investments as of December 31, 2007 are recoverable.
Effective January 1, 2006, we adopted Emerging Issues Task Force (EITF) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (EITF No. 04-5), which requires the general partner in a limited partnership to determine whether the limited partnership is controlled by, and therefore should be consolidated by, the general partner. The adoption of EITF No. 04-5 had no impact on the accounting for our investment in NuStar Energy L.P.
Impairment and Disposal of Long-Lived Assets
Long-lived assets (excluding goodwill, intangible assets with indefinite lives, equity method investments, and deferred tax assets) are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its fair value, with fair value determined based on discounted estimated net cash flows. We believe that the carrying amounts of our long-lived assets as of December 31, 2007 are recoverable.
Taxes Other than Income Taxes
“Taxes other than income taxes” includes primarily liabilities for ad valorem, excise, sales and use, and payroll taxes.
Income Taxes
Income taxes are accounted for under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred amounts are measured using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes,” by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. If a tax position is more likely than not to be sustained upon examination, then an enterprise would be required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. As discussed in Note 18, the adoption of FIN 48 effective January 1, 2007 did not materially affect our financial position or results of operations.
We have elected to classify any interest expense and penalties related to the underpayment of income taxes in “income tax expense” in our consolidated statements of income.
Asset Retirement Obligations
We record a liability, which is referred to as an asset retirement obligation, at fair value for the estimated cost to retire a tangible long-lived asset at the time we incur that liability, which is generally when the asset is purchased, constructed, or leased. We record the liability when we have a legal obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the liability’s fair value.
We have asset retirement obligations with respect to certain of our refinery assets due to various legal obligations to clean and/or dispose of various component parts of each refinery at the time they are retired. However, these component parts can be used for extended and indeterminate periods of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain our refinery assets and continue making improvements to those assets based on technological advances. As a result, we believe that our refineries have indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we would retire refinery assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of any component part of a refinery, we estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using established present value techniques.
We also have asset retirement obligations for the removal of underground storage tanks (USTs) for refined products at owned and leased retail locations. There is no legal obligation to remove USTs while they remain in service. However, environmental laws require that unused USTs be removed within certain periods of time after the USTs no longer remain in service, usually one to two years depending on the jurisdiction in which the USTs are located. We have estimated that USTs at our owned retail locations will not remain in service after 25 years of use and that we will have an obligation to remove those USTs at that time. For our leased retail locations, our lease agreements generally require that we remove certain improvements, primarily USTs and signage, upon termination of the lease. While our lease agreements typically contain options for multiple renewal periods, we have not assumed that such leases will be renewed for purposes of estimating our obligation to remove USTs and signage.
Effective December 31, 2005, we adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations,” represents a legal

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
obligation to perform an asset retirement activity for which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset retirement obligation should be recognized if its fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of its settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under FASB Statement No. 143. The adoption of FIN 47 did not affect our financial position or results of operations.
Foreign Currency Translation
The functional currencies of our Canadian and Aruban operations are the Canadian dollar and the Aruban florin, respectively. The translation of the Canadian operations 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.” The value of the Aruban florin is fixed to the U.S. dollar at 1.79 Aruban florins to one U.S. dollar. The translation of the Aruban operations into U.S. dollars is computed based on this fixed exchange rate for both balance sheet and income statement accounts. As a result, there are no adjustments resulting from this translation 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.
In June 2006, the FASB ratified its consensus on EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF No. 06-3). The scope of EITF No. 06-3 includes any tax assessed by a governmental authority that is imposed concurrent with or subsequent to a revenue-producing transaction between a seller and a customer. For taxes within the scope of this issue that are significant in amount, the consensus requires the following disclosures: (i) the accounting policy elected for these taxes and (ii) the amount of the taxes reflected gross in the income statement on an interim and annual basis for all periods presented. The disclosure of those taxes can be provided on an aggregate basis. We adopted the consensus effective January 1, 2007. We present excise taxes on sales by our U.S. retail system on a gross basis with supplemental information regarding the amount of such taxes included in revenues provided in a footnote on the face of the income statement. All other excise taxes are presented on a net basis in the income statement.
Through December 31, 2005, our operating revenues included sales related to certain buy/sell arrangements. In September 2005, the FASB ratified its consensus on EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF No. 04-13), which requires that inventory purchase and sale transactions with the same counterparty that are entered into in contemplation of one another should be combined. The guidance in EITF No. 04-13 was effective for transactions completed in reporting periods beginning after March 15, 2006, with early application permitted. We adopted EITF No. 04-13 on January 1, 2006.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
One issue addressed by EITF No. 04-13 details factors to consider in evaluating whether certain individual transactions to purchase and sell inventory are made in contemplation of one another and should therefore be viewed as one transaction when applying the principles of AICPA Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions.” When applying these factors, certain of our buy/sell arrangements are deemed to be made in contemplation of one another. Accordingly, commencing January 1, 2006, revenues and cost of sales ceased to be recognized in connection with these arrangements. This adoption resulted in a reduction in our operating revenues in our consolidated statement of income and a corresponding reduction in cost of sales with no material impact on operating income, net income or net income applicable to common stock. If we had applied EITF No. 04-13 for the year ended December 31, 2005, operating revenues and cost of sales would have been reduced by the amounts reflected in the supplemental information on the face of the consolidated statement of income.
We also enter into refined product exchange transactions to fulfill sales contracts with our customers by accessing refined products in markets where we do not operate our own refinery. These refined product exchanges are accounted for as exchanges of non-monetary assets, and no revenues are recorded on these transactions.
Product Shipping and Handling Costs
Costs incurred for shipping and handling of products are included in “cost of sales” in the consolidated statements of income.
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 of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Environmental liabilities are based on best estimates of probable undiscounted future costs over a 20-year time period using currently available technology and applying current regulations, as well as our own internal environmental policies. Amounts recorded for environmental liabilities have not been reduced by possible recoveries from third parties.
Derivative Instruments
All derivative instruments are recorded in the balance sheet as either assets or liabilities measured at their fair value. When we enter into a derivative instrument, it is designated as a fair value hedge, a cash flow hedge, an economic hedge, or a trading instrument. For our economic hedging relationships (hedges not designated as fair value or cash flow hedges) and for derivative instruments entered into by us for trading purposes, the derivative instrument is recorded at fair value and changes in the fair value of the derivative instrument are recognized currently in income. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting loss or gain on the hedged item attributable to the hedged risk, are recognized currently in income in the same period. The effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is initially reported as a component of “other comprehensive income” and is then recorded in income in the period or periods during which the hedged forecasted transaction affects income. The ineffective portion of the gain or loss on the cash flow derivative instrument, if any, is recognized in income as incurred. Income effects of commodity derivative instruments are recorded in “cost of sales” while income effects of interest rate swaps (if applicable) are recorded in “interest and debt expense.”

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Financial Instruments
Our financial instruments include cash and temporary cash investments, restricted cash, receivables, payables, debt, capital lease obligations, 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 values of our debt, commodity derivative contracts, and foreign currency derivative contracts were estimated primarily based on year-end quoted market prices.
In February 2006, the FASB issued Statement No. 155, “Accounting for Certain Hybrid Financial Instruments,” which amends Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This statement improves the financial reporting of certain hybrid financial instruments and simplifies the accounting for these instruments. In particular, Statement No. 155 (i) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, (ii) clarifies which interest-only and principal-only strips are not subject to the requirements of Statement No. 133, (iii) establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, (iv) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives, and (v) amends Statement No. 140 to eliminate the prohibition on a qualifying special-purpose entity holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. The adoption of Statement No. 155 effective January 1, 2007 did not affect our financial position or results of operations.
In March 2006, the FASB issued Statement No. 156, “Accounting for Servicing of Financial Assets,” which amends Statement No. 140. Statement No. 156 requires the initial recognition at fair value of a servicing asset or servicing liability when an obligation to service a financial asset is undertaken by entering into a servicing contract. The adoption of Statement No. 156 effective January 1, 2007 did not affect our financial position or results of operations.
Earnings per Common Share
Earnings per common share is computed by dividing net income applicable to common stock by the weighted-average number of common shares outstanding for the year. Earnings per common share assuming dilution reflects the potential dilution of our outstanding stock options and nonvested shares granted to employees in connection with our stock compensation plans, as well as the 2% mandatory convertible preferred stock prior to its conversion as discussed in Note 14. In addition, see Notes 14 and 15 for a discussion of an accelerated share repurchase program during 2007 and its effect on earnings per common share assuming dilution for the year ended December 31, 2007.
Comprehensive Income
Comprehensive income consists of net income and other gains and losses affecting stockholders’ equity that, under GAAP, are excluded from net income, including foreign currency translation adjustments, gains and losses related to certain derivative contracts, and gains or losses, prior service costs or credits, and transition assets or obligations associated with pension or other postretirement benefits that have not been recognized as components of net periodic benefit cost.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Defined Benefit Pension and Other Postretirement Plans
In September 2006, the FASB issued Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which amends Statement No. 87, “Employers’ Accounting for Pensions,” Statement No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” Statement No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” and other related accounting literature.
Statement No. 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or a liability in the statement of financial position and to recognize changes in that funded status through comprehensive income in the year the changes occur. This statement also requires an employer to measure the funded status of a plan as of the date of the employer’s year-end statement of financial position. We adopted the funded status recognition and related disclosure requirements of Statement No. 158 as of December 31, 2006, and measured the funded status of our defined benefit plans as of that date. The adoption of Statement No. 158 did not materially affect our financial position or results of operations.
Stock-Based Compensation
Through December 31, 2005, we accounted for our employee stock compensation plans using the intrinsic value method of accounting set forth in APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as permitted by FASB Statement No. 123, “Accounting for Stock-Based Compensation.”

