Valero Energy (VLO) 10-K 2008 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(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, 2008

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 toSection 12(b) of the Act:Common stock, $0.01 par value per share listed on the New York Stock Exchange.

Securities registered pursuant toSection 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.
Yesþ Noo

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yeso Noþ

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. Yesþ Noo

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. (Check one):

    Large accelerated filerþ  Accelerated filero  Non-accelerated filer  o Smaller reporting companyo 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso Noþ

The aggregate market value of the voting and non-voting common stock held by non-affiliates was approximately $21.6 billion based on the last sales price quoted as of June 30, 2008 on the New York Stock Exchange, the last business day of the registrant’s most recently completed second fiscal quarter.

As of January 31, 2009, 516,308,274 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 April 30, 2009, at which directors will be elected. Portions of the 2009 Proxy Statement are incorporated by reference in Part III of this Form 10-K and are deemed to be a part of this report.

CROSS-REFERENCE SHEET

The following table indicates the headings in the 2009 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 2009 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,andSection 16(a) Beneficial Ownership Reporting Compliance
11. Executive Compensation	Compensation Committee, Compensation Discussion and Analysis, Director Compensation, Executive Compensation,andCertain Relationships and Related Transactions
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	Beneficial Ownership of Valero SecuritiesandEquity Compensation Plan Information
13. Certain Relationships and Related Transactions, and Director Independence	Certain Relationships and Related TransactionsandIndependent Directors
14. Principal Accountant Fees and Services	KPMG Fees for Fiscal Year 2008, KPMG Fees for Fiscal Year 2007,andAudit 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
PART I
Items 1., 1A. & 2.	Business, Risk Factors and Properties		1
	Segments		2
	Valero’s Operations		3
	Risk Factors		12
	Environmental Matters		16
	Properties		16
	Executive Officers of the Registrant		17
Item 1B.	Unresolved Staff Comments		17
Item 3.	Legal Proceedings		18
Item 4.	Submission of Matters to a Vote of Security Holders		19
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		20
Item 6.	Selected Financial Data		23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		51
Item 8.	Financial Statements and Supplementary Data		57
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		132
Item 9A.	Controls and Procedures		132
Item 9B.	Other Information		132
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		133
Item 11.	Executive Compensation		133
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		133
Item 13.	Certain Relationships and Related Transactions, and Director Independence		133
Item 14.	Principal Accountant Fees and Services		133
PART IV
Item 15.	Exhibits and Financial Statement Schedules		133
Signatures			138

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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 24 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, 2009, we had 21,765 employees.

We own and operate 16 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 CBOB and 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.

¹ CBOB, or “conventional blendstock for oxygenate blending,” is conventional gasoline blendstock intended for blending with oxygenates downstream of the refinery where it was produced. CBOB becomes conventional gasoline after blending with oxygenates.RBOBis a base unfinished reformulated gasoline mixture known as “reformulated gasoline blendstock for oxygenate blending.” It is a specially produced reformulated gasoline blendstock intended for blending with oxygenates downstream of the refinery where it was produced to produce finished gasoline that meets or exceeds U.S. emissions performance requirements for federal reformulated gasoline.

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SEGMENTS

Our business is organized into two reportable segments: refining and retail. Our refining segment includes refining operations, wholesale marketing, product supply and distribution, and transportation operations. The refining segment is segregated geographically into the Gulf Coast, Mid-Continent, West Coast, and Northeast regions.

Our retail segment includes company-operated convenience stores, Canadian dealers/jobbers, truckstop facilities, cardlock facilities, and home heating oil operations. The retail segment is segregated into two geographic regions. Our retail operations in eastern Canada are referred to as Retail – Canada. Our retail operations in the United States are referred to as Retail – U.S. The financial information about our segments in Note 20 of Notes to Consolidated Financial Statements is incorporated herein by reference.

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VALERO’S OPERATIONS

REFINING

On December 31, 2008, our refining operations included 16 refineries in the United States, Canada, and Aruba with a combined total throughput capacity of approximately 3.0 million barrels per day (BPD). The following table presents the locations of these refineries and their approximate feedstock throughput capacities as of December 31, 2008.

		Throughput Capacity(a)
Refinery	Location	(barrels per day)
Gulf Coast:
Corpus Christi(b)	Texas		315,000
Port Arthur	Texas		310,000
St. Charles	Louisiana		250,000
Texas City	Texas		245,000
Aruba	Aruba		235,000
Houston	Texas		145,000
Three Rivers	Texas		100,000
			1,600,000
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		235,000
Delaware City	Delaware		210,000
Paulsboro	New Jersey		185,000
			630,000
Total			2,990,000

(a)	“Throughput capacity” represents estimated capacity for processing crude oil, intermediates, and other feedstocks. Total estimated crude oil capacity is approximately 2.6 million BPD.
(b)	Represents the combined capacities of two refineries – the Corpus Christi East and Corpus Christi West Refineries.

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     Total Refining System

The following table presents the percentages of principal charges and yields (on a combined basis) for all of our refineries for the year ended December 31, 2008. Our total combined throughput volumes averaged 2,643,000 BPD for the 12 months ended December 31, 2008. (The information presented below includes the charges and yields of the Krotz Springs, Louisiana refinery, which we sold effective July 1, 2008. The sale is more fully described in Note 2 of Notes to Consolidated Financial Statements.)

Combined Refining Charges and Yields

		Percentage
Charges:
	sour crude oil		48	%
	acidic sweet crude oil		3	%
	sweet crude oil		23	%
	residual fuel oil		9	%
	other feedstocks		5	%
	blendstocks		12	%
Yields:
	gasolines and blendstocks		45	%
	distillates		35	%
	petrochemicals		3	%
	other products (includes vacuum gas oil, No. 6 fuel oil, petroleum coke, asphalt, and other)		17	%

     Gulf Coast

The following table presents the percentages of principal charges and yields (on a combined basis) for the eight refineries in this region for the year ended December 31, 2008. Total throughput volumes for the Gulf Coast refining region averaged 1,404,000 BPD for the 12 months ended December 31, 2008. (The information presented below includes the charges and yields of the Krotz Springs, Louisiana refinery, which we sold effective July 1, 2008.)

Combined Gulf Coast Region Charges and Yields

		Percentage
Charges:
	sour crude oil		57	%
	sweet crude oil		9	%
	residual fuel oil		13	%
	other feedstocks		7	%
	blendstocks		14	%
Yields:
	gasolines and blendstocks		41	%
	distillates		34	%
	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

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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 through crude oil pipelines, and has access to the Sunoco and Oiltanking terminals at Nederland, Texas. Finished products are distributed into the Colonial, Explorer, and TEPPCO pipelines, across the refinery docks into ships or barges, and through a local truck rack.

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 through the 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.

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 United States, the Caribbean, Europe, and South America.

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 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 medium sour crude oils into conventional gasoline, distillates, and aromatics. 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 with capacity of 120,000 BPD transports crude oil via connections to the Three Rivers Refinery from Corpus Christi. The refinery distributes its refined products primarily through pipelines owned by NuStar Energy L.P.

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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, 2008. Total throughput volumes for the West Coast refining region averaged approximately 276,000 BPD for the 12 months ended December 31, 2008.

Combined West Coast Region Charges and Yields

		Percentage
Charges:
	sour crude oil		68	%
	acidic sweet crude oil		4	%
	residual fuel oil		1	%
	other feedstocks		11	%
	blendstocks		16	%
Yields:
	gasolines and blendstocks		60	%
	distillates		25	%
	other products (includes vacuum gas oil, No. 6 fuel oil, petroleum coke, asphalt, and other)		15	%

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, 2008. Total throughput volumes for the Mid-Continent refining region averaged 423,000 BPD for the 12 months ended December 31, 2008.

Combined Mid-Continent Region Charges and Yields

		Percentage
Charges:
	sour crude oil		13	%
	sweet crude oil		79	%
	other feedstocks		1	%
	blendstocks		7	%
Yields:
	gasolines and blendstocks		49	%
	distillates		40	%
	petrochemicals		3	%
	other products (includes vacuum gas oil, No. 6 fuel oil, asphalt, and other)		8	%

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 south of Oklahoma City. It processes medium sour and light sweet crude oils into conventional gasoline, low-sulfur diesel, liquefied petroleum gas products, and asphalt. Local crude oil is gathered by TEPPCO’s crude oil gathering/trunkline systems and trucking operations, and then transported to the refinery through NuStar Energy L.P.’s crude oil pipeline systems. Foreign, midland, and other domestic crude oils are received via third-party pipelines. Refined products are transported via the Magellan pipeline system, 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, 2008. Total throughput volumes for the Northeast refining region averaged 540,000 BPD for the 12 months ended December 31, 2008.

Combined Northeast Region Charges and Yields

		Percentage
Charges:
	sour crude oil		40	%
	acidic sweet crude oil		11	%
	sweet crude oil		29	%
	residual fuel oil		7	%
	other feedstocks		4	%
	blendstocks		9	%
Yields:
	gasolines and blendstocks		43	%
	distillates		38	%
	petrochemicals		1	%
	other products (includes vacuum gas oil, No. 6 fuel oil, petroleum coke, asphalt, and other)		18	%

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, CBOB, RBOB, petroleum coke, sulfur, low-sulfur diesel, home heating oil, and petrochemicals (benzene). Feedstocks and refined products are transported via pipeline, barge, and truck-rack facilities. The refinery’s production is sold primarily in the northeastern U.S.

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, fuel oil, propane, and butane. 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 (into western Pennsylvania and Ohio), 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 65% of our current crude oil feedstock requirements are purchased through term contracts while the remaining requirements are generally purchased on the spot market. Our term supply agreements include arrangements to purchase feedstocks at market-related prices directly or indirectly from various foreign national oil companies (including feedstocks originating in the Middle East, Africa, Asia, Mexico, and South America) as well as international and domestic oil companies. The term contracts generally permit the parties to amend the contracts (or terminate them), effective as of the next scheduled renewal date, by giving the other party proper notice within a prescribed period of time (e.g., 60 days, 6 months) before expiration of the current term. The majority of the crude oil purchased under Valero’s term contracts is purchased at the producer’s official stated price (i.e., the “market” price established by the seller for all purchasers) and not at a negotiated price specific to Valero. About 80% of our crude oil feedstocks under term supply agreements 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 the 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 2008.

          Wholesale Marketing

We market branded and unbranded transportation fuels on a wholesale basis in 44 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 3,950 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.

          Bulk Sales and Trading

We sell a significant portion of our gasoline and distillate production through bulk sales channels in domestic and international markets. 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.

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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 provide access 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.

          Specialty Products

We also sell a variety of other products produced at our refineries, which we refer to collectively as “Specialty Products.” Our Specialty Products include asphalt, lube oils, natural gas liquids (NGLs), petroleum coke, petrochemicals, and sulfur.

• We produce asphalt at six of our refineries. Our asphalt products are sold for use in road construction, road repair, and roofing applications through a network of refinery and terminal loading racks.

• We produce lube oils at two of our refineries. We produce and market paraffinic, naphthenic, and aromatic oils suitable for use in a wide variety of lubricant and process applications.

• NGLs produced at our refineries include butane, isobutane, and propane. These products can be used for gasoline blending, home heating, and petrochemical plant feedstocks.

• We are a significant producer of petroleum coke, supplying primarily power generation customers and cement manufacturers. Petroleum coke is used largely as a substitute for coal.

• We produce and market a number of commodity petrochemicals including aromatic solvents (benzene, toluene, and xylene) and two grades of propylene. Aromatic solvents and propylenes are sold to customers in the chemical industry for further processing into such products as paints, plastics, and adhesives.

• We are a large producer of sulfur with sales primarily to customers in the agricultural sector. Sulfur is used in manufacturing fertilizer.

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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, 2008, total sales of refined products through Retail – U.S.’s retail sites averaged approximately 115,900 BPD. In addition to transportation fuels, our company-operated convenience stores sell snacks, candy, beer, fast foods, cigarettes, and fountain drinks. On December 31, 2008, we had 1,010 company-operated sites in Retail – U.S. (of which 79% were owned and 21% were leased). Our company-operated stores are operated primarily under the brand name Corner Store^®. Transportation fuels sold in our Retail – U.S. stores are sold primarily under 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, 2008, total retail sales of refined products through Retail – Canada averaged approximately 76,000 BPD. Transportation fuels are sold under the Ultramar^® brand through a network of 865 outlets throughout eastern Canada. On December 31, 2008, we owned or leased 412 retail stores in Retail – Canada and distributed gasoline to 453 dealers and independent jobbers. In addition, Retail – Canada operates 85 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 141,000 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 and global economic activity.

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, productivity and growth (or the lack thereof) of U.S. and global economies, 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.

Continued economic turmoil and hostilities, including the threat of future terrorist attacks, could affect the economies of the United States and other countries. Lower levels of economic activity during periods of recession could result in declines in energy consumption, including declines in the demand for and consumption of our refined products, which could cause our revenues and margins to decline and limit our future growth prospects.

Refining margins are also significantly impacted by additional refinery conversion capacity through the expansion of existing refineries or the construction of new refineries. Worldwide refining capacity expansions may result in refining production capability far exceeding refined product demand, which would have a significant adverse effect on refining margins.

A significant portion of our profitability is derived from the ability to purchase and process crude oil feedstocks that historically have been cheaper than benchmark crude oils, such as West Texas Intermediate crude oil. These crude oil feedstock differentials vary significantly depending on overall economic conditions and trends and conditions within the markets for crude oil and refined products, and they could decline in the future, which would have a negative impact on our earnings.

Uncertainty and illiquidity in credit and capital markets can impair our ability to obtain credit and financing on acceptable terms, and can adversely affect the financial strength of our business partners.

Our ability to obtain credit and capital depends in large measure on capital markets and liquidity factors over which we exert no control. Recent disruptions in the credit and capital markets and concerns about economic growth have had a significant adverse impact on global financial markets. Our ability to access credit and capital markets may be restricted at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. In addition, the cost and availability of debt and equity financing may be adversely impacted by unstable or illiquid market conditions. Protracted uncertainty and illiquidity in these markets also could have an adverse impact on our lenders, commodity hedging counterparties, or our customers, causing them to fail to meet their obligations to us. In addition, decreased returns on pension fund assets may also materially increase our pension funding requirements.