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 year ended December 31, 2005 would have been reduced to the pro forma amounts indicated in the following table (in millions, except per share amounts):
         
Net income applicable to common stock, as reported
  $ 3,577  
Deduct: Compensation expense on stock options determined under fair value method for all awards, net of related tax effects
    (19 )
 
     
Pro forma net income applicable to common stock
  $ 3,558  
 
     
 
       
Earnings per common share:
       
As reported
  $ 6.51  
Pro forma
  $ 6.48  
 
       
Net income, as reported
  $ 3,590  
Deduct: Compensation expense on stock options determined under fair value method for all awards, net of related tax effects
    (19 )
 
     
Pro forma net income
  $ 3,571  
 
     
 
       
Earnings per common share - assuming dilution:
       
As reported
  $ 6.10  
Pro forma
  $ 6.07  
Stock-based compensation expense recognized for the year ended December 31, 2005 was $52 million, net of tax benefits of $28 million.
Effective January 1, 2006, we adopted Statement No. 123 (revised 2004), “Share-Based Payment” (Statement No. 123R), which requires the expensing of the fair value of stock options. The specific impact of our adoption of Statement No. 123R will depend on levels of share-based incentive awards granted in the future. Had we adopted Statement No. 123R in prior periods, the impact of that standard would have approximated the impact of Statement No. 123 as described in the disclosure of the pro forma financial information above.
We adopted the fair value recognition provisions of Statement No. 123R using the modified prospective application. Accordingly, we are recognizing compensation expense for all newly granted stock options and stock options modified, repurchased, or cancelled on or after January 1, 2006. In addition, compensation cost for the unvested portion of stock options and other awards that were outstanding as of January 1, 2006 is being recognized over the remaining vesting period based on the fair value at date of grant and the attribution approach utilized in determining the pro forma information reflected above. Subsequent to the adoption of Statement No. 123R, our total stock-based compensation expense recognized for the years ended December 31,

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2007 and 2006 was $65 million, net of tax benefits of $35 million, and $70 million, net of tax benefits of $38 million, 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 previously accounted for such awards by recognizing compensation cost, if any, under APB Opinion No. 25 and pro forma compensation cost under Statement No. 123 over the nominal vesting period. Upon the adoption of Statement No. 123R, compensation expense for stock options granted on or after January 1, 2006 is being recognized on a straight-line basis, and we changed our method of recognizing compensation cost for new grants that have retirement-eligibility provisions from the nominal vesting period approach to the non-substantive vesting period approach. Under the non-substantive vesting period approach, compensation cost is recognized immediately for awards granted to retirement-eligible employees or over the period from the grant date to the date retirement eligibility is achieved if that date is expected to occur during the nominal vesting period. If the non-substantive vesting period approach had been used by us for awards granted prior to January 1, 2006, pro forma net income applicable to common stock and pro forma net income amounts for the year ended December 31, 2005 would have decreased by $8 million, and net income applicable to common stock and net income for each of the years ended December 31, 2006 and 2007 would have increased by $4 million.
Statement No. 123R also requires the benefits of tax deductions in excess of recognized stock-based compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as previously required. This requirement reduces cash flows from operating activities and increases cash flows from financing activities beginning in 2006. While we cannot estimate the specific magnitude of this change on future cash flows because it depends on, among other things, when employees exercise stock options, the cash flows recognized in financing activities for such excess tax deductions were $311 million and $206 million for the years ended December 31, 2007 and 2006, respectively.
Sales of Subsidiary Stock
Securities and Exchange Commission (SEC) Staff Accounting Bulletin No. 51, “Accounting for Sales of Stock by a Subsidiary” (SAB 51), provides guidance on accounting for the effect of issuances of a subsidiary’s stock on the parent’s investment in that subsidiary. SAB 51 allows registrants to elect an accounting policy of recording such increases or decreases in a parent’s investment (SAB 51 credits or charges, respectively) either in income or in stockholders’ equity. In accordance with the election provided in SAB 51, we adopted a policy of recording such SAB 51 credits or charges directly to “additional paid-in capital” in stockholders’ equity. As further discussed in Note 9, we recognized in 2006 certain SAB 51 credits related to our investment in NuStar Energy L.P. under our adopted policy.
Exchanges of Nonmonetary Assets
In December 2004, the FASB issued Statement No. 153, “Exchanges of Nonmonetary Assets,” which addresses the measurement of exchanges of nonmonetary assets. Statement No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets, which was previously provided by APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. Statement No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement No. 153 was effective for nonmonetary asset exchanges

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occurring in fiscal periods beginning after June 15, 2005. The adoption of Statement No. 153 effective January 1, 2006 did not affect our financial position or results of operations.
New Accounting Pronouncements
FASB Statement No. 157
In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements.” Statement No. 157 defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measures. Statement No. 157 is effective for fiscal years beginning after November 15, 2007, with early adoption encouraged. The provisions of Statement No. 157 are to be applied on a prospective basis, with the exception of certain financial instruments for which retrospective application is required. FASB Staff Position No. FAS 157-2 (FSP 157-2), issued in February 2008, delayed the effective date of Statement No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. We have adopted Statement No. 157 effective January 1, 2008, with the exceptions allowed under FSP 157-2, the adoption of which has not affected our financial position or results of operations.
FASB Statement No. 159
In February 2007, the FASB issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” Statement No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Statement No. 159 is effective for fiscal years beginning after November 15, 2007, with early adoption permitted provided the entity also elects to apply the provisions of Statement No. 157. The adoption of Statement No. 159 effective January 1, 2008 has not affected our financial position or results of operations.
FASB Statement No. 141 (revised 2007)
In December 2007, the FASB issued Statement No. 141 (revised 2007), “Business Combinations” (Statement No. 141R). This statement improves the financial reporting of business combinations and clarifies the accounting for these transactions. Statement No. 141R (i) requires the recognition and measurement of assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at their fair values at the acquisition date, (ii) requires acquisition costs and any related restructuring costs to be recognized separately from the acquisition, (iii) requires step acquisitions to be recognized at the full amounts of the fair values of the identifiable assets and liabilities, as well as any noncontrolling interest in the acquiree, (iv) changes the requirements for recognizing assets acquired and liabilities assumed arising from contingencies, (v) defines a bargain purchase as a business combination in which the total acquisition-date fair value of the identifiable net assets exceeds the fair value of the consideration transferred plus any noncontrolling interest in the acquiree, (vi) requires the recognition of any bargain purchase as a gain in the earnings of the acquirer, and (vii) requires the recognition of changes in deferred tax benefits that are recognizable because of a business combination. The provisions of Statement No. 141R are to be applied prospectively to business combinations with acquisition dates on or after the beginning of an entity’s fiscal year that begins on or after December 15, 2008, with early adoption prohibited. Due to its application to future acquisitions, the adoption of Statement No. 141R effective January 1, 2009 will not have any immediate effect on our financial position or results of operations.

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FASB Statement No. 160
Also in December 2007, the FASB issued Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51.” Statement No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. This statement provides guidance for the accounting and reporting of noncontrolling interests, changes in controlling interests, and the deconsolidation of subsidiaries. In addition, Statement No. 160 amends FASB Statement No. 128, “Earnings per Share,” to specify the computation, presentation, and disclosure requirements for earnings per share if an entity has one or more noncontrolling interests. The adoption of Statement No. 160 effective January 1, 2009 is not expected to materially affect our financial position or results of operations.
Reclassifications
Certain amounts previously reported in our annual report on Form 10-K for the year ended December 31, 2006 have been reclassified to conform to the 2007 presentation. Our consolidated balance sheet as of December 31, 2006 and our consolidated statements of income for the years ended December 31, 2006 and 2005 have been reclassified to present the operations of the Lima Refinery as discontinued operations as discussed above. In addition, operating revenues, cost of sales, and retail selling expenses reported in our 2006 and 2005 consolidated statements of income have been reclassified for certain credit card transactions. Commencing January 1, 2007, fees received from our distributors and dealers associated with certain credit card transactions processed on behalf of those distributors and dealers are being netted against third-party processing costs incurred on such transactions to better reflect the nature of the credit card transactions. The credit card reclassifications increased (decreased) amounts previously reported for 2006 and 2005 as follows (in millions):
                 
    Year Ended December 31,
    2006   2005
Operating revenues
  (74 )   (52 )
Cost of sales
    10       6  
Retail selling expenses
    (84 )     (58 )
2. ACQUISITIONS AND DISPOSITIONS
Sale of Lima Refinery
On May 2, 2007, we entered into an agreement to sell our refinery in Lima, Ohio to Husky Refining Company (Husky), a wholly owned subsidiary of Husky Energy Inc. In addition, our marketing and supply subsidiary separately agreed to sell certain inventory amounts to Husky as part of this transaction. As a result, the assets and liabilities related to these transactions are presented as “assets held for sale” and “liabilities related to assets held for sale,” respectively, in the consolidated balance sheet as of December 31, 2006. In addition, the consolidated statements of income reflect the operations related to the Lima Refinery for the periods prior to the effective date of the sale in “income from discontinued operations, net of income tax expense.”
We sold our Lima Refinery to Husky effective July 1, 2007. Proceeds from the sale were approximately $2.4 billion, including approximately $550 million from the sale of working capital to Husky primarily related to the sale of inventory by our marketing and supply subsidiary. The sale resulted in a pre-tax gain of $827 million, or $426 million after tax, which is included in “income from discontinued operations, net of income tax expense” in the consolidated statement of income for the year ended December 31, 2007. In connection with the sale, we entered into a transition services agreement with Husky under which we agreed to

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provide certain accounting and administrative services to Husky, with the services terminating by July 31, 2008. A significant portion of these services has been transitioned to Husky as of February 27, 2008.
Financial information related to the assets and liabilities sold is summarized as follows (in millions). The statement of income information presented below for 2007 does not include the gain on the sale of the Lima Refinery.
                 