We currently maintain investment-grade ratings by Standard & Poor’s Ratings Services (S&P), Moody’s Investors Service (Moody’s), and Fitch Ratings (Fitch) on our senior unsecured debt. (Ratings from credit agencies are not recommendations to buy, sell, or hold our securities. Each rating should be evaluated independently of any other rating.) We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Specifically, if S&P, Moody’s,

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or Fitch were to downgrade our long-term rating, particularly below investment grade, our borrowing costs would increase, which could adversely affect our ability to attract potential investors and our funding sources could decrease. In addition, we may not be able to obtain favorable credit terms from our suppliers or they may require us to provide collateral, letters of credit, or other forms of security which would increase our operating costs. As a result, a downgrade in our credit ratings could have a material adverse impact on our future operations and financial position.

From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we were unable to obtain necessary funds from financing activities. From time to time, we may need to supplement our cash generation with proceeds from financing activities. We have existing revolving credit facilities, committed letter of credit facilities, and an accounts receivable sales facility to provide us with available financing to meet our ongoing cash needs. Uncertainty and illiquidity continues to exist in the financial markets that may materially impact the ability of the participating financial institutions to fund their commitments to us under our various financing facilities. In light of these uncertainties and the volatile current market environment, we can make no assurances that we will be able to obtain the full amount of the funds available under our financing facilities to satisfy our cash requirements. Our failure to do so could have a material adverse effect on our operations and financial position.

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, material changes in operations, 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 the Middle East, Africa, Asia, North America, and South America. 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.

In addition, the U.S. government can prevent or restrict us from doing business in or with foreign countries. These restrictions, and those of foreign governments, could limit our ability to gain access to business opportunities in various countries. Actions by both the United States and foreign countries have affected our operations in the past and will continue to do so in the future.

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Competitors that produce their own supply of feedstocks, have more extensive retail outlets, or have greater financial resources may have a competitive advantage.

The refining and marketing industry is highly competitive with respect to both feedstock supply and refined product markets. We compete with 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.

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, encounter work stoppages relating to organized labor issues, 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. A significant interruption in one or more of our refineries could also lead to increased volatility in prices for crude oil feedstocks and refined products, and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain insurance coverage that we consider adequate.

We maintain insurance against many, but not all, potential losses arising from operating hazards. Failure by one or more insurers to honor its coverage commitments for an insured event could materially and adversely affect our future cash flows, operating results, and financial condition.

Our refining and marketing operations are subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards, and natural catastrophes. As protection against these hazards, we maintain insurance coverage against some, but not all, such potential losses and liabilities. 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, coverage for hurricane damage is very limited, and coverage for terrorism risks includes very broad exclusions. 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.

Our insurance program includes a number of insurance carriers. Disruptions in the U.S. financial markets have resulted in the deterioration in the financial condition of many financial institutions, including insurance companies. We are not currently aware of any information that would indicate that any of our insurers is unlikely to perform in the event of a covered incident. However, in light of this uncertainty and the volatile current market environment, we can make no assurances that we will be able to obtain the full amount of our insurance coverage for insured events.

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Compliance with and changes in tax laws could adversely affect our performance.

We are subject to extensive tax liabilities, including United States, 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 and Supplementary Data” in Note 24 of Notes to Consolidated Financial Statements under the caption “Environmental Matters.”

Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2008, our capital expenditures attributable to compliance with environmental regulations were approximately $480 million, and are currently estimated to be approximately $635 million for 2009 and approximately $830 million for 2010. The estimates for 2009 and 2010 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, 2008, we were the lessee under a number of cancelable and non-cancelable leases for certain properties. Our leases are discussed more fully in Note 23 of Notes to Consolidated Financial Statements.

Our patents relating to our refining operations are not material to us as a whole. The trademarks and tradenames under which we conduct our retail and branded wholesale business – including Valero^®, Diamond Shamrock^®, Shamrock^®, Ultramar^®, Beacon^®, Corner Store^®, and Stop N Go^® – and other trademarks employed in the marketing of petroleum products are integral to our wholesale and retail marketing operations.

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EXECUTIVE OFFICERS OF THE REGISTRANT

Name	Age*		Positions Held with Valero	Officer Since
William R. Klesse		62	Chief Executive Officer, President, and Chairman of the Board		2001
Kimberly S. Bowers		44	Executive Vice President and General Counsel		2003
Michael S. Ciskowski		51	Executive Vice President and Chief Financial Officer		1998
S. Eugene Edwards		52	Executive Vice President-Corporate Development and Strategic Planning		1998
Joseph W. Gorder		51	Executive Vice President-Marketing and Supply		2003
Richard J. Marcogliese		56	Executive Vice President and Chief Operating Officer		2001

* on January 31, 2009

Mr. Klessewas elected as Valero’s Chairman of the Board in January 2007, and as Chief Executive Officer on December 31, 2005. He added the title of President in January 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.

Ms. Bowerswas elected Executive Vice President and General Counsel in October 2008. She previously served as Senior Vice President and General Counsel of the Company since April 2006. Before that, she was Valero’s Vice President-Legal Services from 2003 to 2006. Ms. Bowers joined Valero’s legal department in 1997.

Mr. Ciskowskiwas elected Executive Vice President and Chief Financial Officer in August 2003. Before that, he served as Executive Vice President-Corporate Development since April 2003, and Senior Vice President in charge of business and corporate development since 2001.

Mr. Edwardswas elected Executive Vice President-Corporate Development and Strategic Planning in December 2005. He previously 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. Gorderwas elected Executive Vice President-Marketing and Supply in December 2005. He 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. Marcogliesewas elected Executive Vice President and Chief Operating Officer in October 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 25 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.

Bay Area Air Quality Management District (BAAQMD)(Benicia Refinery). From 2006 to 2008, the BAAQMD issued 86 violation notices (VNs) for various alleged air regulation and air permit violations at our Benicia Refinery and asphalt plant. No penalties have been specified in these VNs. We are pursuing settlement of all VNs.

Delaware Department of Natural Resources and Environmental Control (DDNREC)(Delaware City Refinery). Our Delaware City Refinery is subject to 12 outstanding notices of violation (NOVs) issued by the DDNREC. Ten of the NOVs allege unauthorized air emission events at the refinery. Two NOVs allege solid waste violations. No penalties have been specified in these NOVs. We are pursuing settlement of these NOVs.

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). In 2008, the NJDEP issued three air-related Administrative Order and Notice of Civil Administrative Penalty Assessments (Notices) to our Paulsboro Refinery that we reasonably believe may result in monetary sanctions of $100,000 or more. The Notices allege the refinery’s failure to comply with a number of air permit and regulatory requirements. The Notices propose penalties of approximately $780,000 in the aggregate. We are pursuing settlement of these Notices with the NJDEP.

Oklahoma Department of Environmental Quality (ODEQ)(Ardmore Refinery). We have received a penalty demand of $385,839 from the ODEQ for alleged excess air emission violations at our Ardmore Refinery occurring from 2006 to 2008. We are in settlement discussions with the ODEQ to resolve this matter.

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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 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 November 2008, the SCAQMD issued an NOV for alleged air regulation and air permit violations related to a September 2008 flaring event at our Wilmington Refinery. We are pursuing settlement of the NOV.

State of Ohio, Office of the Attorney General, Environmental Enforcement(The Premcor Refining Group Inc. former Clark Retail Enterprises, Inc. retail sites). In June 2008, the Attorney General’s office of the State of Ohio issued a penalty demand of $11,133,000 to our wholly owned subsidiary, The Premcor Refining Group Inc., for alleged environmental violations arising from a predecessor’s operation or ownership of underground storage tanks at several sites. We are in settlement discussions with the Ohio Attorney General to resolve this matter.

Texas Commission on Environmental Quality (TCEQ)(McKee Refinery). In March 2008, we received a proposed Agreed Order from the TCEQ for $101,386 to resolve nine alleged violations of 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. We recently reached a tentative agreement with the Texas Attorney General’s office to resolve this matter.

TCEQ(Texas City Refinery). In January 2008, we received a proposed Agreed Order from the TCEQ for $181,200 relating to an open valve and associated flaring at the Texas City Refinery. We agreed to the terms of the order, which was adopted by the TCEQ in February 2009, thus resolving this matter.

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, 2009, there were 6,927 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 2008 and 2007.

	Sales Prices of the				Dividends
	Common Stock				Per
Quarter Ended	High		Low		Common Share
2008:
December 31	$	30.36	$	13.94	$	0.15
September 30		40.74		28.20		0.15
June 30		55.00		39.20		0.15
March 31		71.12		44.94		0.12
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

On January 20, 2009, our board of directors declared a quarterly cash dividend of $0.15 per common share payable March 11, 2009 to holders of record at the close of business on February 11, 2009.

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 2008.

Period	Total		Average		Total Number of		Total Number of		Approximate Dollar
	Number of		Price		Shares Not		Shares Purchased		Value of Shares that
	Shares		Paid per		Purchased as Part		as Part of		May Yet Be Purchased
	Purchased		Share		of Publicly		Publicly		Under the Plans or
					Announced Plans		Announced Plans		Programs (2)
					or Programs (1)		or Programs
October 2008		8,366,493	$	21.62		446,928		7,919,565	$ 3.46 billion
November 2008		20,526	$	19.61		20,526		–	$ 3.46 billion
December 2008		507	$	17.52		507		–	$ 3.46 billion
Total		8,387,526	$	21.61		467,961		7,919,565	$ 3.46 billion

(1)

The shares reported in this column represent purchases settled in the fourth quarter of 2008 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. On February 28, 2008, we announced that our board of directors approved a new $3 billion common stock purchase program. This program is in addition to the $6 billion program. This new $3 billion program has no expiration date. Our stock purchase programs are 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.

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.

This Performance Graph and the related textual information are based on historical data and are not indicative of future performance.

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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, 2003 and ending December 31, 2008. The New Peer Group consists of the following 13 companies that are engaged in domestic refining operations: Alon USA Energy, Inc., Chevron Corporation, ConocoPhillips, CVR Energy, Inc., Exxon Mobil Corporation, Frontier Oil Corporation, Hess Corporation, Holly Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Sunoco, Inc., Tesoro Corporation, and Western Refining, Inc. The Old Peer Group consisted of the following ten companies: 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. The New Peer Group serves as an update to our Old Peer Group by including additional domestic independent refiners (Alon USA Energy, Inc., CVR Energy, Inc., Holly Corporation, and Western Refining, Inc.) and removing one energy company that does not conduct domestic refining operations (Occidental Petroleum Corporation).

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN*

Among Valero Energy Corporation, The S&P 500 Index,
A New Peer Group and an Old Peer Group

	12/2003		12/2004		12/2005		12/2006		12/2007		12/2008
Valero Common Stock	$	100	$	197.64	$	451.53	$	450.06	$	620.65	$	195.21
S&P 500		100		110.88		116.33		134.70		142.10		89.53
New Peer Group		100		128.93		152.64		205.69		263.27		202.99
Old Peer Group		100		129.30		153.99		206.52		268.02		207.99

* Assumes that an investment in Valero common stock and each index was $100 on December 31, 2003. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from December 31, 2003 through December 31, 2008.

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ITEM 6. SELECTED FINANCIAL DATA

The selected financial data for the five-year period ended December 31, 2008 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,
	2008 (a)			2007 (a) (b)		2006 (a) (b)		2005 (a) (b) (c)		2004 (a) (d)
Operating revenues (e)	$	119,114		$	95,327	$	87,640	$	80,616	$	54,589
Operating income		563			6,918		7,722		5,268		2,979
Income (loss) from continuing operations		(1,131	)		4,565		5,287		3,473		1,804
Earnings (loss) per common share from continuing operations – assuming dilution		(2.16	)		7.72		8.36		5.90		3.27
Dividends per common share		0.57			0.48		0.30		0.19		0.145
Property, plant and equipment, net		23,213			21,560		20,032		17,266		10,234
Goodwill		–			4,019		4,061		4,792		2,388
Total assets		34,417			42,722		37,753		32,798		19,392
Debt and capital lease obligations (less current portion)		6,264			6,470		4,619		5,156		3,901
Stockholders’ equity		15,620			18,507		18,605		15,050		7,798

(a)	Effective July 1, 2008, we sold our Krotz Springs Refinery to Alon Refining Krotz Springs, Inc. 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, 2007, 2006, 2005, and 2004, and as a result, certain balance sheet amounts reflected herein have been reclassified.
(b)	Effective July 1, 2007, we sold our Lima Refinery to Husky Refining Company. 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.
(c)	Includes the operations related to the Premcor Acquisition beginning September 1, 2005.
(d)	Includes the operations related to the acquisition of the Aruba Refinery and related businesses beginning March 5, 2004.
(e)	Operating revenues reported for 2005 and 2004 include approximately $7.8 billion and $4.9 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;

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• refinery overcapacity or undercapacity;

• the actions taken by competitors, including both pricing and adjustments to 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;

• overall economic conditions, including the stability and liquidity of financial markets; and

• other factors generally described in the “Risk Factors” section included in “Items 1., 1A. & 2. – Business, Risk Factors and Properties” in this report.

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.

25

OVERVIEW

In this overview, we describe some of the primary factors that we believe affected our results of operations during the year ended December 31, 2008. We reported a loss from continuing operations of $1.1 billion, or $2.16 per share, for the year ended December 31, 2008 compared to income from continuing operations of $4.6 billion, or $7.72 per share, for the year ended December 31, 2007. The 2008 results included a charge in the fourth quarter of 2008 of $4.1 billion ($4.0 billion after tax) resulting from the impairment of goodwill.

The goodwill impairment loss, which represented a write-off of the entire balance of our goodwill, was associated with a significant decline in our market capitalization in the fourth quarter of 2008 that resulted in large part from severe disruptions in the capital and commodities markets. In performing our goodwill impairment test under applicable accounting rules, we estimate fair value by discounting the estimated future cash flows from our refineries. The decline in our market capitalization during the fourth quarter of 2008 resulted in the use of higher, risk-adjusted discount rates in determining the fair values of our reporting units, which reflected the significant risk premium implied by our stock price as of December 31, 2008. As a result of applying these higher discount rates to the cash flows of our reporting units, the fair values in each of our reporting units were below their net book values including goodwill, thus indicating potential impairment. Due to this conclusion of potential impairment, existing accounting rules required additional analysis for each of the reporting units to determine the amount of the loss, and this additional analysis indicated that all of the goodwill in each of our reporting units should be written off.