    July 1,     December 31,  
    2007     2006  
Current assets (primarily inventory)
  $ 570     $ 456  
Property, plant and equipment, net
    929       918  
Goodwill
    107       108  
Deferred charges and other assets, net
    46       45  
 
           
Assets held for sale
  $ 1,652     $ 1,527  
 
           
 
               
Current liabilities, including current portion of capital lease obligation
  $ 15     $ 29  
Capital lease obligation, excluding current portion
    38       38  
 
           
Liabilities related to assets held for sale
  $ 53     $ 67  
 
           
                         
    Year Ended December 31,
    2007   2006   2005
Operating revenues
  2,231     4,119     1,494  
Income before income tax expense
    391       291       193  
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.
During 2006, an independent appraisal of the assets acquired in the Premcor Acquisition and certain other evaluations related to the Premcor Acquisition purchase price allocation were completed. The purchase price of the Premcor Acquisition was allocated based on the fair values of the assets acquired and the liabilities assumed at the date of acquisition resulting from this final appraisal and other evaluations. The purchase price and the final purchase price allocation were as follows (in millions):
         
Cash paid
  $ 3,377  
Transaction costs
    27  
Less unrestricted cash acquired
    (1,061 )
 
     
Premcor Acquisition, net of cash acquired
    2,343  
Common stock and stock options issued
    3,773  
 
     
Total purchase price, excluding unrestricted cash acquired
  $ 6,116  
 
     

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Current assets, net of unrestricted cash acquired
  $ 3,551  
Property, plant and equipment
    6,771  
Intangible assets
    5  
Goodwill
    1,882  
Deferred charges and other assets
    30  
Current liabilities, less current portion of long-term debt and capital lease obligations
    (1,746 )
Long-term debt assumed, including current portion
    (1,912 )
Capital lease obligation, including current portion
    (14 )
Deferred income taxes
    (2,027 )
Other long-term liabilities
    (424 )
 
     
Purchase price, excluding unrestricted cash acquired
  $ 6,116  
 
     
Unaudited Pro Forma Financial Information
The consolidated statements of income include the results of operations of the Premcor Acquisition commencing on September 1, 2005. The unaudited pro forma financial information for the year ended December 31, 2005 included in the table below (in millions, except per share amounts) assumes that the Premcor Acquisition occurred on January 1, 2005 and reflects the results of operations of the Lima Refinery as discontinued operations. 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.
         
Operating revenues
  91,177  
Operating income
    5,979  
Net income
    4,127  
Net income applicable to common stock
    4,114  
Earnings per common share
    6.80  
Earnings per common share - assuming dilution
    6.36  
Sale of Denver Refinery
On May 31, 2005, we sold our Denver Refinery and related assets and liabilities to Suncor Energy (U.S.A.) Inc. for $30 million plus $15 million for working capital, including feedstock and refined product inventories. In connection with this sale, we recognized a pre-tax gain of $3 million, net of a reduction of $4 million for associated goodwill.
Sale of Equity Interest in Javelina Joint Venture
On November 1, 2005, we sold our 20% equity interests in Javelina Company and Javelina Pipeline Company to MarkWest Energy Partners, L.P. for $78 million, recognizing a gain of $55 million. Javelina Company processes refinery off-gas at a plant in Corpus Christi, Texas.
3. RESTRICTED CASH
Restricted cash as of December 31, 2007 and 2006 included $23 million and $22 million, respectively, of cash held in trust related to certain 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, 2007 and

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2006 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,  
    2007     2006  
Accounts receivable
  $ 7,702     $ 4,385  
Notes receivable and other
    32       32  
 
           
 
    7,734       4,417  
Allowance for doubtful accounts
    (43 )     (33 )
 
           
Receivables, net
  $ 7,691     $ 4,384  
 
           
The changes in the allowance for doubtful accounts consisted of the following (in millions):
                         
    Year Ended December 31,  
    2007     2006     2005  
Balance as of beginning of year
  $ 33     $ 31     $ 27  
Increase in allowance charged to expense
    34       16       15  
Accounts charged against the allowance, net of recoveries
    (25 )     (14 )     (12 )
Foreign currency translation
    1       -       1  
 
                 
Balance as of end of year
  $ 43     $ 33     $ 31  
 
                 
We have an accounts receivable sales facility with a group of third-party financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables, which matures in August 2008. Under this program, one of our wholly owned subsidiaries sells an undivided percentage ownership interest in the eligible receivables, without recourse, to third-party financial institutions. We remain responsible for servicing the transferred receivables and pay certain fees related to our sale of receivables under the program. Under the facility, we retain the residual interest in the designated pool of receivables. This retained interest, which is included in “receivables, net” in the consolidated balance sheets, is recorded at fair value. Due to (i) a short average collection cycle for such receivables, (ii) our collection experience history, and (iii) the composition of the designated pool of trade accounts receivable that are part of this program, the fair value of our retained interest approximates the total amount of the designated pool of accounts receivable reduced by the amount of accounts receivable sold to the third-party financial institutions under the program.
The costs we incurred related to this facility, which were included in “other income, net” in the consolidated statements of income, were $40 million, $55 million, and $30 million for the years ended December 31, 2007, 2006, and 2005, respectively. Proceeds from collections under this facility of $19.3 billion, $31.2 billion, and $24.1 billion for the years ended December 31, 2007, 2006, and 2005, 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 2007, 2006, or 2005.

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As of December 31, 2007 and 2006, $4.0 billion and $2.6 billion, respectively, of our accounts receivable composed the designated pool of accounts receivable included in the program. During 2007, we reduced the amount of eligible receivables sold to the third-party financial institutions by $900 million. As a result, as of December 31, 2007 and 2006, the amount of eligible receivables sold to the third-party financial institutions was $100 million and $1 billion, respectively.
5. INVENTORIES
Inventories consisted of the following (in millions):
                 
    December 31,  
    2007     2006  
Refinery feedstocks
  $ 1,739     $ 1,680  
Refined products and blendstocks
    2,188       2,056  
Convenience store merchandise
    85       85  
Materials and supplies
    172       158  
 
           
Inventories
  $ 4,184     $ 3,979  
 
           
Refinery feedstock and refined product and blendstock inventory volumes totaled 106 million barrels and 107 million barrels as of December 31, 2007 and 2006, respectively. There were no substantial liquidations of LIFO inventory layers for the years ended December 31, 2007, 2006, and 2005.
As of December 31, 2007 and 2006, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $6.2 billion and $2.9 billion, respectively.
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     2007     2006  
Land
          $ 577     $ 551  
Crude oil processing facilities
  10 - 33 years     20,662       18,105  
Butane processing facilities
  30 years     246       246  
Pipeline and terminal facilities
  13 - 42 years     511       378  
Retail facilities
  2 - 22 years     735       648  
Buildings
  13 - 47 years     782       698  
Other
  1 - 44 years     1,019       930  
Construction in progress
            1,255       1,865  
 
                   
Property, plant and equipment, at cost
            25,787       23,421  
Accumulated depreciation
            (4,078 )     (3,241 )
 
                   
Property, plant and equipment, net
          $ 21,709     $ 20,180  
 
                   

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As of December 31, 2007 and 2006, we had crude oil processing facilities, pipeline and terminal facilities, and certain buildings and other equipment under capital leases totaling $54 million and $52 million, respectively. Accumulated amortization on assets under capital leases was $10 million and $6 million, respectively, as of December 31, 2007 and 2006.
Depreciation expense for the years ended December 31, 2007, 2006, and 2005 was $916 million, $776 million, and $590 million, respectively.
7. INTANGIBLE ASSETS
Intangible assets consisted of the following (in millions):
                                 
    December 31, 2007     December 31, 2006  
    Gross     Accumulated     Gross     Accumulated  
    Cost     Amortization     Cost     Amortization  
Intangible assets subject to amortization:
                               
Customer lists
  $ 116     $ (45 )   $ 99     $ (32 )
Canadian retail operations
    156       (23 )     133       (17 )
U.S. retail store operations
    94       (66 )     95       (56 )
Air emission credits
    62       (23 )     62       (18 )
Royalties and licenses
    25       (11 )     25       (10 )
Gasoline and diesel sulfur credits
    27       (23 )     22       (3 )
Other
    4       (3 )     4       (1 )
 
                       
Intangible assets subject to amortization
  $ 484     $ (194 )   $ 440     $ (137 )
 
                       
All of our intangible assets are subject to amortization. Amortization expense for intangible assets was $48 million, $35 million, and $29 million for the years ended December 31, 2007, 2006, and 2005, respectively. The estimated aggregate amortization expense for the years ending December 31, 2008 through December 31, 2012 is as follows (in millions):
         
    Amortization
    Expense
2008
  34  
2009
    25  
2010
    22  
2011
    16  
2012
    16  
During the year ended December 31, 2007, gross cost and accumulated amortization increased by $40 million and $9 million, respectively, due to fluctuations in the Canadian dollar exchange rate. During the year ended December 31, 2006, certain intangible assets were retired which resulted in a reduction of $23 million in both gross cost and accumulated amortization.

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8. GOODWILL
The changes in the carrying amount of goodwill were as follows (in millions):
                 
    Year Ended December 31,  
    2007     2006  
Balance as of beginning of year
  $ 4,103     $ 4,837  
Final Premcor Acquisition purchase price allocation and adjustments
    -       (646 )
Acquisition earn-out payments not previously accrued (see Note 22)
    -       26  
Settlements and adjustments related to acquisition tax contingencies, stock option exercises, and other
    (42 )     (114 )
 
           
Balance as of end of year
  $ 4,061     $ 4,103  
 
           
Settlements and adjustments related to acquisition tax contingencies, stock option exercises, and other reflected in the table above relate primarily to settlements of various income tax contingencies assumed in the UDS and Premcor Acquisitions and exercises of stock options assumed in those acquisitions, the effects of which were recorded as purchase price adjustments, and adjustments to the amount of goodwill attributable to our investment in NuStar Energy 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, 2007 and 2006, confirming that no impairment of goodwill had occurred in any of our reporting units as of those dates.
9. INVESTMENT IN AND TRANSACTIONS WITH NUSTAR ENERGY L.P.
NuStar Energy L.P. is a limited partnership that owns and operates crude oil and refined product pipeline, terminalling, and storage tank assets. As discussed in Note 1 under “Basis of Presentation and Principles of Consolidation,” one of our previously wholly owned subsidiaries, NuStar GP Holdings, LLC, served as the general partner of and held our limited partner interest in NuStar Energy L.P. On July 1, 2005, NuStar Energy 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 NuStar Energy L.P. common units in exchange for Kaneb Partners’ units. In addition, we contributed $29 million to NuStar Energy L.P. to maintain our 2% general partner interest in NuStar Energy L.P. As a result of these transactions, our combined ownership interest in NuStar Energy L.P. was reduced from 45.7% to 23.4%. Our ownership interest in NuStar Energy L.P. remained at 23.4% as of June 30, 2006 (the end of the quarter prior to the offerings discussed below under the heading “Sale of NuStar GP Holdings, LLC”), which was composed of a 2% general partner interest, incentive distribution rights, and a 21.4% limited partner interest. The limited partner interest was represented by 10,222,630 common units of NuStar Energy L.P., of which 9,599,322 were previously subordinated units that converted to common units on May 8, 2006 upon the termination of the subordination period in accordance with the terms of NuStar Energy L.P.’s partnership agreement.

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Through the date of termination of the subordination period, NuStar Energy L.P. had issued common units to the public on three separate occasions, which had diluted our ownership percentage. These three issuances resulted in increases, or SAB 51 credits (see Note 1 under “Sales of Subsidiary Stock”), in our proportionate share of NuStar Energy L.P.’s capital because, in each case, the issuance price per unit exceeded our carrying amount per unit at the time of issuance. We had not recognized any SAB 51 credits in our consolidated financial statements through March 31, 2006 and were not permitted to do so until the subordinated units converted to common units. In conjunction with the conversion of the subordinated units held by us to common units in the second quarter of 2006, we recognized the entire balance of $158 million in SAB 51 credits as an increase in our investment in NuStar Energy L.P. and $101 million after tax as an increase to “additional paid-in capital” in our consolidated balance sheet.
Sale of NuStar GP Holdings, LLC
On July 19, 2006, NuStar GP Holdings, LLC consummated an initial public offering (IPO) of 17,250,000 of its units representing limited liability company interests to the public at $22.00 per unit, before an underwriters’ discount of $1.265 per unit. On December 22, 2006, NuStar GP Holdings, LLC completed a secondary public offering of 20,550,000 units representing limited liability company interests at a price of $21.62 per unit, before an underwriters’ discount of $0.8648 per unit. In addition, NuStar GP Holdings, LLC sold 4,700,000 unregistered units to its chairman of the board of directors (who was at that time also chairman of Valero’s board of directors) at $21.62 per unit. All such units were sold by our subsidiaries that held various ownership interests in NuStar GP Holdings, LLC. As a result, NuStar GP Holdings, LLC did not receive any proceeds from these offerings, and our indirect ownership interest in NuStar GP Holdings, LLC was reduced to zero.
Proceeds to our selling subsidiaries from the IPO totaled approximately $355 million, net of the underwriters’ discount and other offering expenses, which resulted in a pre-tax gain to us of $132 million on the sale of the units. Proceeds to our selling subsidiaries from the secondary offering and private sale of units totaled approximately $525 million, net of the underwriters’ discount and other offering expenses, which resulted in an additional pre-tax gain to us of $196 million. The total pre-tax gain of $328 million is included in “other income, net” in the consolidated statement of income for the year ended December 31, 2006. The funds received from these offerings were used for general corporate purposes.
Summary Financial Information
Financial information reported by NuStar Energy L.P. is summarized below (in millions):
                 
    Year Ended December 31,  
    2006     2005  
Revenues
  $ 1,136     $ 660  
Operating income
    211       154  
Net income
    150       111  
Related-Party Transactions
Under various throughput, handling, terminalling, and service agreements, we use NuStar Energy L.P.’s pipelines to transport crude oil shipped to and refined products shipped from certain of our refineries and use NuStar Energy L.P.’s refined product terminals for certain terminalling services. In addition, through 2006, we provided personnel to NuStar Energy L.P. to perform operating and maintenance services with respect to certain assets for which we received reimbursement from NuStar Energy L.P. We recognized in “cost of sales” both our costs related to the throughput, handling, terminalling, and service agreements with NuStar

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Energy L.P. and the receipt from NuStar Energy L.P. of payment for operating and maintenance services we provided to NuStar Energy L.P. We have indemnified NuStar Energy L.P. for certain environmental liabilities related to assets we previously sold to NuStar Energy 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.
Under a services agreement, through December 31, 2005, we provided NuStar Energy L.P. with the corporate functions of legal, accounting, treasury, engineering, information technology, and other services for an administrative fee. Effective January 1, 2006, the administrative fee was amended to provide for fewer services as a result of the transfer to NuStar GP, LLC (formerly Valero GP, LLC), the general partner of the general partner of NuStar Energy L.P., of a substantial number of employees of our subsidiaries who had previously provided services to NuStar GP, LLC under the prior services agreement. The administrative fee was recorded as a reduction of “general and administrative expenses.” Effective January 1, 2007, the services agreement was amended to provide for limited services. This amended services agreement provided for a termination date of December 31, 2010, unless we terminated the agreement earlier, in which case we were required to pay a termination fee of $13 million. In April 2007, we notified NuStar Energy L.P. of our decision to terminate the services agreement. Accordingly, the $13 million termination fee was accrued and paid during the second quarter of 2007.
As of December 31, 2006, our “receivables, net” included $1 million from NuStar Energy L.P., representing amounts due for employee costs, insurance costs, operating expenses, administrative costs, and rentals. As of December 31, 2006, our “accounts payable” included $21 million to NuStar Energy L.P., representing amounts due for pipeline tariffs, terminalling fees, and tank rentals and fees. The following table summarizes the results of transactions with NuStar Energy L.P. (in millions):
                 
    Year Ended December 31,
    2006   2005
Expenses charged by us to NuStar Energy L.P.
  127     80  
Fees and expenses charged to us by NuStar Energy L.P.
    261       234  
Effective July 1, 2005, we acquired Martin Oil Company LLC, a wholesale motor fuel marketer in the midwestern United States, from NuStar Energy L.P. The acquisition cost was $26 million, $22 million of which represented working capital acquired in the transaction.
10. DEFERRED CHARGES AND OTHER ASSETS
“Deferred charges and other assets, net” includes refinery turnaround and catalyst costs. As indicated in Note 1, refinery turnaround costs are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. Fixed-bed catalyst costs are deferred when incurred and amortized on a straight-line basis over the estimated useful life of the specific catalyst. Amortization expense for deferred refinery turnaround and catalyst costs was $383 million, $293 million, and $205 million for the years ended December 31, 2007, 2006, and 2005, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cameron Highway Oil Pipeline Project
We own a 50% interest in the Cameron Highway Oil Pipeline Company, a general partnership formed to construct and operate a crude oil pipeline (the Cameron Highway Oil Pipeline Project). The 390-mile crude oil pipeline, which began operations during the first quarter of 2005, delivers up to 500,000 barrels per day from the Gulf of Mexico to the major refining areas of Port Arthur and Texas City, Texas. Our investment in the Cameron Highway Oil Pipeline Project is accounted for using the equity method and is included in “deferred charges and other assets, net” in the consolidated balance sheets. During May and June of 2007, we made cash capital contributions of $215 million representing our 50% portion of the amount required to enable the joint venture to redeem its fixed-rate notes and variable-rate debt. In 2005, we received a $48 million return of our investment resulting from the refinancing of the Cameron Highway Oil Pipeline Project’s debt. As of December 31, 2007 and 2006, our investment in the Cameron Highway Oil Pipeline Project totaled $297 million and $100 million, respectively.
11. ACCRUED EXPENSES
Accrued expenses consisted of the following (in millions):
                 
    December 31,  
    2007     2006  
Employee wage and benefit costs
  $ 259     $ 194  
Interest expense
    79       84  
Contingent earn-out obligations
    25       75  
Derivative liabilities
    10       17  
Environmental costs
    55       44  
Other
    74       93  
 
           
Accrued expenses
  $ 502     $ 507  
 
           

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. DEBT AND CAPITAL LEASE OBLIGATIONS
Long-term debt balances, at stated values, and capital lease obligations consisted of the following (in millions):
                         
            December 31,  
    Maturity     2007     2006  
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  
3.50% notes
    2009       200       200  
4.75% notes
    2013       300       300  
4.75% notes
    2014       200       200  
6.125% notes
    2007       -       230  
6.125% notes
    2017       750       -  
6.625% notes
    2037       1,500       -  
6.875% notes
    2012       750       750  
7.50% notes
    2032       750       750  
8.75% notes
    2030       200       200  
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%
    2011       200       200  
6.70%
    2013       180       180  
6.75%
    2011       210       210  
6.75%
    2014       185       185  
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% (callable)
    2015       287       287  
9.25% (callable)
    2010       -       175  
9.50% (callable) (b)
    2013       350       350  
Other debt
  Various     6       14  
Net unamortized discount, including fair value adjustments
            (42 )     (26 )
 
                   
Total debt
            6,819       5,048  
Capital lease obligations
            43       46  
 
                   
Total debt and capital lease obligations
            6,862       5,094  
Less current portion, including net unamortized premium of $34 and $10
            (392 )     (475 )
 
                   
Long-term debt and capital lease obligations, less current portion
          $ 6,470     $ 4,619  
 
                   
 
(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.
 