Effective July 1, 2008, we sold our refinery in Krotz Springs, Louisiana to a subsidiary of Alon USA Energy, Inc. The sale resulted in a pre-tax gain of $305 million, or $170 million after tax, as discussed in Note 2 of Notes to Consolidated Financial Statements. Net cash proceeds from the sale were $463 million, including approximately $135 million from the sale of working capital. In addition, we received contingent consideration in the form of a three-year earn-out agreement based on certain product margins.

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.” The weakening of industry fundamentals for refined products that we experienced in the fourth quarter of 2007 continued throughout 2008. Gasoline margins declined significantly in all of our refining regions in 2008 compared to 2007. The decline in margins was primarily due to a decrease in gasoline demand and an increase in ethanol production. Margins on certain secondary refined products, such as petroleum coke and petrochemical feedstocks, also declined during 2008 due to a significant increase in the cost of crude oil and other feedstocks used to produce them. However, these decreases were partially offset by the effect of favorable diesel margins in 2008, which increased compared to 2007 primarily due to strong global demand.

Because more than 65% of our total crude oil throughput consists of sour crude oil and acidic sweet crude oil feedstocks that historically have been purchased at prices less than sweet crude oil, our profitability is also significantly affected by the spread between sweet crude oil and sour crude oil prices, referred to as the “sour crude oil differential.” During 2008, sour crude oil differentials remained wide and improved somewhat in 2008 compared to 2007 levels.

Regarding operations, on January 25, 2008, our Aruba Refinery was shut down due to a fire in its vacuum unit. We resumed partial operation of the refinery in mid-February, and during the second quarter of 2008 we completed the repairs and resumed full operations of the refinery. During the third quarter of 2008, certain of our refineries were shut down as a result of two hurricanes that impacted the Gulf Coast.

26

Although we avoided major damage from the hurricanes, repair costs and downtime attributable to the hurricanes and the Aruba downtime reduced our results of operations for 2008.

During the year ended December 31, 2008, we increased our quarterly common stock dividend from $0.12 per share to $0.15 per share and purchased 23.0 million shares of our common stock under our board-authorized programs, which represented more than 4% of our shares outstanding at the beginning of 2008. We also redeemed $350 million of 9.5% callable debt that was due in 2013 and invested $3.2 billion in capital expenditures and deferred turnaround and catalyst costs.

27

RESULTS OF OPERATIONS

2008 Compared to 2007

Financial Highlights
(millions of dollars, except per share amounts)

	Year Ended December 31,
	2008			2007 (a)			Change
Operating revenues	$	119,114		$	95,327		$	23,787
Costs and expenses:
Cost of sales		107,429			81,645			25,784
Refining operating expenses		4,555			4,016			539
Retail selling expenses		768			750			18
General and administrative expenses		559			638			(79	)
Depreciation and amortization expense:
Refining		1,327			1,222			105
Retail		105			90			15
Corporate		44			48			(4	)
Gain on sale of Krotz Springs Refinery		(305	)		–			(305	)
Goodwill impairment loss (b)		4,069			–			4,069
Total costs and expenses		118,551			88,409			30,142
Operating income		563			6,918			(6,355	)
Other income, net		113			167			(54	)
Interest and debt expense:
Incurred		(451	)		(466	)		15
Capitalized		111			107			4
Income from continuing operations before income tax expense		336			6,726			(6,390	)
Income tax expense		1,467			2,161			(694	)
Income (loss) from continuing operations		(1,131	)		4,565			(5,696	)
Income from discontinued operations, net of income tax expense (a)		–			669			(669	)
Net income (loss)	$	(1,131	)	$	5,234		$	(6,365	)
Earnings (loss) per common share – assuming dilution:
Continuing operations	$	(2.16	)	$	7.72		$	(9.88	)
Discontinued operations		–			1.16			(1.16	)
Total	$	(2.16	)	$	8.88		$	(11.04	)

See the footnote references on page 31. 

28

Operating Highlights
(millions of dollars, except per barrel and per gallon amounts)

	Year Ended December 31,
	2008			2007			Change
Refining (a):
Operating income (b)	$	797		$	7,355		$	(6,558	)
Throughput margin per barrel (c)	$	10.79		$	12.33		$	(1.54	)
Operating costs per barrel:
Refining operating expenses	$	4.71		$	3.93		$	0.78
Depreciation and amortization		1.37			1.20			0.17
Total operating costs per barrel	$	6.08		$	5.13		$	0.95
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		592			638			(46	)
Medium/light sour crude		673			635			38
Acidic sweet crude		79			80			(1	)
Sweet crude		606			724			(118	)
Residuals		228			247			(19	)
Other feedstocks		149			173			(24	)
Total feedstocks		2,327			2,497			(170	)
Blendstocks and other		316			301			15
Total throughput volumes		2,643			2,798			(155	)
Yields (thousand barrels per day):
Gasolines and blendstocks		1,187			1,285			(98	)
Distillates		915			919			(4	)
Petrochemicals		71			82			(11	)
Other products (d)		463			507			(44	)
Total yields		2,636			2,793			(157	)
Retail – U.S.:
Operating income	$	260		$	154		$	106
Company-operated fuel sites (average)		973			957			16
Fuel volumes (gallons per day per site)		5,000			4,979			21
Fuel margin per gallon	$	0.229		$	0.174		$	0.055
Merchandise sales	$	1,097		$	1,024		$	73
Merchandise margin (percentage of sales)		29.9	%		29.7	%		0.2	%
Margin on miscellaneous sales	$	99		$	101		$	(2	)
Retail selling expenses	$	505		$	494		$	11
Depreciation and amortization expense	$	70		$	59		$	11
Retail – Canada:
Operating income	$	109		$	95		$	14
Fuel volumes (thousand gallons per day)		3,193			3,234			(41	)
Fuel margin per gallon	$	0.268		$	0.248		$	0.020
Merchandise sales	$	200		$	187		$	13
Merchandise margin (percentage of sales)		28.5	%		27.8	%		0.7	%
Margin on miscellaneous sales	$	36		$	37		$	(1	)
Retail selling expenses	$	263		$	256		$	7
Depreciation and amortization expense	$	35		$	31		$	4

See the footnote references on page 31. 

29

Refining Operating Highlights by Region (e)
(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2008			2007		Change
Gulf Coast:
Operating income	$	3,191		$	4,505	$	(1,314	)
Throughput volumes (thousand barrels per day)		1,404			1,537		(133	)
Throughput margin per barrel (c)	$	11.57		$	12.81	$	(1.24	)
Operating costs per barrel:
Refining operating expenses	$	4.65		$	3.70	$	0.95
Depreciation and amortization		1.30			1.08		0.22
Total operating costs per barrel	$	5.95		$	4.78	$	1.17
Mid-Continent (a):
Operating income	$	577		$	910	$	(333	)
Throughput volumes (thousand barrels per day)		423			402		21
Throughput margin per barrel (c)	$	9.27		$	11.66	$	(2.39	)
Operating costs per barrel:
Refining operating expenses	$	4.26		$	4.13	$	0.13
Depreciation and amortization		1.29			1.33		(0.04	)
Total operating costs per barrel	$	5.55		$	5.46	$	0.09
Northeast:
Operating income	$	724		$	1,084	$	(360	)
Throughput volumes (thousand barrels per day)		540			570		(30	)
Throughput margin per barrel (c)	$	9.95		$	10.46	$	(0.51	)
Operating costs per barrel:
Refining operating expenses	$	4.88		$	3.98	$	0.90
Depreciation and amortization		1.40			1.27		0.13
Total operating costs per barrel	$	6.28		$	5.25	$	1.03
West Coast:
Operating income	$	374		$	856	$	(482	)
Throughput volumes (thousand barrels per day)		276			289		(13	)
Throughput margin per barrel (c)	$	10.84		$	14.41	$	(3.57	)
Operating costs per barrel:
Refining operating expenses	$	5.37		$	4.82	$	0.55
Depreciation and amortization		1.77			1.49		0.28
Total operating costs per barrel	$	7.14		$	6.31	$	0.83
Operating income for regions above	$	4,866		$	7,355	$	(2,489	)
Goodwill impairment loss (b)		(4,069	)		–		(4,069	)
Total refining operating income	$	797		$	7,355	$	(6,558	)

See the footnote references on page 31. 

30

Average Market Reference Prices and Differentials (f)
(dollars per barrel)

	Year Ended December 31,
	2008			2007		Change
Feedstocks:
West Texas Intermediate (WTI) crude oil	$	99.56		$	72.27	$	27.29
WTI less sour crude oil at U.S. Gulf Coast (g)		5.20			4.95		0.25
WTI less Mars crude oil		6.13			5.61		0.52
WTI less Alaska North Slope (ANS) crude oil		1.22			0.58		0.64
WTI less Maya crude oil		15.71			12.41		3.30
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		4.85			13.78		(8.93	)
No. 2 fuel oil less WTI		18.35			11.94		6.41
Ultra-low-sulfur diesel less WTI		22.96			17.76		5.20
Propylene less WTI		(3.69	)		11.05		(14.74	)
U.S. Mid-Continent:				��
Conventional 87 gasoline less WTI		4.46			18.02		(13.56	)
Low-sulfur diesel less WTI		24.12			21.30		2.82
U.S. Northeast:
Conventional 87 gasoline less WTI		3.22			13.98		(10.76	)
No. 2 fuel oil less WTI		20.23			12.96		7.27
Lube oils less WTI		68.79			48.29		20.50
U.S. West Coast:
CARBOB 87 gasoline less ANS		11.15			23.80		(12.65	)
CARB diesel less ANS		23.81			22.66		1.15

The following notes relate to references on pages 28 through 31.
(a)	Effective July 1, 2007, we sold our Lima Refinery to Husky Refining Company (Husky). Therefore, the results of operations of the Lima Refinery for the six months of 2007 prior to its sale, as well as the gain on the sale of the refinery, are reported as discontinued operations, and all refining operating highlights, both consolidated and for the Mid-Continent region, exclude the Lima Refinery. The sale resulted in a pre-tax gain of $827 million ($426 million after tax), which is included in “Income from discontinued operations, net of income tax expense” for the year ended December 31, 2007.
(b)	Upon applying the goodwill impairment testing criteria under existing accounting rules during the fourth quarter of 2008, we determined that the goodwill in all four of our reporting units was impaired, which resulted in a goodwill impairment loss of $4.1 billion ($4.0 billion after tax). This goodwill impairment loss is included in the refining segment operating income but is excluded from the consolidated and regional throughput margins per barrel and the regional operating income amounts presented for the year ended December 31, 2008 in order to make that information comparable between periods.
(c)	Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.
(d)	Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
(e)	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 (for periods prior to its sale effective July 1, 2008), 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.
(f)	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.
(g)	The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.

31

General

Operating revenues increased 25% for the year ended December 31, 2008 compared to the year ended December 31, 2007 primarily as a result of higher average refined product prices. Refined product prices were significantly higher in the first nine months of 2008 compared to the same period of 2007, but fourth quarter 2008 refined product prices declined to levels substantially below the fourth quarter of 2007. This resulted in a $10.1 billion decrease in fourth quarter 2008 revenues compared to 2007, which lowered the revenue increase for the year to $23.8 billion. Offsetting the higher revenues were substantially higher average feedstock costs.

Operating income decreased $6.4 billion, or 92%, and income from continuing operations decreased $5.7 billion for the year ended December 31, 2008 compared to the year ended December 31, 2007 primarily due to a $6.6 billion decrease in refining segment operating income. The decrease was primarily due to a goodwill impairment loss of $4.1 billion recorded in the fourth quarter of 2008 as discussed in Note 8 of Notes to Consolidated Financial Statements. Also, see “Impairment of Assets” under “Critical Accounting Policies Involving Critical Accounting Estimates” below for a detailed analysis of the methodology and assumptions used in the determination of this goodwill impairment loss. The goodwill impairment loss is included in the refining segment operating income but is excluded from the consolidated and regional throughput margins per barrel and regional operating income amounts for the year ended December 31, 2008 for comparability purposes. The refining segment operating income and income from continuing operations for the year ended December 31, 2007 exclude the operations of the Lima Refinery and the gain on its sale, which are classified as discontinued operations due to our sale of that refinery effective July 1, 2007 as discussed in Note 2 of Notes to Consolidated Financial Statements.

Refining

Operating income for our refining segment decreased from $7.4 billion for the year ended December 31, 2007 to $797 million for the year ended December 31, 2008, resulting mainly from the $4.1 billion goodwill impairment loss discussed above, a 12% decrease in throughput margin per barrel, a 12% increase in refining operating expenses (including depreciation and amortization expense), and a 6% decline in throughput volumes. These decreases were partially offset by a $305 million gain on the sale of our Krotz Springs Refinery effective July 1, 2008, which is discussed in Note 2 of Notes to Consolidated Financial Statements.

Total refining throughput margins for 2008 compared to 2007 were impacted by the following factors:

• Distillate margins in 2008 increased in all of our refining regions from the margins in 2007. The increase in distillate margins was primarily due to strong global demand.

• Gasoline margins decreased significantly in all of our refining regions in 2008 compared to the margins in 2007. The decline in gasoline margins was primarily due to a decrease in gasoline demand and an increase in ethanol production.

• Margins on various secondary refined products such as asphalt, fuel oils, propylene, and petroleum coke declined from 2007 to 2008 as prices for these products did not increase in proportion to the large increase in the costs of the feedstocks used to produce them.

• Sour crude oil feedstock differentials to WTI crude oil in 2008 remained favorable and were wider than the differentials in 2007. These favorable differentials were 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.