(b)   In December 2007, we exercised the call provision on the 9.50% senior notes. These notes were redeemed on February 1, 2008 at 104.750% of stated value. The carrying amount of these notes as of December 31, 2007 was $381 million.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Bank Credit Facilities
In August 2005, we replaced our two $750 million revolving bank credit facilities with a $2.5 billion five-year revolving credit facility (the Revolver), which originally had a maturity date of August 2010. Borrowings under the Revolver bear interest at LIBOR plus a margin, or an alternate base rate as defined under the agreement. We are also being charged various fees and expenses in connection with the Revolver, including facility fees and letter of credit fees. The interest rate and fees under the Revolver are subject to adjustment based upon the credit ratings assigned to our long-term debt. The Revolver also included certain restrictive covenants including a coverage ratio and a debt-to-capitalization ratio. In July 2006, the Revolver was amended to (i) extend the maturity date by one year to August 2011, (ii) eliminate the coverage ratio covenant, and (iii) reduce the pricing under the agreement. In November 2007, the Revolver was amended to extend the maturity date from August 2011 to November 2012. As of December 31, 2007 and 2006, there were no borrowings outstanding under the Revolver and outstanding letters of credit issued under this facility totaled $292 million and $245 million, respectively.
In addition to the Revolver, one of our Canadian subsidiaries has a committed revolving credit facility under which it may borrow and obtain letters of credit up to Cdn. $115 million. In December 2007, the Canadian credit facility was amended to extend the maturity date from December 2010 to December 2012. As of December 31, 2007 and 2006, we had no borrowings outstanding and letters of credit issued under this credit facility totaled Cdn. $11 million and Cdn. $85 million, respectively.
We also have various uncommitted short-term bank credit facilities. As of December 31, 2007 and 2006, we had no borrowings outstanding under our uncommitted short-term bank credit facilities; however, there were $502 million and $343 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.
During April 2007, we borrowed $3 billion under a 364-day term credit agreement with a financial institution to fund the accelerated share repurchase program discussed in Note 14. The term loan bore interest at LIBOR plus a margin, or an alternate base rate as defined under the term credit agreement. In May 2007, we repaid $500 million of the borrowings under the term credit agreement. The remaining balance of $2.5 billion was repaid in June 2007 using available cash and proceeds from our issuance of long-term notes in June 2007 described below.
In August 2005, we entered into a $1.5 billion five-year bank term loan which was used to partially finance the Premcor Acquisition. The term loan bore interest at LIBOR plus 75 basis points and was fully repaid by December 31, 2005.
Other Long-Term Debt
In February 2007, we redeemed our 9.25% senior notes for $183 million, or 104.625% of stated value. These notes had a carrying amount of $187 million on the date of redemption, resulting in a gain of $4 million that was included in “other income, net” in the consolidated statement of income. In addition, we made scheduled debt repayments of $230 million in April 2007 related to our 6.125% notes and $50 million in November 2007 related to our 6.311% CORE notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In June 2007, we issued $750 million of 6.125% notes due June 15, 2017 and $1.5 billion of 6.625% notes due June 15, 2037. Proceeds from the issuance of these notes totaled $2.245 billion, before deducting underwriting discounts of $18 million.
In December 2007, we exercised a call provision on our 9.5% senior notes, which were redeemed on February 1, 2008 for $367 million, resulting in a gain of $14 million in 2008.
During March 2006, we made a scheduled debt repayment of $220 million related to our 7.375% notes. In addition, during the year ended December 31, 2006, we made the following debt payments:
    $1 million during March 2006 related to our 7.75% notes due in February 2012,
 
    $14 million during July 2006 related to our 6.75% senior notes due in May 2014, and
 
    $14 million during July 2006 related to our 7.5% senior notes due in June 2015.
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. During September 2005, we repurchased $190 million of the 7.75% senior subordinated notes due in February 2012. In October 2005, we repurchased the 12.5% senior notes due in January 2009 for $182 million. In November 2005, we repurchased the Ohio Water Development Authority Environmental Facilities Revenue Bonds for $10 million. In 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.
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, 2007 were as follows (in millions):
         
2008
  $ 356  
2009
    209  
2010
    33  
2011
    418  
2012
    759  
Thereafter
    5,086  
Net unamortized discount and fair value adjustments
    (42 )
 
     
Total
  $ 6,819  
 
     
For payments due on capital lease obligations, see Note 22.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2007 and 2006, the estimated fair value of our long-term debt, including current portion, was as follows (in millions):
                 
    December 31,
    2007   2006
Carrying amount
  6,819     5,048  
Fair value
    7,109       5,361  
13. OTHER LONG-TERM LIABILITIES
Other long-term liabilities consisted of the following (in millions):
                 
    December 31,  
    2007     2006  
Employee benefit plan liabilities
  $ 701     $ 686  
Environmental liabilities
    230       254  
Tax liabilities for uncertain income tax positions
    160       -  
Tax liabilities other than income taxes
    163       95  
Deferred gain on sale of assets to NuStar Energy L.P.
    114       135  
Insurance liabilities
    86       91  
Asset retirement obligations
    70       51  
Unfavorable lease obligations
    51       65  
Contingent earn-out obligations
    -       25  
Other
     235        220  
 
           
Other long-term liabilities
  $ 1,810     $ 1,622  
 
           
Employee benefit plan liabilities include the long-term obligation for our pension and other postretirement benefit plans as discussed in Note 20. Environmental liabilities reflect the long-term portion of our estimated remediation costs for environmental matters as discussed in Note 23. Tax liabilities for uncertain income tax positions reflect obligations under FIN 48 as discussed in Note 18. Tax liabilities other than income taxes include long-term liabilities for various taxes such as sales, franchise, and excise taxes as well as interest accrued on all tax-related liabilities, including income taxes. Deferred gain reflects the unamortized balance of the proceeds in excess of the carrying amount of assets we sold to NuStar Energy L.P. 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.
Unfavorable lease obligations reflect the fair value of liabilities assumed in connection with the Premcor Acquisition related to lease agreements for closed retail facilities and the UDS Acquisition related to lease agreements for retail facilities and vessel charters. Included in “other” are liabilities for various matters including legal and regulatory liabilities, derivative obligations, and various contractual obligations.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The table below reflects the changes in our asset retirement obligations (in millions). See Note 1 under “Asset Retirement Obligations” for a discussion of the liability related to these obligations.
                         
    Year Ended December 31,  
    2007     2006     2005  
Balance as of beginning of year
  $ 51     $ 51     $ 41  
Additions to accrual
    1       1       9  
Accretion expense
    2       2       2  
Settlements
    (13 )     (5 )     (2 )
Changes in timing and amount of estimated cash flows
    28       2       1  
Foreign currency translation
    1       -       -  
 
                 
Balance as of end of year
  $ 70     $ 51     $ 51  
 
                 
14. STOCKHOLDERS’ EQUITY
Share Activity
For the years ended December 31, 2007, 2006, and 2005, activity in the number of shares of preferred stock, common stock, and treasury stock was as follows (in millions):
                         
    Preferred   Common   Treasury
    Stock   Stock   Stock
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 issued, net of shares repurchased, in connection with employee stock plans and other
    -       -       7  
 
                       
Balance as of December 31, 2005
    3       621       (4 )
Conversion of preferred stock
    (3 )     6       -  
Shares repurchased, net of shares issued, in connection with employee stock plans and other
    -       -       (20 )
 
                       
Balance as of December 31, 2006
    -       627       (24 )
Shares repurchased under $6 billion common stock purchase program
    -       -       (70 )
Shares issued, net of shares repurchased, in connection with employee stock plans and other
    -       -       3  
 
                       
Balance as of December 31, 2007
    -       627       (91 )
 
                       

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Preferred Stock
We have 20 million shares of preferred stock authorized with a par value of $.01 per share. As of December 31, 2007 and 2006, no shares of preferred stock were outstanding.
In connection with the acquisition of the St. Charles Refinery 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 was amortized as additional preferred stock dividends through June 30, 2006, the day before the mandatory conversion of the preferred stock as discussed below.
Each share of convertible preferred stock was convertible, at the option of the holder, at any time before July 1, 2006 into 1.982 shares of our common stock. All mandatory convertible preferred stock not previously converted automatically converted to our common stock on July 1, 2006. Upon automatic conversion of the convertible preferred stock on July 1, 2006, 1.982 shares of common stock were issued for each share of convertible preferred stock based on the average closing price of our common stock over the 20-day trading period ending on the second trading day prior to July 1, 2006. During 2006 and 2005, 3,164,151 and 6,835,849 shares of the preferred stock were converted into 6,271,327 and 13,548,636 shares of our common stock, respectively.
Prior to the issuance of shares of our common stock upon conversion of the convertible preferred stock, the number of shares of our common stock included in the calculation of “earnings per common share - assuming dilution” for each reporting period was based on the average closing price of our common stock over the 20-day trading period ending on the second trading day prior to the end of the reporting period.
Common Stock Offerings
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.
Common Stock Splits
On September 15, 2005, 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 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) for 2005 were adjusted to reflect the effect of the stock split. 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.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Treasury Stock
We purchase shares of our common stock in open market transactions to meet our obligations under employee benefit plans. We also purchase shares of our common stock from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions.
On October 19, 2006, our board of directors approved a $2 billion common stock purchase program. This authorization was in addition to our existing authorization to purchase shares to offset dilution created by our employee stock incentive programs. On April 25, 2007, our board of directors approved an amendment to our $2 billion common stock purchase program to increase the authorized purchases under the program to $6 billion. Stock purchases under the program are made from time to time at prevailing prices as permitted by securities laws and other legal requirements, and are subject to market conditions and other factors. The program does not have a scheduled expiration date.
In conjunction with the increase in our common stock purchase program, we entered into an agreement with a financial institution to purchase $3 billion of our shares under an accelerated share repurchase program, and in late April 2007, 42.1 million shares were purchased under this agreement. As described in Note 12 above, the purchase of these shares was initially funded with a 364-day term credit agreement, which we subsequently replaced with longer-term financing. The cost of the shares purchased under this accelerated share repurchase program was to be adjusted at the expiration of the program, with the final purchase cost based on a discount to the average trading price of our common stock, weighted by the daily volume of shares traded, during the program period. Any adjustment to the cost could be paid in cash or stock, at our option.
The accelerated share repurchase program was completed on July 23, 2007, and we elected to pay in cash an additional $94 million for the shares purchased. This cash payment was deducted from reported income from continuing operations in calculating earnings per common share from continuing operations assuming dilution for the year ended December 31, 2007 (see Note 15).
During the years ended December 31, 2007, 2006, and 2005, we purchased 84.3 million, 34.6 million, and 13.2 million shares of our common stock, respectively, at a cost of $5.8 billion, $2.0 billion, and $571 million, respectively. These purchases were made in connection with the administration of our employee benefit plans and the $6 billion stock purchase program authorized by our board of directors, including the effect of the accelerated share repurchase program discussed above. During the years ended December 31, 2007, 2006, and 2005, we issued 16.1 million, 14.7 million, and 20.9 million shares from treasury, respectively, at an average cost of $62.89, $55.70, and $27.51 per share, respectively, for our employee benefit plans.
Through February 22, 2008, we have purchased 4.9 million shares of our common stock at a cost of $317 million during 2008.
Common Stock Dividends
On January 17, 2008, our board of directors declared a quarterly cash dividend of $0.12 per common share payable March 12, 2008 to holders of record at the close of business on February 13, 2008.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Accumulated Other Comprehensive Income
Accumulated balances for each component of accumulated other comprehensive income (loss) were as follows (in millions):
                                 
    Foreign             Net Gain     Accumulated  
    Currency     Pension/OPEB     (Loss) On     Other  
    Translation     Liability     Cash Flow     Comprehensive  
    Adjustment     Adjustment     Hedges     Income (Loss)  
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  
2006 change
    (11 )     (100 )     41       (70 )
 
                       
Balance as of December 31, 2006
    330       (110 )     45       265  
2007 change
    250       86       (28 )     308  
 
                       
Balance as of December 31, 2007
  $ 580     $ (24 )   $ 17     $ 573  
 
                       
Preferred Share Purchase Rights
Prior to June 30, 2007, each outstanding share of our common stock was accompanied by one preferred share purchase right (Right). With certain exceptions, each Right entitled 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. These Rights expired on June 30, 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. EARNINGS PER SHARE
Earnings per common share amounts from continuing operations were computed as follows (dollars and shares in millions, except per share amounts):
                         
    Year Ended December 31,  
    2007     2006     2005  
Earnings per common share from continuing operations:
                       
Income from continuing operations
  $ 4,565     $ 5,287     $ 3,473  
Less: Preferred stock dividends
    -       2       13  
 
                 
Income from continuing operations applicable to common stock
  $ 4,565     $ 5,285     $ 3,460  
 
                 
 
Weighted-average common shares outstanding
    565       611       549  
 
                 
 
Earnings per common share from continuing operations
  $ 8.08     $ 8.65     $ 6.30  
 
                 
 
                       
Earnings per common share from continuing operations - assuming dilution:
                       
Income from continuing operations
  $ 4,565     $ 5,287     $ 3,473  
Less: Cash paid in final settlement of accelerated share repurchase program
    94       -       -  
 
                 
Income from continuing operations assuming dilution
  $ 4,471     $ 5,287     $ 3,473  
 
                 
 
Weighted-average common shares outstanding
    565       611       549  
Effect of dilutive securities:
                       
Stock options
    13       18       21  
Performance awards and other benefit plans
    1       1       6  
Mandatory convertible preferred stock
    -       2       12  
 
                 
Weighted-average common shares outstanding - assuming dilution
    579       632       588  
 
                 
 
                       
Earnings per common share from continuing operations - assuming dilution
  $ 7.72     $ 8.36     $ 5.90  
 
                 
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,
    2007   2006   2005
Stock options
    2       -       3  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
16. STATEMENTS OF CASH FLOWS
In order to determine net cash provided by operating activities, net income is adjusted by, among other things, changes in current assets and current liabilities as follows (in millions):
                         
    Year Ended December 31,  
    2007     2006     2005  
Decrease (increase) in current assets:
                       
Restricted cash
  $ -     $ (1 )   $ 192  
Receivables, net
    (3,227 )     (837 )     (834 )
Inventories
    (249 )     (405 )     372  
Income taxes receivable
    32       38       (70 )
Prepaid expenses and other
    (58 )     (81 )     217  
Increase (decrease) in current liabilities:
                       
Accounts payable
    2,557       1,362       1,126  
Accrued expenses
    (20 )     (54 )     (116 )
Taxes other than income taxes
    15       (4 )     28  
Income taxes payable
     481       (162 )      167  
 
                 
Changes in current assets and current liabilities
  $ (469 )   $ (144 )   $ 1,082  
 
                 
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, and current portion of long-term debt and capital lease obligations, as well as the effect of certain noncash investing and financing activities discussed below;
 
    previously accrued capital expenditures, deferred turnaround and catalyst costs, and contingent earn-out payments are reflected in investing activities in the consolidated statements of cash flows;
 
    changes in assets held for sale and liabilities related to assets held for sale prior to the sale of the Lima Refinery are reflected in the line item to which the changes relate in the table above;
 
    the amounts shown above exclude the current assets and current liabilities acquired in connection with the Premcor Acquisition and certain minor acquisitions in 2005, 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
 
    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, 2007 included:
    a $158 million charge to “additional paid-in capital” to accrue for purchases of our common stock in 2007 that were not settled and paid until 2008; and
 
    adjustments to goodwill and certain noncurrent liabilities resulting from adjustments to the purchase price allocations related to the Premcor and UDS Acquisitions (as discussed in Note 8).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Noncash investing and financing activities for the year ended December 31, 2006 included:
    the recognition of $158 million (pre-tax) of SAB 51 credits related to our investment in NuStar Energy L.P. (as discussed in Note 9);
 
    adjustments to property, plant and equipment, goodwill, and certain current and noncurrent assets and liabilities resulting from adjustments to the purchase price allocations related to the Premcor and UDS Acquisitions;
 
    the conversion of 3,164,151 shares of preferred stock into 6,271,327 shares of our common stock as discussed in Note 14; and
 
    the recording of a $39 million capital lease obligation and related capital lease asset pertaining to certain facilities at the Lima Refinery.
Noncash investing and financing activities for the year ended December 31, 2005 included:
    the issuance of $3.2 billion (85 million shares) of common stock and $595 million of vested employee stock options as partial consideration for the Premcor Acquisition;
 
    the conversion of 6,835,849 shares of preferred stock into 13,548,636 shares of our common stock as discussed in Note 14;
 
    the recognition of a $28 million capital lease obligation and related capital lease asset pertaining to certain equipment at our Texas City Refinery; and
 
    adjustments to property, plant and equipment and certain current and noncurrent assets and liabilities resulting from adjustments to the purchase price allocation related to the acquisition of the Aruba Refinery in 2004.
Cash flows related to the discontinued operations of the Lima Refinery have been combined with the cash flows from continuing operations within each category in the consolidated statement of cash flows for each period presented. Cash provided by operating activities related to our discontinued operations was $260 million, $215 million, and $121 million for the years ended December 31, 2007, 2006, and 2005, respectively. Cash used in investing activities related to the Lima Refinery was $14 million, $133 million, and $42 million for the years ended December 31, 2007, 2006, and 2005, respectively.
Cash flows related to interest and income taxes were as follows (in millions):
                         
    Year Ended December 31,
    2007   2006   2005
Interest paid (net of amount capitalized)
  331     261     251  
Income taxes paid, net of tax refunds received
    2,014       2,349       1,345  
17. PRICE RISK MANAGEMENT ACTIVITIES
Commodity Price Risk
We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refining operations. To reduce the impact of this price volatility, we use derivative commodity instruments (swaps, futures, and options) to manage our exposure to:
    changes in the fair value of a portion of our refinery feedstock and refined product inventories and a portion of our unrecognized firm commitments to purchase these inventories (fair value hedges);