• Throughput volumes decreased 155,000 barrels per day during 2008 compared to 2007 primarily due to a fire in the vacuum unit at our Aruba Refinery in January of 2008, downtime for

32

maintenance at our Port Arthur and Delaware City Refineries, unplanned downtime at our Port Arthur, Texas City, St. Charles, and Houston Refineries related to Hurricanes Ike and Gustav, the sale of our Krotz Springs Refinery, and economic decisions to reduce throughputs in certain of our refineries as a result of unfavorable market fundamentals, partially offset by the 2007 shutdown of our McKee Refinery discussed in Note 23 of Notes to Consolidated Financial Statements.

•

Throughput margin in 2008 included approximately $100 million related to the McKee Refinery business interruption settlement discussed in Note 23 of Notes to Consolidated Financial Statements.

Refining operating expenses, excluding depreciation and amortization expense, increased $0.78 per barrel, or 20%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. Per-barrel operating expenses increased mainly due to an increase in energy costs, as well as the effect of the throughput volume decline discussed above. Refining depreciation and amortization expense increased 9% from 2007 to 2008 primarily due to the implementation of new capital projects and increased turnaround and catalyst amortization.

Retail

Retail operating income was $369 million for the year ended December 31, 2008 compared to $249 million for the year ended December 31, 2007. This 48% increase in operating income was primarily attributable to a $0.055 per gallon increase in retail fuel margins and increased in-store sales in our U.S. retail operations. The significant improvement in fuel margins was largely the result of rapidly declining crude oil prices in the second half of 2008.

Corporate Expenses and Other

General and administrative expenses, including corporate depreciation and amortization expense, decreased $83 million for the year ended December 31, 2008 compared to the year ended December 31, 2007. This decrease was primarily due to lower variable incentive compensation expenses combined with the nonrecurrence of 2007 expenses related to executive retirement costs and a $13 million termination fee paid for the cancellation of our services agreement with NuStar Energy L.P.

“Other income, net” decreased for the year ended December 31, 2008 compared to the year ended December 31, 2007 primarily due to a $91 million foreign currency exchange rate gain in 2007 resulting from the repayment of a loan by a foreign subsidiary, reduced interest income resulting from lower cash balances and interest rates, and a reduction in the fair value of certain nonqualified benefit plan assets. These decreases were partially offset by income related to the Alon earn-out agreement discussed in Notes 2 and 17 of Notes to Consolidated Financial Statements, lower costs incurred under our accounts receivable sales program, an increase in earnings from our equity investment in Cameron Highway Oil Pipeline Company, and a $14 million gain in 2008 on the redemption of our 9.5% senior notes as discussed in Note 12 of Notes to Consolidated Financial Statements.

Interest and debt expense decreased primarily due to reduced interest on tax liabilities, partially offset by higher average debt balances.

Income tax expense decreased $694 million from 2007 to 2008 mainly as a result of lower operating income, excluding the effect on operating income of the $4.1 billion goodwill impairment loss discussed above that has an insignificant tax effect. Excluding this goodwill impairment loss, our effective tax rate for the year ended December 31, 2008 was comparable to the effective tax rate for the year ended December 31, 2007.

33

Income from discontinued operations for the year ended December 31, 2007 represents a $426 million after-tax gain on the sale of the Lima Refinery effective July 1, 2007 and net income from its operations prior to the sale.

34

2007 Compared to 2006

Financial Highlights
(millions of dollars, except per share amounts)

	Year Ended December 31,
	2007 (a)			2006 (a)			Change
Operating revenues	$	95,327		$	87,640		$	7,687
Costs and expenses:
Cost of sales		81,645			73,863			7,782
Refining operating expenses		4,016			3,622			394
Retail selling expenses		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. (b)		–			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 (b)		–			(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 38.

35

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 (c)	$	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 (d)		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	$	101		$	85		$	16
Retail selling expenses	$	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 38.

36

Refining Operating Highlights by Region (e)
(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 (c)	$	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 (c)	$	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 (c)	$	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 (c)	$	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 38.

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Average Market Reference Prices and Differentials (f)
(dollars per barrel)

	Year Ended December 31,
	2007		2006		Change
Feedstocks:
WTI crude oil	$	72.27	$	66.00	$	6.27
WTI less sour crude oil at U.S. Gulf Coast (g)		4.95		7.01		(2.06	)
WTI less Mars crude oil		5.61		7.12		(1.51	)
WTI less 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 (h)		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 35 through 38.
(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)	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.
(c)	Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.
(d)	Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
(e)	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.
(f)	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.
(g)	The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.
(h)	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 compared to 2006 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.

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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 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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OUTLOOK

Based on current forward market indicators, we expect both refined product margins and sour crude oil differentials for 2009 to be lower than the corresponding amounts reported in 2008. We expect the current economic slowdown to unfavorably impact demand for refined products. Although gasoline margins in the first quarter of 2009 have recovered somewhat from the negative margins experienced in late 2008, gasoline margins are expected to remain under pressure until demand begins to recover. Distillate margins are also expected to be unfavorably affected by reduced demand attributable to the current economic recession. We believe that distillate margins will continue to depend primarily on the pace of global economic activity and the rate at which new refining capacity is brought online.

In regard to feedstocks, thus far in 2009, sour crude oil differentials have decreased from fourth quarter 2008 levels and are expected to remain lower for the first half of 2009. Reduced overall crude oil production by OPEC has caused a reduction in the supply of sour crude oil and a resulting increase in the price of such crude oils relative to sweet crude oils. In light of the current and expanding weakness in the U.S. and global economies, we expect 2009 will be a challenging year for the refining industry and our company.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Year Ended December 31, 2008
Net cash provided by operating activities for the year ended December 31, 2008 was $3.0 billion compared to $5.3 billion for the year ended December 31, 2007. The decrease in cash generated from operating activities was due primarily to the decrease in operating income discussed above under “Results of Operations,” after excluding the effect of the goodwill impairment loss included in the 2008 operating income that had no effect on cash. Changes in cash provided by or used for working capital during the years ended December 31, 2008 and 2007 are shown in Note 16 of Notes to Consolidated Financial Statements. Both receivables and accounts payable decreased in 2008 due to a significant decrease in crude oil and refined product prices at December 31, 2008 compared to such prices at the end of 2007. Receivables for 2008 also decreased due to the termination in the first quarter of 2008 of certain agreements related to the sale of the Lima Refinery to Husky and the timing of receivable collections at year-end 2007. The change in working capital for 2007 includes a $900 million decrease in the eligible trade receivables sold under our accounts receivable sales facility as discussed below in the discussion of 2007 versus 2006 cash flows.

See the 2007 cash flow discussion below for information related to the cash flows of the discontinued operations of the Lima Refinery.

The net cash generated from operating activities during the year ended December 31, 2008, combined with $1.5 billion of available cash on hand and $463 million of proceeds from the sale of our Krotz Springs Refinery, were used mainly to:

• fund $3.2 billion of capital expenditures and deferred turnaround and catalyst costs;

• make an early redemption of our 9.5% senior notes for $367 million and scheduled debt repayments of $7 million;

• purchase 23.0 million shares of our common stock at a cost of $955 million;

• fund a $25 million contingent earn-out payment in connection with the acquisition of the St. Charles Refinery, an $87 million acquisition of retail fuel sites, and a $57 million acquisition primarily of an interest in a refined product pipeline; and

• pay common stock dividends of $299 million.

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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 $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 debt redemption of $183 million and scheduled debt repayments of $280 million;

• fund capital contributions, net of distributions, of $209 million to the Cameron Highway Oil Pipeline Company 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.

Capital Investments
During the year ended December 31, 2008, we expended $2.8 billion for capital expenditures and $408 million for deferred turnaround and catalyst costs. Capital expenditures for the year ended December 31, 2008 included $479 million of costs related to environmental projects.

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 23 of Notes to Consolidated Financial Statements). Payments due under this earn-out arrangement were limited based on annual and aggregate limits. 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. Subsequent to this payment, we have no further commitments with respect to contingent earn-out agreements.

For 2009, we expect to incur approximately $2.7 billion for capital investments, including approximately $2.2 billion for capital expenditures (approximately $635 million of which is for environmental projects) and approximately $490 million for deferred turnaround and catalyst costs. The capital expenditure

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estimate excludes anticipated expenditures related to strategic acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.

Krotz Springs Refinery Disposition
Effective July 1, 2008, we consummated the sale of our Krotz Springs Refinery to Alon Refining Krotz Springs, Inc. (Alon), a subsidiary of Alon USA Energy, Inc. The sale resulted in a pre-tax gain of $305 million, or $170 million after tax. Cash proceeds, net of certain costs related to the sale, were $463 million, including approximately $135 million from the sale of working capital to Alon primarily related to the sale of inventory by our marketing and supply subsidiary. In addition to the cash consideration received, we also received contingent consideration in the form of a three-year earn-out agreement based on certain product margins, which had a fair value of $171 million as of July 1, 2008. We have hedged the risk of a decline in the referenced product margins by entering into certain commodity derivative contracts. In addition, we entered into various agreements with Alon as further described in Note 2 of Notes to Consolidated Financial Statements.

Contractual Obligations
Our contractual obligations as of December 31, 2008 are summarized below (in millions).

	Payments Due by Period
	2009		2010		2011		2012		2013		Thereafter		Total
Debt and capital lease obligations	$	315	$	39	$	424	$	765	$	495	$	4,619	$	6,657
Operating lease obligations		397		272		174		84		51		257		1,235
Purchase obligations		12,812		2,507		1,589		1,208		623		1,752		20,491
Other long-term liabilities		–		163		150		150		149		1,549		2,161
Total	$	13,524	$	2,981	$	2,337	$	2,207	$	1,318	$	8,177	$	30,544

Debt and Capital Lease Obligations
Payments for debt and capital lease obligations in the table above reflect stated values and minimum rental payments, respectively.

On February 1, 2008, we redeemed our 9.50% senior notes for $367 million, or 104.75% of stated value. In addition, in March 2008, we made a scheduled debt repayment of $7 million related to certain of our other debt.

As of December 31, 2008, “current portion of debt and capital lease obligations” as reflected in the consolidated balance sheet consisted primarily of $200 million related to our 3.5% notes that matures in April 2009, $100 million of debt secured by certain of our accounts receivable that matures in June 2009 (discussed below), and the remaining $9 million of our 5.125% Series 1997D industrial revenue bonds that matures in April 2009.

We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables. In June 2008, we amended the agreement to extend the maturity date from August 2008 to June 2009. As of December 31, 2008, the amount of eligible receivables sold to the third-party entities and financial institutions was $100 million; the proceeds from the sale are reflected as debt in our consolidated balance sheet as of December 31, 2008. The amount outstanding as of December 31, 2008 was repaid in February 2009. Note 4 of Notes to Consolidated Financial Statements includes additional discussion of this program.

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

43

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, 2008, 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	Baa2 (stable outlook)
Fitch Ratings	BBB (stable outlook)

We cannot provide assurance that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell, or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing and the cost of such financings.

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.”

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, 2008, our short-term and long-term purchase obligations decreased by $18.2 billion from the amount reported as of December 31, 2007. The decrease is primarily attributable to lower crude oil and other feedstock prices at December 31, 2008 compared to December 31, 2007.

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, 2008.

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Other Commercial Commitments
As of December 31, 2008, our committed lines of credit were as follows:

	Borrowing
	Capacity	Expiration
Letter of credit facility	$300 million	June 2009
Letter of credit facility	$275 million	July 2009
Revolving credit facility	$2.5 billion	November 2012
Canadian revolving credit facility	Cdn. $115 million	December 2012

In June 2008, we entered into a one-year committed revolving letter of credit facility under which we may obtain letters of credit of up to $300 million. In July 2008, we entered into another one-year committed revolving letter of credit facility under which we may obtain letters of credit of up to $275 million. Both of these credit facilities support certain of our crude oil purchases. We are being charged letter of credit issuance fees in connection with these letter of credit facilities.

As of December 31, 2008, we had $201 million of letters of credit outstanding under uncommitted short-term bank credit facilities, $431 million of letters of credit outstanding under our three U.S. committed revolving credit facilities, and Cdn. $19 million of letters of credit outstanding under our Canadian committed revolving credit facility. These letters of credit expire during 2009 and 2010.

Stock Purchase Programs
On February 28, 2008, our board of directors approved a new $3 billion common stock purchase program. This program is in addition to the remaining amount under the $6 billion program previously authorized. This new $3 billion program has no expiration date. As of December 31, 2008, we had made no purchases of our common stock under the new $3 billion program. As of December 31, 2008, we have approvals under these stock purchase programs to purchase approximately $3.5 billion of our common stock.

During 2008, we purchased 18.0 million shares of our common stock for $667 million under our $6 billion common stock purchase program and 5.0 million shares for $288 million in connection with the administration of our employee benefit plans. These purchases represented approximately 4% of our outstanding shares of common stock as of December 31, 2008.

Pension Plan Funded Status
During 2008, we contributed $110 million to our qualified pension plans. Based on a 5.40% discount rate and fair values of plan assets as of December 31, 2008, the fair value of the assets in our qualified pension plans was equal to approximately 76% of the projected benefit obligation under those plans as of the end of 2008. The fair value of the assets in our qualified pension plans was in excess of the projected benefit obligation under those plans as of December 31, 2007. However, due primarily to a significant decline in the fair value of the plan assets during 2008 resulting from unfavorable economic and market conditions, the qualified pension plans were underfunded as of December 31, 2008.

Although we have only $8 million of minimum required contributions to our Qualified Plans during 2009 under the Employee Retirement Income Security Act, we plan to contribute approximately $130 million to our Qualified Plans during 2009. In January 2009, $50 million of this total expected contribution was contributed to our main Qualified Plan.

Environmental Matters
As discussed in Note 24 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

45

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 23 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. Accordingly, no expense or liability has been recognized in our consolidated financial statements with respect to this turnover tax on exports. We commenced arbitration proceedings with the Netherlands Arbitration Institute pursuant to which we are seeking to enforce our rights under the tax holiday and other agreements related to the refinery. The arbitration hearing was held on February 3-4, 2009. We anticipate a decision sometime later this year. We have also filed protests of these assessments through proceedings in Aruba. In April 2008, we entered into an escrow agreement with the GOA and Caribbean Mercantile Bank NV (CMB), pursuant to which we agreed to deposit an amount equal to the disputed turnover tax on exports into an escrow account with CMB, pending resolution of the tax protest proceedings in Aruba. Under this escrow agreement, we are required to continue to deposit an amount equal to the disputed tax on a monthly basis until the tax dispute is resolved through the Aruba proceedings. Amounts deposited under this escrow agreement, which totaled $102 million as of December 31, 2008, are reflected as “restricted cash” in our consolidated balance sheet.