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
    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. We sometimes use interest rate swap agreements to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt. As of December 31, 2007 and 2006, we did not have any interest rate swap agreements.
As of December 31, 2005, we had interest rate swap agreements with a notional amount of $1.0 billion and interest rates ranging from 5.6% to 6.0%. All of these swaps were accounted for as fair value hedges. During the first quarter of 2006, $125 million of these interest rate swaps were settled on their scheduled maturity date. Effective May 1, 2006, we terminated the remaining $875 million of interest rate swap contracts outstanding at that date for a payment of $54 million. Substantially all of this payment was deferred and is being amortized to interest expense over the remaining lives of the debt instruments that were being hedged.
Foreign Currency Risk
We are exposed to exchange rate fluctuations on transactions related to our Canadian operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments. As of December 31, 2007, we had commitments to purchase $507 million of U.S. dollars. These commitments matured on or before January 29, 2008, resulting in a 2008 loss of $2 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,
    2007   2006   2005
Fair value hedges
  (17 )   (11 )   16  
Cash flow hedges
    (18 )     8       21  
The above amounts were included in “cost of sales” in the consolidated statements of income. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness. No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges.
During 2005, we recognized in “cost of sales” approximately $525 million of pre-tax losses resulting from the forward sales of distillates and associated forward purchases of crude oil. All of these forward derivative positions were closed prior to December 31, 2005. During 2007, 2006, and 2005, we recognized in “cost of sales” gains (losses) of $37 million, $4 million, and $(6) million, respectively, associated with trading activities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For cash flow hedges, gains and losses reported in “accumulated other comprehensive income” in the consolidated balance sheets are reclassified into cost of sales when the forecasted transactions affect income. During the years ended December 31, 2007, 2006, and 2005, respectively, we recognized in “accumulated other comprehensive income” unrealized after-tax gains (losses) of $(11) million, $70 million, and $(218) million on certain cash flow hedges, primarily related to forward sales of gasoline and distillates and associated forward purchases of crude oil, with $17 million, $45 million, and $4 million of cumulative after-tax gains on cash flow hedges remaining in “accumulated other comprehensive income” as of December 31, 2007, 2006, and 2005, respectively. The deferred gains at December 31, 2007 will be reclassified into “cost of sales” in 2008 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, 2007, 2006, and 2005, there were no amounts reclassified from “accumulated other comprehensive income” into income as a result of the discontinuance of cash flow hedge accounting.
Market and Credit Risk
Our price risk management activities involve the receipt or payment of fixed price commitments into the future. These transactions give rise to market risk, the risk that future changes in market conditions may make an instrument less valuable. We closely monitor and manage our exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Market risks are monitored by a risk control group to ensure compliance with our stated risk management policy. Concentrations of customers in the refining industry may impact our overall exposure to credit risk, in that these customers may be similarly affected by changes in economic or other conditions. We believe that our counterparties will be able to satisfy their obligations under their price risk management contracts with us.
18. INCOME TAXES
Income from continuing operations before income tax expense from domestic and foreign operations was as follows (in millions):
                         
    Year Ended December 31,  
    2007     2006     2005  
U.S. operations
  $ 5,846     $ 7,290     $ 4,081  
Canadian operations
    458       289       452  
Aruban operations
    422        319        561  
 
                 
Income from continuing operations before income tax expense
  $ 6,726     $ 7,898     $ 5,094  
 
                 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following is a reconciliation of income tax expense related to continuing operations to income taxes computed by applying the statutory federal income tax rate (35% for all years presented) to income from continuing operations before income tax expense (in millions):
                         
    Year Ended December 31,  
    2007     2006     2005  
Federal income tax expense at the U.S. statutory rate
  $ 2,354     $ 2,764     $ 1,783  
U.S. state income tax expense, net of U.S. federal income tax effect
    83       46       46  
U.S. manufacturing deduction
    (88 )     (71 )     (21 )
Canadian operations
    (48 )     (45 )     (7 )
Aruban operations
    (144 )     (108 )     (193 )
Other, net
    4       25       13  
 
                 
Income tax expense
  $ 2,161     $ 2,611     $ 1,621  
 
                 
The Aruba Refinery’s profits are non-taxable in Aruba due to a tax holiday granted by the Government of Aruba (GOA) through December 31, 2010. The tax holiday resulted in increased net income of $8 million, or $0.01 per common share assuming dilution, $6 million, or $0.01 per common share assuming dilution, and $11 million, or $0.02 per common share assuming dilution, for the years ended December 31, 2007, 2006, and 2005, respectively.
Components of income tax expense (benefit) related to continuing operations were as follows (in millions):
                         
    Year Ended December 31,  
    2007     2006     2005  
Current:
                       
U.S. federal
  $ 1,764     $ 2,198     $ 1,104  
U.S. state
    96       76       92  
Canada
    202       51       187  
Aruba
    3       3       2  
 
                 
Total current
    2,065       2,328       1,385  
 
                 
 
Deferred:
                       
U.S. federal
    155       285       291  
U.S. state
    31       (5 )     (21 )
Canada
    (90 )     3       (35 )
Aruba
    -       -       1  
 
                 
Total deferred
    96       283        236  
 
                 
 
Income tax expense
  $ 2,161     $ 2,611     $ 1,621  
 
                 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows (in millions):
                 
    December 31,  
    2007     2006  
Deferred income tax assets:
               
Tax credit carryforwards
  $ 95     $ 76  
Net operating losses (NOL)
    36       49  
Compensation and employee benefit liabilities
    175       217  
Environmental
    86       95  
Inventories
    224       133  
Property, plant and equipment
    -       9  
Other assets
     360       307  
 
           
Total deferred income tax assets
    976       886  
Less: Valuation allowance
    (54 )     (100 )
 
           
Net deferred income tax assets
     922       786  
 
           
 
               
Deferred income tax liabilities:
               
Turnarounds
    (264 )     (249 )
Property, plant and equipment
    (4,297 )     (4,249 )
Inventories
    (302 )     (400 )
Other
    (126 )     (155 )
 
           
Total deferred income tax liabilities
    (4,989 )     (5,053 )
 
           
 
               
Net deferred income tax liabilities
  $ (4,067 )   $ (4,267 )
 
           
As of December 31, 2007, 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
  65     2008 through 2026
U.S. state income tax credits
    34     Unlimited
Foreign tax credit
    30     2011    
U.S. state NOL
    753     2008 through 2027
We have recorded a valuation allowance as of December 31, 2007 and 2006, 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, 2007 is primarily dependent upon our ability to generate future taxable income in certain states and foreign source income in the United States.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Subsequently recognized tax benefits related to the valuation allowance for deferred income tax assets as of December 31, 2007 will be allocated as follows (in millions):
         
Income tax benefit in consolidated statement of income
  $ 16  
Goodwill
    31  
Additional paid-in capital
    7  
 
     
Total
  $ 54  
 
     
Deferred income taxes have not been provided on the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and the respective tax bases of our foreign subsidiaries based on the determination that such differences are essentially permanent in duration in that the earnings of these subsidiaries are expected to be indefinitely reinvested in foreign operations. As of December 31, 2007, the cumulative undistributed earnings of these subsidiaries were approximately $3.9 billion. If those earnings were not considered indefinitely reinvested, deferred income taxes would have been recorded after consideration of foreign tax credits. It is not practicable to estimate the amount of additional tax that might be payable on those earnings, if distributed.
As discussed in Note 1, we adopted the provisions of FIN 48 on January 1, 2007. We did not recognize a significant change in our liability for uncertain tax positions as a result of our implementation of FIN 48; however, certain amounts previously reported in “deferred income taxes” were reclassified to “other long-term liabilities” in the consolidated balance sheet as of January 1, 2007. In accordance with the provisions of FIN 48, prior period amounts were not reclassified.
The following is a reconciliation of the change in unrecognized tax benefits for the year ended December 31, 2007 (in millions):
         
Balance as of January 1, 2007
  $ 160  
Additions based on tax positions related to the current year
    32  
Additions for tax positions related to prior years
    13  
Reductions for tax positions related to prior years
    (36 )
Settlements
    (5 )
 
     
Balance as of December 31, 2007
  $ 164  
 
     
Included in the balance as of December 31, 2007 are $65 million of tax benefits that, if recognized, would reduce our annual effective tax rate. We do not expect our unrecognized tax benefits to change significantly over the next 12 months.
We have elected to classify any interest expense and penalties related to income taxes within income tax expense in our consolidated statements of income. During the years ended December 31, 2007, 2006, and 2005, we recognized approximately $1 million, $25 million, and $12 million in interest and penalties. We had accrued approximately $46 million and $45 million for the payment of interest and penalties as of December 31, 2007 and 2006, respectively.
Our tax years through 1999 and UDS’s tax years through 1998 are closed to adjustment by the Internal Revenue Service. Valero’s separate tax years 2000 and 2001 (prior to the UDS Acquisition) are currently under examination. In addition, our tax years 2002 through 2005 are currently under examination and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Premcor’s separate tax years 2002 through 2005 are also under examination. During 2007, the Internal Revenue Service proposed adjustments to our 2002 and 2003 taxable income, including adjustments related to inventory and depreciation methods. We are protesting the proposed adjustments and do not expect that the ultimate disposition of these findings will result in a material change to our financial position or results of operations. We believe that adequate provisions for income taxes have been reflected in the consolidated financial statements.
19. SEGMENT INFORMATION
We have two reportable segments, refining and retail. Our refining segment includes refining operations, wholesale marketing, product supply and distribution, and transportation operations. The retail segment includes company-operated convenience stores, Canadian dealers/jobbers and truckstop facilities, cardlock facilities, and home heating oil operations. Operations that are not included in either of the two reportable segments are included in the corporate category.
The reportable segments are strategic business units that offer different products and services. They are managed separately as each business requires unique technology and marketing strategies. Performance is evaluated based on operating income. Intersegment sales are generally derived from transactions made at prevailing market rates.
                                 
    Refining   Retail   Corporate   Total
    (in millions)
 
                               
Year ended December 31, 2007:
                               
Operating revenues from external customers
  86,443     8,884     -     95,327  
Intersegment revenues
    6,298       -       -       6,298  
Depreciation and amortization expense
    1,222       90       48       1,360  
Operating income (loss)
    7,355       249       (686 )     6,918  
Total expenditures for long-lived assets
    2,483       107       193       2,783  
 
                               
Year ended December 31, 2006:
                               
Operating revenues from external customers
    79,406       8,234       -       87,640  
Intersegment revenues
    5,729       -       -       5,729  
Depreciation and amortization expense
    985       87       44       1,116  
Operating income (loss)
    8,182       182       (642 )     7,722  
Total expenditures for long-lived assets
    3,637       101       57       3,795  
 
                               
Year ended December 31, 2005:
                               
Operating revenues from external customers
    73,216       7,400       -       80,616  
Intersegment revenues
    4,971       -       -       4,971  
Depreciation and amortization expense
    716       83       37       836  
Operating income (loss)
    5,709       154       (595 )     5,268  
Total expenditures for long-lived assets
    2,384       106       87       2,577  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Our principal products include conventional and CARB gasolines, RBOB, ultra-low-sulfur diesel, and oxygenates and other gasoline blendstocks. We also produce a substantial slate of middle distillates, jet fuel, and petrochemicals, in addition to lube oils and asphalt. Through December 31, 2005, our revenues related to crude oil buy/sell arrangements were included in the refining segment in the “other product revenues” line in the table below. Commencing January 1, 2006, in accordance with the guidance provided by EITF No. 04-13, revenues and cost of sales related to these arrangements ceased to be recognized (see Note 1 for a discussion of EITF No. 04-13 in “Revenue Recognition”). Other product revenues also include such products as gas oils, No. 6 fuel oil, and petroleum coke. Operating revenues from external customers for our principal products for the years ended December 31, 2007, 2006, and 2005 were as follows (in millions):
                         
    Year Ended December 31,  
    2007     2006     2005  
Refining:
                       
Gasolines and blendstocks
  $   43,014     $   40,458     $   33,492  
Distillates
    31,552       28,524       22,383  
Petrochemicals
    3,797       3,254       2,639  
Lubes and asphalts
    1,837       1,863       1,575  
Other product revenues
    6,243       5,307       13,127  
 
                 
Total refining operating revenues
    86,443       79,406       73,216  
 
                 
Retail:
                       
Fuel sales (gasoline and diesel)
    7,235       6,709       5,945  
Merchandise sales and other
    1,356       1,272       1,206  
Home heating oil
    293       253       249  
 
                 
Total retail operating revenues
    8,884       8,234       7,400  
 
                 
Consolidated operating revenues
  $   95,327     $   87,640     $   80,616  
 
                 
Operating revenues by geographic area for the years ended December 31, 2007, 2006, and 2005 are shown in the table below (in millions). The geographic area is based on location of customer.
                         
    Year Ended December 31,  
    2007     2006     2005  
United States
  $   82,168     $   76,604     $   70,333  
Canada
    8,142       7,275       7,591  
Other foreign countries
    5,017       3,761       2,692  
 
                 
Consolidated operating revenues
  $   95,327     $   87,640     $   80,616  
 
                 
For the years ended December 31, 2007, 2006, and 2005, no customer accounted for more than 10% of our consolidated operating revenues.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Long-lived assets include property, plant and equipment, intangible assets subject to amortization, and certain long-lived assets included in “deferred charges and other assets, net.” Geographic information by country for long-lived assets consisted of the following (in millions):
                 
    December 31,  
    2007     2006  
United States
  $  19,590     $  18,407  
Canada
    2,412       2,016  
Aruba
    972       909  
 
           
Consolidated long-lived assets
  $ 22,974     $ 21,332  
 
           
Total assets by reportable segment were as follows (in millions):
                 
    December 31,  
    2007     2006  
Refining
  $  37,703     $  34,275  
Retail
    2,098       1,826  
Corporate
    2,921       1,652  
 
           
Total consolidated assets
  $ 42,722     $ 37,753  
 
           
The entire balance of goodwill as of December 31, 2007 and 2006 has been included in the total assets of the refining reportable segment.
20. EMPLOYEE BENEFIT PLANS
Pension Plans and Postretirement Benefits Other Than Pensions
We have several qualified non-contributory defined benefit plans (collectively, the Qualified Plans), some of which are subject to collective bargaining agreements. The Qualified Plans cover substantially all employees in the United States and generally provide eligible employees with retirement income based on years of service and compensation during specific periods.
We also have several nonqualified supplemental executive retirement plans (Supplemental Plans), which provide additional pension benefits to executive officers and certain other employees. The Supplemental Plans and the Qualified Plans are collectively referred to as the Pension Plans.
We also provide certain health care and life insurance benefits for retired employees, referred to as other postretirement benefits. Substantially all of our employees may become eligible for these benefits if, while still working for us, they either reach normal retirement age or take early retirement. We offer health care benefits through a self-insured plan and, for certain locations, a health maintenance organization while life insurance benefits are provided through an insurance company. We fund our postretirement benefits other than pensions on a pay-as-you-go basis. Individuals who became our employees as a result of an acquisition became eligible for other postretirement benefits under our plan as determined by the terms of the relevant acquisition agreement.
We assumed certain obligations under various pension and other postretirement benefit plans in conjunction with the Aruba and Premcor Acquisitions, and in connection with the Kaneb Acquisition by NuStar

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Energy L.P. Our initial obligations under these plans were recorded through purchase accounting as of the date of each respective acquisition. Our disclosures include net periodic benefit costs related to such obligations commencing on the date of acquisition. In conjunction with the sale of NuStar GP Holdings, LLC discussed in Note 9, effective July 1, 2006, certain eligible employees of NuStar GP, LLC ceased participating in our Pension Plans and other postretirement benefit plans. These former employees became participants in separate employee benefit plans of NuStar GP, LLC. Certain liabilities related to pension and other postretirement benefits for these participants were transferred from us to NuStar GP, LLC and are included in the disclosures below as “Spin-off of NuStar Energy L.P.”
The changes in benefit obligation, the changes in fair value of plan assets, and the funded status of our Pension Plans and other postretirement benefit plans as of and for the years ended December 31, 2007 and 2006 were as follows (in millions):
                                 
                    Other Postretirement  
    Pension Plans     Benefit Plans  
    2007     2006     2007     2006  
 
                               
Change in benefit obligation:
                               
Benefit obligation at beginning of year
  $ 1,252     $ 1,188     $ 477     $ 454  
Service cost
    95       96       13       14  
Interest cost
    71       64       27       24  
Acquisitions
    -       -       -       2  
Participant contributions
    -       -       7       5  
Plan amendments
    (1 )     2       -       -  
Special termination benefits
    14       -       1       -  
Spin-off of NuStar Energy L.P.
    -       (1 )     -       (7 )
Medicare subsidy for prescription drugs
    -       -       1       -  
Benefits paid
    (78 )     (84 )     (20 )     (18 )
Actuarial (gain) loss
    (61 )     (13 )     (34 )     3  
Foreign currency exchange rate changes
    -       -       5       -  
 
                       
Benefit obligation at end of year
  $ 1,292     $ 1,252     $ 477     $ 477  
 
                       
 
                               
Change in plan assets:
                               
Fair value of plan assets at beginning of year
  $ 1,156     $ 793     $ -     $ -  
Actual return on plan assets
    125       91       -       -  
Valero contributions
    155       356       12       13  
Participant contributions
    -       -       7       5  
Medicare subsidy for prescription drugs
    -       -       1       -  
Benefits paid
    (78 )     (84 )     (20 )     (18 )
 
                       
Fair value of plan assets at end of year
  $ 1,358     $ 1,156     $ -     $ -  
 
                       
 
                               
Reconciliation of funded status:
                               
Fair value of plan assets at end of year
  $ 1,358     $ 1,156     $ -     $ -  
Less: Benefit obligation at end of year
    1,292       1,252       477       477  
 
                       
Funded status at end of year
  $ 66     $ (96 )   $ (477 )   $ (477 )
 
                       

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Table of Contents

VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The pre-tax amounts related to our Pension Plans and other postretirement benefit plans recognized in our consolidated balance sheets as of December 31, 2007 and 2006 were as follows (in millions):
                                 
                    Other Postretirement
    Pension Plans   Benefit Plans
    2007   2006   2007   2006
Deferred charges and other assets
  $ 239     $ 66     $ -     $ -  
Accrued expenses
    (13 )     (13 )     (18 )     (17 )
Other long-term liabilities
    (160 )     (149 )     (459 )     (460 )
Accumulated other comprehensive loss
    38       153       13       43  
The pre-tax amounts in accumulated other comprehensive (income) loss as of December 31, 2007 and 2006 that have not yet been recognized as components of net periodic benefit cost were as follows (in millions):
                                 
                    Other Postretirement
    Pension Plans   Benefit Plans
    2007   2006   2007   2006
Prior service cost (credit)
  $     22     $     25     $   (93 )   $ (102 )
Net actuarial loss
    16     128       106       145  
 
                       
Total
  $ 38   $ 153   $ 13   $ 43