In addition to the turnover tax described above, the GOA has also asserted other tax amounts aggregating approximately $25 million related to dividends and other tax items. The GOA, through the arbitration, is also now questioning the validity of the tax holiday generally, although the GOA has never issued any formal assessment for profit tax at any time during the tax holiday period. We believe that the provisions of our tax holiday agreement exempt us from all of these taxes and, accordingly, no expense or liability has been recognized in our consolidated financial statements. We are also challenging approximately $30 million in foreign exchange payments made to the Central Bank of Aruba as payments exempted under our tax holiday, as well as other reasons. These taxes and assessments are also being addressed in the arbitration proceedings discussed above.

Other
In July 2008, we entered into an agreement to participate as a prospective shipper on the 500,000 barrel-per-day expansion of the Keystone crude oil pipeline system, which is expected to be completed by 2012. Once completed, the pipeline will enable crude oil to be transported from Western Canada to the U.S. Gulf Coast at Port Arthur, Texas. In addition to our commitment to ship crude oil through the pipeline, we have an option to acquire an equity interest in the Keystone partnerships. We have also secured commitments from several Canadian oil producers to sell to us heavy sour crude oil for shipment through the pipeline.

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 submitted claims to our insurance

46

carriers under our insurance policies. We reached a settlement with the insurance carriers on our claims, resulting in pre-tax income of approximately $100 million in the first quarter of 2008 that was recorded as a reduction to “cost of sales.”

On January 25, 2008, our Aruba Refinery was shut down due to a fire in its vacuum unit. During the second quarter, we completed the repairs and resumed full operations of the refinery. This incident reduced our operating income for the year ended December 31, 2008.

In November 2007, we announced plans to explore strategic alternatives related to our Aruba Refinery. We are continuing to pursue potential transactions for this refinery, which may include the sale of the refinery.

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 borrowings under our credit facilities, 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 in the public and private capital markets or the arrangement of additional credit facilities. However, there can be no assurances regarding the availability of any future financings or additional credit facilities or whether such financings or additional credit facilities can be made available on terms that are acceptable to us.

NEW ACCOUNTING PRONOUNCEMENTS

As discussed in Note 1 of Notes to Consolidated Financial Statements, certain new financial accounting pronouncements have been issued that 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.

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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. Due to adverse changes in market conditions during the fourth quarter of 2008, as discussed further below in our discussion of goodwill, we evaluated our significant operating assets for potential impairment as of December 31, 2008, and we determined that the carrying amount of each of these assets was recoverable. Our impairment evaluations are based on assumptions that management deems to be reasonable. 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.

In regard to goodwill, we have historically performed our goodwill impairment test as of October 1 of each year. However, during the fourth quarter of 2008, there were severe disruptions in the capital and commodities markets that contributed to a significant decline in our common stock price, thus causing our market capitalization to decline to a level substantially below our net book value. Because a low market capitalization relative to net book value represents a key indicator that goodwill may be impaired, we determined that goodwill needed to be evaluated for impairment as of December 31, 2008 in addition to our normal annual testing date. As of the date of this goodwill impairment evaluation, all of our goodwill was allocated among four reporting units, namely each of the four geographic regions of our refining segment (the Gulf Coast, Mid-Continent, Northeast, and West Coast regions). No goodwill was reported in our retail segment.

Goodwill impairment testing is comprised of two steps. The first step (step 1) is to compare the estimated fair value of each reporting unit to its net book value, including any goodwill assigned to that reporting unit. If the estimated fair value of a reporting unit is higher than its recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value of a reporting unit is less than its recorded net book value, then the second step of the goodwill impairment test (step 2) is required to determine the amount of the goodwill impairment loss, if any. In the second step, the estimated fair value derived for the reporting unit in step 1 is deemed to represent the purchase price in a hypothetical acquisition of that reporting unit. The fair values of each of the reporting unit’s identifiable assets and liabilities are determined as they would be in a purchase business combination, and the excess of the deemed purchase price over the net fair value of all of the identifiable assets and liabilities represents the implied fair value of the goodwill of that reporting unit. If the carrying amount of that reporting unit’s goodwill exceeds this implied fair value of goodwill, an impairment loss is recognized in the amount of that excess to reduce the carrying amount of goodwill to the implied fair value determined in this hypothetical purchase price allocation.

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Because quoted market prices for our reporting units are not available, the impairment testing rules required management to exercise its judgment to determine the estimated fair values of our four reporting units for purposes of performing step 1 of the goodwill impairment test. Management considered the cyclicality of the refining business in deriving the set of prices that were applied to the anticipated charge and production volumes in each reporting unit. In determining the present values of each reporting unit’s cash flow streams, management utilized discount rates that were commensurate with the risks involved in the assets. To this applicable discount rate, management added a reasonable risk premium in order to consider the impact of volatility within the refining industry and current tightness in the capital markets on an investor’s required rate of return.

An important requirement related to this fair value determination process is to reconcile the sum of the fair values determined for the various reporting units to our market capitalization. In order to perform this reconciliation, we first determined a fair value for our retail segment using an appropriate discount rate. Then we compared the sum of the fair values of the retail segment and the four refining reporting units to our total enterprise value, with our market capitalization determined based on our common stock price as of December 31, 2008. For this purpose, we also added a control premium to our market capitalization, in recognition of the fact that an acquiring entity generally is willing to pay more for equity ownership that gives it a controlling interest than an individual investor would pay for shares that constitute less than a controlling interest. The control premium that we added to our market capitalization represented a reasonable premium for acquisitions in our industry. Because the enterprise value, including the control premium, was comparable to the sum of the fair values determined above, we concluded that the assumptions utilized to determine the fair values of our reporting units were reasonable. The computed fair value of each of the reporting units was less than its net book value including goodwill, and therefore the goodwill in each of the reporting units was potentially impaired.

We then applied step 2 of the goodwill impairment test to each of the reporting units, with the fair value for each reporting unit derived in step 1 constituting the assumed purchase price in a hypothetical acquisition of each of those reporting units. In allocating value to the property, plant and equipment of each of the reporting units, we used current replacement costs for the refineries that comprised each reporting unit and applied a depreciation factor based on historical depreciation. We adjusted deferred income taxes based on the fair value assigned to property, plant and equipment and reflected the fair value of inventory and other working capital included in each reporting unit. Our calculations indicated that the net fair value of each reporting unit’s identifiable assets and liabilities was significantly in excess of the deemed purchase price, and therefore no implied fair value of goodwill existed in any of the four reporting units. As a result, we concluded that an impairment of the entire amount of recorded goodwill was required, which resulted in a $4.1 billion pre-tax goodwill impairment loss, or $4.0 billion after tax, in the fourth quarter of 2008.

Environmental Liabilities
Our operations are subject to extensive environmental regulation by federal, state, and local authorities relating primarily to discharge of materials into the environment, waste management, and pollution prevention measures. Future legislative action and regulatory initiatives could result in changes to required operating permits, additional remedial actions, or increased capital expenditures and operating costs that cannot be assessed with certainty at this time.

Accruals for environmental liabilities are based on best estimates of probable undiscounted future costs assuming currently available remediation technology and applying current regulations, as well as our own internal environmental policies. However, environmental liabilities are difficult to assess and estimate due to uncertainties related to the magnitude of possible remediation, the timing of such remediation, and the 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

49

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, 2008, 2007, and 2006 is included in Note 24 of Notes to Consolidated Financial Statements.

Pension and Other Postretirement Benefit Obligations
We have significant pension and other postretirement benefit liabilities and costs that are developed from actuarial valuations. Inherent in these valuations are key assumptions including discount rates, expected return on plan assets, future compensation increases, and health care cost trend rates. Changes in these assumptions are primarily influenced by factors outside our control. For example, the discount rate assumption represents a yield curve comprised of various long-term bonds that each receive one of the two highest ratings given by the recognized rating agencies 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, 2008 and net periodic benefit cost for the year ending December 31, 2009 (in millions):

			Other
	Pension		Postretirement
	Benefits		Benefits
Increase in projected benefit obligation resulting from:
Discount rate decrease	$	66	$	15
Compensation rate increase		28		–
Health care cost trend rate increase		–		9
Increase in expense resulting from:
Discount rate decrease		10		1
Expected return on plan assets decrease		4		–
Compensation rate increase		6		–
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 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

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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). 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 income. Finally, we enter into derivative commodity instruments based on our fundamental and technical analysis of market conditions that we mark to market for accounting purposes. See “Derivative Instruments” in Note 1 of Notes to Consolidated Financial Statements for a discussion of our accounting for the various types of derivative transactions.

The types of instruments used in our hedging and trading activities described above include swaps, futures, and options. Our positions in derivative commodity instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.

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The following tables provide information about our derivative commodity instruments as of December 31, 2008 and 2007 (dollars in millions, except for the weighted-average pay and receive prices as described below), including:

Fair Value Hedges – Fair value hedges are used to hedge certain recognized refining inventories (which had a carrying amount of $4.4 billion and $3.8 billion as of December 31, 2008 and 2007, respectively, and a fair value of $5.1 billion and $10.0 billion as of December 31, 2008 and 2007, respectively) and our unrecognized firm commitments (i.e.,binding agreements to purchase inventories in the future). 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.

Cash Flow Hedges – Cash flow hedges are used to hedge certain forecasted feedstock and product purchases, refined product sales, and natural gas purchases. 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.

Economic Hedges – Economic hedges are hedges not designated as fair value or cash flow hedges that are used to:

– manage price volatility in refinery feedstock and refined product inventories,

– manage price volatility in forecasted feedstock and product purchases, refined product sales, and natural gas purchases; and

– manage price volatility in the referenced product margins associated with the Alon earn-out agreement as discussed in Note 2 of Notes to Consolidated Financial Statements.

The derivative instruments related to economic hedges are recorded at fair value and changes in the fair value of the derivative instruments are recognized currently in income.

Trading Activities – These represent derivative commodity instruments held or issued for trading purposes. The derivative instruments entered into by us for trading activities are recorded at fair value and changes in the fair value of the derivative instruments are recognized currently in income.

The following tables include only open positions at the end of the reporting period. 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, 2008
			Wtd Avg		Wtd Avg							Pre-tax
	Contract		Pay		Receive		Contract		Market			Fair
	Volumes		Price		Price		Value		Value			Value
Fair Value Hedges:
Futures – short:
2009 (crude oil and refined products)		6,904		N/A	$	48.28	$	333	$	320		$	13
Cash Flow Hedges:
Swaps – long:
2009 (crude oil and refined products)		60,162	$	121.69		58.44		N/A		(3,805	)		(3,805	)
2010 (crude oil and refined products)		4,680		63.72		64.03		N/A		1			1
Swaps – short:
2009 (crude oil and refined products)		60,162		62.38		129.80		N/A		4,056			4,056
2010 (crude oil and refined products)		4,680		76.32		78.69		N/A		11			11
Futures – long:
2009 (crude oil and refined products)		780		38.62		N/A		30		27			(3	)
Economic Hedges:
Swaps – long:
2009 (crude oil and refined products)		25,987		96.88		55.25		N/A		(1,082	)		(1,082	)
2010 (crude oil and refined products)		19,734		105.96		63.94		N/A		(829	)		(829	)
2011 (crude oil and refined products)		3,900		124.78		67.99		N/A		(221	)		(221	)
Swaps – short:
2009 (crude oil and refined products)		25,931		59.65		106.81		N/A		1,223			1,223
2010 (crude oil and refined products)		19,734		72.18		121.96		N/A		982			982
2011 (crude oil and refined products)		3,900		74.08		136.66		N/A		244			244
Futures – long:
2009 (crude oil and refined products)		135,882		59.17		N/A		8,040		7,319			(721	)
2010 (crude oil and refined products)		3,466		78.33		N/A		271		240			(31	)
2009 (natural gas)		4,310		8.46		N/A		36		24			(12	)
Futures – short:
2009 (crude oil and refined products)		135,091		N/A		62.74		8,475		7,510			965
2010 (crude oil and refined products)		3,692		N/A		84.66		313		276			37
2009 (natural gas)		4,310		N/A		5.68		24		24			–
Options – long:
2009 (crude oil and refined products)		57		60.64		N/A		1		–			(1	)
Trading Activities:
Swaps – long:
2009 (crude oil and refined products)		19,887		77.56		45.09		N/A		(646	)		(646	)
2010 (crude oil and refined products)		10,050		40.66		35.35		N/A		(53	)		(53	)
2011 (crude oil and refined products)		1,950		78.36		65.80		N/A		(24	)		(24	)
Swaps – short:
2009 (crude oil and refined products)		16,084		56.44		97.17		N/A		655			655
2010 (crude oil and refined products)		5,850		64.19		73.12		N/A		52			52
2011 (crude oil and refined products)		1,950		68.06		80.59		N/A		24			24

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	December 31, 2008
			Wtd Avg		Wtd Avg						Pre-tax
	Contract		Pay		Receive		Contract		Market		Fair
	Volumes		Price		Price		Value		Value		Value
Futures – long:
2009 (crude oil and refined products)		24,039	$	71.70		N/A	$	1,724	$	1,300	$	(424	)
2010 (crude oil and refined products)		956		84.12		N/A		80		70		(10	)
2009 (natural gas)		200		5.79		N/A		1		1		–
Futures – short:
2009 (crude oil and refined products)		21,999		N/A		73.38		1,614		1,209		405
2010 (crude oil and refined products)		956		N/A		83.63		80		70		10
2009 (natural gas)		200		N/A		5.82		1		1		–
Options – long:
2009 (crude oil and refined products)		100		30.00		N/A		–		–		–
Total pre-tax fair value of open positions											$	816

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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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INTEREST RATE RISK

In general, our primary market risk exposure for changes in interest rates relates to our 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 debt balances are adjusted accordingly. We had no interest rate derivative instruments outstanding as of December 31, 2008 and 2007.

The following table provides information about our 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, 2008
	Expected Maturity Dates
																There-						Fair
	2009			2010			2011			2012			2013			after			Total			Value
Debt:
Fixed rate	$	209		$	33		$	418		$	759		$	489		$	4,597		$	6,505		$	6,362
Average interest rate		3.6	%		6.8	%		6.4	%		6.9	%		5.5	%		6.8	%		6.6	%
Floating rate	$	100		$	–		$	–		$	–		$	–		$	–		$	100		$	100
Average interest rate		3.9	%		–	%		–	%		–	%		–	%		–	%		3.9	%

	December 31, 2007
	Expected Maturity Dates
																There-						Fair
	2008			2009			2010			2011			2012			after			Total			Value
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	%

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, 2008, we had commitments to purchase $280 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before January 30, 2009, resulting in a 2009 gain 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, 2008. 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, 2008, 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 59 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, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the PCAOB, the Company’s internal control over financial reporting as of December 31, 2008, 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 26, 2009, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

San Antonio, Texas
February 26, 2009

58

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’s) internal control over financial reporting as of December 31, 2008, 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, 2008, based on criteria established in Internal Control–Integrated Framework issued by COSO.

59

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, 2008 and 2007, 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, 2008, and our report dated February 26, 2009 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

San Antonio, Texas
February 26, 2009

60

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)

	December 31,
	2008			2007
ASSETS
Current assets:
Cash and temporary cash investments	$	940		$	2,464
Restricted cash		131			31
Receivables, net		2,897			7,691
Inventories		4,637			4,073
Income taxes receivable		197			–
Deferred income taxes		98			247
Prepaid expenses and other		550			175
Assets held for sale		–			306
Total current assets		9,450			14,987
Property, plant and equipment, at cost		28,103			25,599
Accumulated depreciation		(4,890	)		(4,039	)
Property, plant and equipment, net		23,213			21,560
Intangible assets, net		224			290
Goodwill		–			4,019
Deferred charges and other assets, net		1,530			1,866
Total assets	$	34,417		$	42,722
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	312		$	392
Accounts payable		4,446			9,587
Accrued expenses		374			500
Taxes other than income taxes		592			632
Income taxes payable		–			499
Deferred income taxes		485			293
Liabilities related to assets held for sale		–			11
Total current liabilities		6,209			11,914
Debt and capital lease obligations, less current portion		6,264			6,470
Deferred income taxes		4,163			4,021
Other long-term liabilities		2,161			1,810
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		7,190			7,111
Treasury stock, at cost; 111,290,436 and 90,841,602 common shares		(6,884	)		(6,097	)
Retained earnings		15,484			16,914
Accumulated other comprehensive income (loss)		(176	)		573
Total stockholders’ equity		15,620			18,507
Total liabilities and stockholders’ equity	$	34,417		$	42,722

See Notes to Consolidated Financial Statements.

61

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, Except per Share Amounts)

	Year Ended December 31,
	2008			2007			2006
Operating revenues (1)	$	119,114		$	95,327		$	87,640
Costs and expenses:
Cost of sales		107,429			81,645			73,863
Refining operating expenses		4,555			4,016			3,622
Retail selling expenses		768			750			719
General and administrative expenses		559			638			598
Depreciation and amortization expense		1,476			1,360			1,116
Gain on sale of Krotz Springs Refinery		(305	)		–			–
Goodwill impairment loss		4,069			–			–
Total costs and expenses		118,551			88,409			79,918
Operating income		563			6,918			7,722
Equity in earnings of NuStar Energy L.P.		–			–			45
Other income, net		113			167			350
Interest and debt expense:
Incurred		(451	)		(466	)		(377	)
Capitalized		111			107			165
Minority interest in net income of NuStar GP Holdings, LLC		–			–			(7	)
Income from continuing operations before income tax expense		336			6,726			7,898
Income tax expense		1,467			2,161			2,611
Income (loss) from continuing operations		(1,131	)		4,565			5,287
Income from discontinued operations, net of income tax expense		–			669			176
Net income (loss)		(1,131	)		5,234			5,463
Preferred stock dividends		–			–			2
Net income (loss) applicable to common stock	$	(1,131	)	$	5,234		$	5,461
Earnings (loss) per common share:
Continuing operations	$	(2.16	)	$	8.08		$	8.65
Discontinued operations		–			1.19			0.29
Total	$	(2.16	)	$	9.27		$	8.94
Weighted-average common shares outstanding (in millions)		524			565			611
Earnings (loss) per common share – assuming dilution:
Continuing operations	$	(2.16	)	$	7.72		$	8.36
Discontinued operations		–			1.16			0.28
Total	$	(2.16	)	$	8.88		$	8.64
Weighted-average common shares outstanding – assuming dilution (in millions)		524			579			632
Dividends per common share	$	0.57		$	0.48		$	0.30
Supplemental information:
(1) Includes excise taxes on sales by our U.S. retail system	$	816		$	801		$	782

See Notes to Consolidated Financial Statements.

62

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, 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

Net loss

–

–

–

–

(1,131

)

–

Dividends on common stock

–

–

–

–

(299

)

–

Stock-based compensation expense

–

–

62

–

–

–

Shares repurchased under $6 billion common stock purchase program

–

–

–

(667

)

–

–

Shares repurchased, net of shares issued, in connection with employee stock plans and other

–

–

17

(120

)

–

–

Other comprehensive loss

–

–

–

–

–

(749

)

Balance as of December 31, 2008

$

–

$

6

$

7,190

$

(6,884

)

$

15,484

$

(176

)

See Notes to Consolidated Financial Statements.

63

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)

	Year Ended December 31,
	2008			2007			2006
Cash flows from operating activities:
Net income (loss)	$	(1,131	)	$	5,234		$	5,463
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense		1,476			1,376			1,155
Goodwill impairment loss		4,069			–			–
Gain on sale of Krotz Springs Refinery		(305	)		–			–
Gain on sale of Lima Refinery		–			(827	)		–
Gain on sale of NuStar GP Holdings, LLC		–			–			(328	)
Noncash interest expense and other income, net		(76	)		(10	)		31
Stock-based compensation expense		59			100			108
Deferred income tax expense (benefit)		675			(131	)		290
Changes in current assets and current liabilities		(1,630	)		(469	)		(144	)
Changes in deferred charges and credits and other operating activities, net		(145	)		(15	)		(263	)
Net cash provided by operating activities		2,992			5,258			6,312
Cash flows from investing activities:
Capital expenditures		(2,790	)		(2,260	)		(3,187	)
Deferred turnaround and catalyst costs		(408	)		(518	)		(569	)
Proceeds from sale of Krotz Springs Refinery		463			–			–
Proceeds from sale of Lima Refinery		–			2,428			–
Proceeds from sale of NuStar GP Holdings, LLC		–			–			880
Contingent payments in connection with acquisitions		(25	)		(75	)		(101	)
(Investment) return of investment in Cameron Highway Oil Pipeline Company, net		24			(209	)		(26	)
Proceeds from minor dispositions of property, plant and equipment		25			63			64
Minor acquisitions		(144	)		–			–
Other investing activities, net		(7	)		(11	)		(32	)
Net cash used in investing activities		(2,862	)		(582	)		(2,971	)
Cash flows from financing activities:
Non-bank debt:
Borrowings		–			2,245			–
Repayments		(374	)		(463	)		(249	)
Bank credit agreements:
Borrowings		296			3,000			830
Repayments		(296	)		(3,000	)		(830	)
Termination of interest rate swaps		–			–			(54	)
Purchase of common stock for treasury		(955	)		(5,788	)		(2,020	)
Issuance of common stock in connection with employee benefit plans		16			159			122
Benefit from tax deduction in excess of recognized stock-based compensation cost		9			311			206
Common and preferred stock dividends		(299	)		(271	)		(184	)
Other financing activities		(4	)		(24	)		(9	)
Net cash used in financing activities		(1,607	)		(3,831	)		(2,188	)
Effect of foreign exchange rate changes on cash		(47	)		29			1
Net increase (decrease) in cash and temporary cash investments		(1,524	)		874			1,154
Cash and temporary cash investments at beginning of year		2,464			1,590			436
Cash and temporary cash investments at end of year	$	940		$	2,464		$	1,590

See Notes to Consolidated Financial Statements.

64

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of Dollars)

	Year Ended December 31,
	2008			2007			2006
Net income (loss)	$	(1,131	)	$	5,234		$	5,463
Other comprehensive income (loss):
Foreign currency translation adjustment, net of income tax expense of $-, $31, and $-		(490	)		250			(11	)
Pension and other postretirement benefits:
Net gain (loss) arising during the year, net of income tax (expense) benefit of $227, $(56), and $-		(410	)		80			(1	)
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $-, $(3), and $-		(1	)		6			–
Net gain (loss) on pension and other postretirement benefits		(411	)		86			(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 $(46), $6, and $(38)		85			(11	)		70
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $(36), $9, and $15		67			(17	)		(29	)
Net gain (loss) on cash flow hedges		152			(28	)		41
Other comprehensive income (loss)		(749	)		308			29
Comprehensive income (loss)	$	(1,880	)	$	5,542		$	5,492

See Notes to Consolidated Financial Statements.

65

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 16 refineries with a combined total throughput capacity as of December 31, 2008 of approximately 3.0 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.

As discussed in Note 2, we sold our Krotz Springs Refinery and our Lima Refinery effective July 1, 2008 and July 1, 2007, respectively. The assets and liabilities of the Krotz Springs Refinery, as well as inventory sold by our marketing and supply subsidiary associated with that transaction, have been reclassified as held for sale as of December 31, 2007. See Note 2 for a discussion of the presentation in the statements of income of the results of operations for these two refineries for periods preceding the effective dates of the sales.

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. The term Premcor Acquisition refers to the merger of Premcor Inc. (Premcor) into Valero effective September 1, 2005.

66

VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Hierarchy of Generally Accepted Accounting Principles
In May 2008, the Financial Accounting Standards Board (FASB) issued Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” Statement No. 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with United States generally accepted accounting principles (GAAP). Statement No. 162 was effective November 15, 2008. The adoption of Statement No. 162 has not affected our financial position or results of operations.

Use of Estimates
The preparation of financial statements in conformity with 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.

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” as described in 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.

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, except gains or losses on dispositions of certain property, plant and equipment that are reported on a separate line item due to materiality.

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

67

VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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. See Note 8.

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, 2008 are recoverable.

Impairment and Disposal of Long-Lived Assets
Long-lived assets (excluding goodwill, intangible assets with indefinite lives, equity method investments, and deferred tax assets) are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its fair value, with fair value determined based on discounted estimated net cash flows. We believe that the carrying amounts of our long-lived assets as of December 31, 2008 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.

68

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 19, 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.

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

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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 (loss).” 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 (loss).”

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 Emerging Issues Task Force (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.

We enter into certain purchase and sale arrangements with the same counterparty that are deemed to be made in contemplation of one another. Commencing January 1, 2006, the date of our adoption of EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” we combine these transactions and, as a result, revenues and cost of sales are not recognized in connection with these arrangements.

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

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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 values. 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 activity. 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. 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. Income effects of commodity derivative instruments, other than certain contracts related to an earn-out agreement discussed in Notes 2 and 17, are recorded in “cost of sales” while income effects of interest rate swaps (if applicable) are recorded in “interest and debt expense.”

In September 2008, the FASB issued Staff Position No. FAS 133-1 and FIN 45-4, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161” (FSP No. FAS 133-1 and FIN 45-4). FSP No. FAS 133-1 and FIN 45-4 amends FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” to require disclosures by sellers of credit derivatives, including those embedded in hybrid instruments. FSP No. FAS 133-1 and FIN 45-4 also amends FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” to require disclosure about the current status of the payment/performance risk of a guarantee. Additionally, FSP No. FAS 133-1 and FIN 45-4 clarifies the FASB’s intent that disclosures required by FASB Statement No. 161, “Disclosures about Derivatives and Hedging Activities,” should be provided for any reporting period beginning after November 15, 2008. The provisions of FSP No. FAS 133-1 and FIN 45-4 that amend Statement No. 133 and Interpretation No. 45 are effective for fiscal years, and interim periods within those fiscal years, ending after November 15, 2008. Since FSP No. FAS 133-1 and FIN 45-4 only affects disclosure requirements, the adoption of FSP No. FAS 133-1 and FIN 45-4 effective December 31, 2008 has not affected our financial position or results of operations.

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 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.

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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.

In February 2007, the FASB issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115.” 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. The adoption of Statement No. 159 effective January 1, 2008 did not materially affect our financial position or results of operations.

Fair Value Measurements
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, but does not require any new fair value measurements. We adopted Statement No. 157 effective January 1, 2008, with the exceptions allowed under FASB Staff Position No. FAS 157-2 (FSP No. FAS 157-2) (further described under“New Accounting Pronouncements"),the adoption of which did not affect our financial position or results of operations but did result in additional required disclosures, which are provided in Note 17.

In October 2008, the FASB issued Staff Position No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (FSP No. FAS 157-3). FSP No. FAS 157-3 applies to financial assets within the scope of accounting pronouncements that require or permit fair value measurements in accordance with Statement No. 157. FSP No. FAS 157-3 clarifies the application of Statement No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. We adopted FSP No. FAS 157-3 effective October 10, 2008 and applied its provisions to our financial statements commencing in the third quarter of 2008. The adoption of FSP No. FAS 157-3 has not materially affected our financial position or results of operations.

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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. Common equivalent shares were excluded from the computation of diluted earnings per share for the year ended December 31, 2008 because the effect of including such shares would be anti-dilutive.

Comprehensive Income
Comprehensive income consists of net income (loss) and other gains and losses affecting stockholders’ equity that, under GAAP, are excluded from net income (loss), including foreign currency translation adjustments, gains and losses related to certain derivative contracts, and gains or losses, prior service costs or credits, and transition assets or obligations associated with pension or other postretirement benefits that have not been recognized as components of net periodic benefit cost.

Defined Benefit Pension and Other Postretirement Plans
In September 2006, the FASB issued Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which amends Statement No. 87, “Employers’ Accounting for Pensions,” Statement No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” Statement No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” and other related accounting literature.

Statement No. 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or a liability in the statement of financial position and to recognize changes in that funded status through comprehensive income in the year the changes occur. This statement also requires an employer to measure the funded status of a plan as of the date of the employer’s year-end statement of financial position. We adopted the funded status recognition and related disclosure requirements of Statement No. 158 as of December 31, 2006, the adoption of which did not materially affect our financial position or results of operations in 2006. See Note 21 for information regarding the funded status of our defined benefit plans as of December 31, 2008 and 2007.

Stock-Based Compensation
Effective January 1, 2006, we adopted Statement No. 123 (revised 2004), “Share-Based Payment” (Statement No. 123(R)), which requires the expensing of the fair value of stock options. We adopted the fair value recognition provisions of Statement No. 123(R) using the modified prospective application. Accordingly, we recognize compensation expense for all newly granted stock options and stock options modified, repurchased, or cancelled on or after January 1, 2006. Compensation expense for stock options granted on or after January 1, 2006 is being recognized on a straight-line basis. 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 applying the attribution approach utilized in determining the pro forma effect of expensing stock options that was required for periods prior to the effective date of Statement No. 123(R). Our total stock-based compensation expense recognized for the years ended December 31, 2008, 2007, and 2006 was

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

$38 million, net of tax benefits of $21 million, $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. Upon the adoption of Statement No. 123(R), we changed our method of recognizing compensation cost for new grants that have retirement-eligibility provisions from recognizing such costs over the nominal vesting period 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, net income (loss) applicable to common stock and net income (loss) would have increased by $2 million, $4 million, and $4 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Statement No. 123(R) 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. 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 $9 million, $311 million, and $206 million for the years ended December 31, 2008, 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 this policy.

New Accounting Pronouncements
FSP No. FAS 157-2
In February 2008, the FASB issued Staff Position No. FAS 157-2, which 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. The exceptions apply to the following: nonfinancial assets and nonfinancial liabilities measured at fair value in a business combination; impaired property, plant and equipment; goodwill; and the initial recognition of the fair value of asset retirement obligations and restructuring costs. The implementation of Statement No. 157 for these assets and liabilities effective January 1, 2009 has not had a material effect on 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. 141(R)). This statement improves the financial reporting of business combinations and

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clarifies the accounting for these transactions. The provisions of Statement No. 141(R) 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. 141(R) effective January 1, 2009 has not had any immediate effect on our financial position or results of operations.

FASB Statement No. 160
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.

FASB Statement No. 161
In March 2008, the FASB issued Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” Statement No. 161 establishes, among other things, the disclosure requirements for derivative instruments and for hedging activities. This statement requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about contingent features related to credit risk in derivative agreements. Statement No. 161 is effective for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008. Since Statement No. 161 only affects disclosure requirements, the adoption of Statement No. 161 effective January 1, 2009 has not affected our financial position or results of operations.

FSP No. EITF 03-6-1
In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP No. EITF 03-6-1). FSP No. EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method described in Statement No. 128. FSP No. EITF 03-6-1 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2008; early adoption is not permitted. The adoption of FSP No. EITF 03-6-1 effective January 1, 2009 is not expected to materially affect our calculation of earnings per common share.

EITF Issue No. 08-6
In November 2008, the FASB ratified its consensus on EITF Issue No. 08-6, “Equity Method Investment Accounting Considerations” (EITF No. 08-6). EITF No. 08-6 applies to all investments accounted for under the equity method and provides guidance regarding (i) initial measurement of an equity investment, (ii) recognition of other-than-temporary impairment of an equity method investment, including any impairment charge taken by the investee, and (iii) accounting for a change in ownership level or degree of influence on an investee. The consensus is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. EITF No. 08-6 is to be applied prospectively and earlier application is not permitted. Due to its application to future equity method investments, the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

adoption of EITF No. 08-6 effective January 1, 2009 has not had any immediate effect on our financial position or results of operations.

FSP No. FAS 132(R)-1
In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP No. FAS 132(R)-1). FSP No. FAS 132(R)-1 amends FASB Statement No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The additional requirements of FSP No. FAS 132(R)-1 are designed to enhance disclosures regarding (i) investment policies and strategies, (ii) categories of plan assets, (iii) fair value measurements of plan assets, and (iv) significant concentrations of risk. FSP No. FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009, with earlier application permitted. Since FSP No. FAS 132(R)-1 only affects disclosure requirements, the adoption of FSP No. FAS 132(R)-1 will not affect our financial position or results of operations.

Reclassifications
Our consolidated balance sheet as of December 31, 2007 has been reclassified to present the assets and liabilities of the Krotz Springs Refinery as “assets held for sale” and “liabilities related to assets held for sale,” respectively. In addition, certain other minor amounts previously reported in our annual report on Form 10-K for the year ended December 31, 2007 have been reclassified to conform to the 2008 presentation.

2. ACQUISITIONS AND DISPOSITIONS

Sale of Krotz Springs Refinery
Effective July 1, 2008, we sold our refinery in Krotz Springs, Louisiana to Alon Refining Krotz Springs, Inc. (Alon), a subsidiary of Alon USA Energy, Inc. As a result, the assets and liabilities related to the Krotz Springs Refinery as of December 31, 2007 have been presented in the consolidated balance sheet as “assets held for sale” and “liabilities related to assets held for sale,” respectively. The nature and significance of our post-closing participation in the offtake agreement described below represents a continuation of activities with the Krotz Springs Refinery for accounting purposes, and as such the results of operations related to the Krotz Springs Refinery have not been presented as discontinued operations in the consolidated statements of income for any of the periods presented.

The sale resulted in a pre-tax gain of $305 million ($170 million after tax), which is presented in “gain on sale of Krotz Springs Refinery” in the consolidated statement of income for the year ended December 31, 2008. Cash proceeds, net of certain costs related to the sale, were $463 million, including approximately $135 million from the sale of working capital to Alon primarily related to the sale of inventory by our marketing and supply subsidiary. In addition to the cash consideration received, we also received contingent consideration in the form of a three-year earn-out agreement based on certain product margins, which had a fair value of $171 million as of July 1, 2008. We have hedged the risk of a decline in the referenced product margins by entering into certain commodity derivative contracts.

In connection with the sale, we also entered into the following agreements with Alon:

• an agreement to supply crude oil and other feedstocks to the Krotz Springs Refinery through September 30, 2008, which was subsequently extended until November 30, 2008;

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• an offtake agreement under which we agreed to (i) purchase all refined products from the Krotz Springs Refinery for three months after the effective date of the sale, (ii) purchase certain products for an additional one to five years after the expiration of the initial three-month period of the agreement, and (iii) provide certain refined products to Alon that are not produced at the Krotz Springs Refinery for an initial term of 15 months and thereafter until terminated by either party; and

• a transition services agreement under which we agreed to provide certain accounting and administrative services to Alon, with the services terminating by July 31, 2009. Substantially all of these services had been transitioned to Alon as of December 31, 2008.

Financial information related to the Krotz Springs Refinery assets and liabilities sold is summarized as follows (in millions):

	July 1,		December 31,
	2008		2007
Current assets (primarily inventory)	$	138	$	111
Property, plant and equipment, net		153		149
Goodwill		42		42
Deferred charges and other assets, net		4		4
Assets held for sale	$	337	$	306
Current liabilities	$	10	$	11
Liabilities related to assets held for sale	$	10	$	11

Sale of Lima Refinery
Effective July 1, 2007, we sold 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 sold certain inventory amounts to Husky as part of this transaction. 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.”

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 provide certain accounting and administrative services to Husky; all of these services were transitioned to Husky by the middle of 2008.

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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
Operating revenues	$	2,231	$	4,119
Income before income tax expense		391		291

Minor Acquisitions
In February 2008, we purchased ConocoPhillips’ one-third undivided joint interest in a refined product pipeline and terminal for $57 million. These assets provide transportation and storage services for moving refined products from our McKee Refinery to markets in El Paso, Texas and Phoenix and Tucson, Arizona.

In August 2008, we purchased 70 convenience stores and fueling kiosks from Albertson’s LLC for $87 million, including $4 million for inventory. These retail sites, which are located in Texas, Colorado, Arizona, and Louisiana, enhance our existing retail network and supply chain.

3. RESTRICTED CASH

Restricted cash consisted of the following (in millions):

	December 31,
	2008		2007
Cash held in trust related to the UDS Acquisition	$	22	$	23
Cash held in trust related to the Premcor Acquisition		7		8
Cash related to escrow agreement with the Government of Aruba (see Note 23)		102		–
Restricted cash	$	131	$	31

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4. RECEIVABLES

Receivables consisted of the following (in millions):

	December 31,
	2008			2007
Accounts receivable	$	2,939		$	7,702
Notes receivable and other		16			32
		2,955			7,734
Allowance for doubtful accounts		(58	)		(43	)
Receivables, net	$	2,897		$	7,691

The changes in the allowance for doubtful accounts consisted of the following (in millions):

	Year Ended December 31,
	2008			2007			2006
Balance as of beginning of year	$	43		$	33		$	31
Increase in allowance charged to expense		43			34			16
Accounts charged against the allowance, net of recoveries		(27	)		(25	)		(14	)
Foreign currency translation		(1	)		1			–
Balance as of end of year	$	58		$	43		$	33

We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables. In June 2008, we amended the agreement to extend the maturity date from August 2008 to June 2009. We use this program as a source of working capital funding. Under this program, one of our marketing subsidiaries (Valero Marketing) sells eligible receivables, without recourse, to another of our subsidiaries (Valero Capital), whereupon the receivables are no longer owned by Valero Marketing. Valero Capital, in turn, sells an undivided percentage ownership interest in the eligible receivables, without recourse, to the third-party entities and financial institutions. To the extent that Valero Capital retains an ownership interest in the receivables it has purchased from Valero Marketing, such interest is included in our consolidated financial statements solely as a result of the consolidation of the financial statements of Valero Capital with those of Valero Energy Corporation; the receivables are not available to satisfy the claims of the creditors of Valero Marketing or Valero Energy Corporation.

As of December 31, 2008 and 2007, $1.3 billion and $4.0 billion, respectively, of our accounts receivable composed the designated pool of accounts receivable included in the program. As of December 31, 2008 and 2007, the amount of eligible receivables sold to the third-party entities and financial institutions was $100 million. At December 31, 2008, proceeds from the sale of receivables under this facility were reflected as debt in our consolidated balance sheet. The amount outstanding as of December 31, 2008 was repaid in February 2009. Prior to December 31, 2008, amounts received under the program were reflected as a reduction of “receivables, net” in the consolidated balance sheet, with the residual interest that we retained in the designated pool of receivables 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 approximated the total amount of the designated pool of accounts receivable reduced by

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the amount of accounts receivable sold to the third-party entities and financial institutions under the program.

We remain responsible for servicing the receivables sold to the third-party entities and financial institutions and pay certain fees related to our sale of receivables 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 $6 million, $40 million, and $55 million for the years ended December 31, 2008, 2007, and 2006, respectively. Proceeds from collections under this facility of $3.3 billion, $19.3 billion, and $31.2 billion for the years ended December 31, 2008, 2007, and 2006, respectively, were reinvested in the program by the third-party entities and financial institutions. However, the third-party entities’ and 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 2008, 2007, or 2006.

5. INVENTORIES

Inventories consisted of the following (in millions):

	December 31,
	2008		2007
Refinery feedstocks	$	2,140	$	1,701
Refined products and blendstocks		2,224		2,117
Convenience store merchandise		90		85
Materials and supplies		183		170
Inventories	$	4,637	$	4,073

Refinery feedstock and refined product and blendstock inventory volumes totaled 114 million barrels and 105 million barrels as of December 31, 2008 and 2007, respectively. There were no substantial liquidations of LIFO inventory layers for the years ended December 31, 2008, 2007, and 2006.

As of December 31, 2008 and 2007, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $686 million and $6.2 billion, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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	2008			2007
Land		$	602		$	574
Crude oil processing facilities	10 - 33 years		21,194			20,509
Butane processing facilities	30 years		246			246
Pipeline and terminal facilities	24 - 42 years		549			511
Retail facilities	5 - 22 years		787			735
Buildings	13 - 47 years		872			775
Other	1 - 44 years		1,102			1,006
Construction in progress			2,751			1,243
Property, plant and equipment, at cost			28,103			25,599
Accumulated depreciation			(4,890	)		(4,039	)
Property, plant and equipment, net		$	23,213		$	21,560

We had crude oil processing facilities, pipeline and terminal facilities, and certain buildings and other equipment under capital leases totaling $54 million as of both December 31, 2008 and 2007. Accumulated amortization on assets under capital leases was $13 million and $10 million, respectively, as of December 31, 2008 and 2007.

Depreciation expense for the years ended December 31, 2008, 2007, and 2006 was $990 million, $916 million, and $776 million, respectively.

7. INTANGIBLE ASSETS

Intangible assets consisted of the following (in millions):

	December 31, 2008					December 31, 2007
	Gross		Accumulated			Gross		Accumulated
	Cost		Amortization			Cost		Amortization
Intangible assets subject to amortization:
Customer lists	$	97	$	(43	)	$	116	$	(45	)
Canadian retail operations		127		(22	)		156		(23	)
U.S. retail store operations		95		(76	)		94		(66	)
Air emission credits		62		(29	)		62		(23	)
Royalties and licenses		25		(12	)		25		(11	)
Gasoline and diesel sulfur credits		27		(27	)		27		(23	)
Other		4		(4	)		4		(3	)
Intangible assets subject to amortization	$	437	$	(213	)	$	484	$	(194	)

All of our intangible assets are subject to amortization. Amortization expense for intangible assets was $33 million, $48 million, and $35 million for the years ended December 31, 2008, 2007, and 2006,

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respectively. The estimated aggregate amortization expense for the years ending December 31, 2009 through December 31, 2013 is as follows (in millions):

	Amortization
	Expense
2009	$	23
2010		20
2011		14
2012		14
2013		14

During the year ended December 31, 2008, gross cost and accumulated amortization of intangible assets decreased by $50 million and $14 million, respectively, due to fluctuations in the Canadian dollar exchange rate.

8. GOODWILL

The changes in the carrying amount of goodwill were as follows (in millions):

	Year Ended December 31,
	2008			2007
Balance as of beginning of year	$	4,019		$	4,061
Settlements and adjustments related to acquisition tax contingencies, stock option exercises, and other		50			(42	)
Goodwill impairment loss		(4,069	)		–
Balance as of end of year	$	–		$	4,019

Settlements and adjustments related to acquisition tax contingencies, stock option exercises, and other reflected in the table above relate primarily to settlements and adjustments 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.

All of our goodwill was 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. Our annual test for impairment of goodwill has historically been performed as of October 1 of each year. However, during the fourth quarter of 2008, there were severe disruptions in the capital and commodities markets that contributed to a significant decline in our common stock price. As a result, our equity market capitalization fell significantly below our net book value. Because this situation is an indicator that goodwill may be impaired, we performed an additional analysis to evaluate the potential impairment of our goodwill as of December 31, 2008. Based on this additional analysis, we determined that all of the goodwill in our four reporting units was impaired, which resulted in the recognition of a goodwill impairment loss of $4.1 billion ($4.0 billion after tax). For purposes of this goodwill impairment test, the fair value of each reporting unit was estimated based on the present value of expected future cash flows, with the present value determined using discount rates that reflected the risk inherent in the assets and risk premiums that reflected the volatility in the industry and the financial markets.

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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. Our ownership interest in NuStar Energy L.P. was 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.

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.

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Summary Financial Information
Financial information reported by NuStar Energy L.P. for the year ended December 31, 2006 is summarized below (in millions):

Revenues	$	1,136
Operating income		211
Net income		150

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 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 and result from events occurring or conditions existing prior to the date of sale.

Under a services agreement in existence during 2006, we provided NuStar Energy L.P. with certain corporate functions for an administrative fee, which 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.

The following table summarizes the results of transactions with NuStar Energy L.P. for the year ended December 31, 2006 (in millions):

Expenses charged by us to NuStar Energy L.P.	$	127
Fees and expenses charged to us by NuStar Energy L.P.		261

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 $438 million, $383 million, and $293 million for the years ended December 31, 2008, 2007, and 2006, respectively.

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Cameron Highway Oil Pipeline Project
We own a 50% interest in Cameron Highway Oil Pipeline Company, a general partnership formed to construct and operate a crude oil pipeline. The 390-mile crude oil pipeline 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 Cameron Highway Oil Pipeline Company 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. As of December 31, 2008 and 2007, our investment in Cameron Highway Oil Pipeline Company totaled $289 million and $297 million, respectively.

11. ACCRUED EXPENSES

Accrued expenses consisted of the following (in millions):

	December 31,
	2008		2007
Employee wage and benefit costs	$	169	$	258
Interest expense		66		79
Contingent earn-out obligations		–		25
Derivative liabilities		7		10
Environmental liabilities		42		55
Other		90		73
Accrued expenses	$	374	$	500

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. DEBT AND CAPITAL LEASE OBLIGATIONS

Debt balances, at stated values, and capital lease obligations consisted of the following (in millions):

			December 31,
	Maturity		2008			2007
Bank credit facilities	Various		$	–		$	–
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
3.50% notes		2009		200			200
4.75% notes		2013		300			300
4.75% notes		2014		200			200
6.125% notes		2017		750			750
6.625% notes		2037		1,500			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%		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
9.50% (callable)		2013		–			350
Other debt	Various			100			6
Net unamortized discount, including fair value adjustments				(68	)		(42	)
Total debt				6,537			6,819
Capital lease obligations, including unamortized fair value adjustments of $3 and $4				39			43
Total debt and capital lease obligations				6,576			6,862
Less current portion, including net unamortized premium of $- and $31				(312	)		(392	)
Debt and capital lease obligations, less current portion			$	6,264		$	6,470

(a) The maturity dates reflected for the Series 1997A, 1997B, and 1997C tax-exempt revenue refunding bonds represent their final maturity dates; however, principal payments on these bonds commence in 2010.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
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Bank Credit Facilities
We have a $2.5 billion revolving credit facility (the Revolver) that has a maturity date of November 2012. 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 non-bank debt. The Revolver also includes certain restrictive covenants including a debt-to-capitalization ratio. During the years ended December 31, 2008 and 2006, we borrowed and repaid $296 million and $830 million, respectively, under the Revolver. There were no borrowings under the Revolver during the year ended December 31, 2007. As of December 31, 2008 and 2007, there were no borrowings outstanding under the Revolver and outstanding letters of credit issued under this facility totaled $199 million and $292 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, 2008 and 2007, we had no borrowings outstanding under our Canadian credit facility and letters of credit issued under this credit facility totaled Cdn. $19 million and Cdn. $11 million, respectively.

In June 2008, we entered into a one-year committed revolving letter of credit facility under which we may obtain letters of credit of up to $300 million. In July 2008, we entered into another one-year committed revolving letter of credit facility under which we may obtain letters of credit of up to $275 million. Both of these credit facilities support certain of our crude oil purchases. We are being charged letter of credit issuance fees in connection with these letter of credit facilities. As of December 31, 2008, we had $232 million of outstanding letters of credit issued under these revolving credit facilities.

We also have various uncommitted short-term bank credit facilities. As of December 31, 2008 and 2007, we had no borrowings outstanding under our uncommitted short-term bank credit facilities; however, there were $201 million and $502 million, respectively, of letters of credit outstanding under such facilities for which we are charged letter of credit issuance fees. The uncommitted credit facilities have no commitment fees or compensating balance requirements.

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.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
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Non-Bank Debt
On February 1, 2008, we redeemed our 9.50% senior notes for $367 million, or 104.75% of stated value. These notes had a carrying amount of $381 million on the date of redemption, resulting in a gain of $14 million that was included in “other income, net” in the consolidated statement of income. In addition, in March 2008, we made a scheduled debt repayment of $7 million related to certain of our other 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.

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.

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.

Other Disclosures
Our revolving bank credit facilities and other debt arrangements contain various customary restrictive covenants, including cross-default and cross-acceleration clauses.

Principal payments due on debt as of December 31, 2008 were as follows (in millions):

2009	$	309
2010		33
2011		418
2012		759
2013		489
Thereafter		4,597
Net unamortized discount and fair value adjustments		(68	)
Total	$	6,537

For payments due on capital lease obligations, see Note 23.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of December 31, 2008 and 2007, the estimated fair value of our debt, including current portion, was as follows (in millions):

	December 31,
	2008		2007
Carrying amount	$	6,537	$	6,819
Fair value		6,462		7,109

13. OTHER LONG-TERM LIABILITIES

Other long-term liabilities consisted of the following (in millions):

	December 31,
	2008		2007
Employee benefit plan liabilities	$	1,047	$	701
Environmental liabilities		255		230
Tax liabilities for uncertain income tax positions		226		160
Other tax liabilities		189		163
Deferred gain on sale of assets to NuStar Energy L.P.		92		114
Insurance liabilities		90		86
Asset retirement obligations		72		70
Unfavorable lease obligations		38		51
Other		152		235
Other long-term liabilities	$	2,161	$	1,810

Employee benefit plan liabilities include the long-term obligation for our pension and other postretirement benefit plans as discussed in Note 21. Environmental liabilities reflect the long-term portion of our estimated remediation costs for environmental matters as discussed in Note 24. Tax liabilities for uncertain income tax positions reflect obligations under FIN 48 as discussed in Note 19 .. Other tax liabilities 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., which we recognize in income over the term of certain throughput and handling agreements with NuStar Energy L.P. (see Note 9). Insurance liabilities reflect reserves established by our captive insurance subsidiary, 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 and various contractual obligations.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
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The table below reflects the changes in our asset retirement obligations (in millions). See Note 1 under “Asset Retirement Obligations” for a discussion of the liability related to these obligations.

	Year Ended December 31,
	2008			2007			2006
Balance as of beginning of year	$	70		$	51		$	51
Additions to accrual		4			1			1
Accretion expense		3			2			2
Settlements		(4	)		(13	)		(5	)
Changes in timing and amount of estimated cash flows		–			28			2
Foreign currency translation		(1	)		1			–
Balance as of end of year	$	72		$	70		$	51

14. STOCKHOLDERS’ EQUITY

Share Activity
For the years ended December 31, 2008, 2007, and 2006, 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, 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	)
Shares repurchased under $6 billion common stock purchase program		–			–		(18	)
Shares repurchased, net of shares issued, in connection with employee stock plans and other		–			–		(2	)
Balance as of December 31, 2008		–			627		(111	)

Preferred Stock
We have 20 million shares of preferred stock authorized with a par value of $.01 per share. As of December 31, 2008 and 2007, 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. 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

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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, 3,164,151 shares of the preferred stock were converted into 6,271,327 shares of our common stock.

Prior to the issuance of shares of our common stock upon conversion of the convertible preferred stock, the number of shares of our common stock included in the calculation of “earnings per common share – assuming dilution” for each reporting period 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.

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).

On February 28, 2008, our board of directors approved a new $3 billion common stock purchase program. This program is in addition to the remaining amount under the $6 billion program previously authorized. This new $3 billion program has no expiration date. As of December 31, 2008, we had made no purchases of our common stock under the new $3 billion program. As of December 31, 2008, we have approvals under these stock purchase programs to purchase approximately $3.5 billion of our common stock.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During the years ended December 31, 2008, 2007, and 2006, we purchased 23.0 million, 84.3 million, and 34.6 million shares of our common stock, respectively, at a cost of $955 million, $5.8 billion, and $2.0 billion, respectively. These purchases were made in connection with the administration of our employee benefit plans and the $6 billion common 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, 2008, 2007, and 2006, we issued 2.5 million, 16.1 million, and 14.7 million shares from treasury, respectively, at an average cost of $65.85, $62.89, and $55.70 per share, respectively, for our employee benefit plans.

Common Stock Dividends
On January 20, 2009, our board of directors declared a quarterly cash dividend of $0.15 per common share payable March 11, 2009 to holders of record at the close of business on February 11, 2009.

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, 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
2008 change		(490	)		(411	)		152			(749	)
Balance as of December 31, 2008	$	90		$	(435	)	$	169		$	(176	)

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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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. EARNINGS (LOSS) PER SHARE

Earnings (loss) per common share amounts from continuing operations were computed as follows (dollars and shares in millions, except per share amounts):

	Year Ended December 31,
	2008			2007		2006
Earnings (loss) per common share from continuing operations:
Income (loss) from continuing operations	$	(1,131	)	$	4,565	$	5,287
Less: Preferred stock dividends		–			–		2
Income (loss) from continuing operations applicable to common stock	$	(1,131	)	$	4,565	$	5,285
Weighted-average common shares outstanding		524			565		611
Earnings (loss) per common share from continuing operations	$	(2.16	)	$	8.08	$	8.65
Earnings (loss) per common share from continuing operations – assuming dilution:
Income (loss) from continuing operations	$	(1,131	)	$	4,565	$	5,287
Less: Cash paid in final settlement of accelerated share repurchase program		–			94		–
Income (loss) from continuing operations assuming dilution	$	(1,131	)	$	4,471	$	5,287
Weighted-average common shares outstanding		524			565		611
Effect of dilutive securities (1):
Stock options		–			13		18
Restricted stock and performance awards		–			1		1
Mandatory convertible preferred stock		–			–		2
Weighted-average common shares outstanding – assuming dilution		524			579		632
Earnings (loss) per common share from continuing operations – assuming dilution	$	(2.16	)	$	7.72	$	8.36

(1) Common equivalent shares were excluded from the computation of diluted earnings per share for the year ended December 31, 2008 because the effect of including such shares would be anti-dilutive.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table reflects potentially dilutive securities that were excluded from the calculation of “earnings (loss) per common share from continuing operations – assuming dilution” as the effect of including such securities would have been anti-dilutive (in millions). For the year ended December 31, 2008, the common equivalent shares presented represent potentially dilutive securities, primarily stock options, that were excluded as a result of the net loss reported for 2008. For 2008, 2007, and 2006, the stock option amounts presented represent outstanding stock options for which the exercise prices were greater than the average market price of the common shares during each respective reporting period.

	Year Ended December 31,
	2008		2007		2006
Common equivalent shares		7		–		–
Stock options		7		2		–

16. STATEMENTS OF CASH FLOWS

In order to determine net cash provided by operating activities, net income (loss) is adjusted by, among other things, changes in current assets and current liabilities as follows (in millions):

	Year Ended December 31,
	2008			2007			2006
Decrease (increase) in current assets:
Restricted cash	$	(100	)	$	–		$	(1	)
Receivables, net		4,815			(3,227	)		(837	)
Inventories		(705	)		(249	)		(405	)
Income taxes receivable		(197	)		32			38
Prepaid expenses and other		(190	)		(58	)		(81	)
Increase (decrease) in current liabilities:
Accounts payable		(4,985	)		2,557			1,362
Accrued expenses		182			(20	)		(54	)
Taxes other than income taxes		(4	)		15			(4	)
Income taxes payable		(446	)		481			(162	)
Changes in current assets and current liabilities	$	(1,630	)	$	(469	)	$	(144	)

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 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;

• amounts accrued for common stock purchases in the open market that are not settled as of the balance sheet date are reflected in financing activities in the consolidated statements of cash flows when the purchases are settled and paid;

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

• changes in assets held for sale and liabilities related to assets held for sale pertaining to the operations of the Krotz Springs Refinery and the Lima Refinery prior to their sales are reflected in the line items to which the changes relate in the table above; 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 activities for the year ended December 31, 2008 included the contingent consideration received in the form of the earn-out agreement related to the sale of the Krotz Springs Refinery discussed in Note 2. Noncash investing activities for the years ended December 31, 2008 and 2007 included 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).

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.

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 statements of cash flows for the years ended December 31, 2007 and 2006. Cash provided by operating activities related to our discontinued operations was $260 million and $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.

Cash flows related to interest and income taxes were as follows (in millions):

	Year Ended December 31,
	2008		2007		2006
Interest paid (net of amount capitalized)	$	351	$	331	$	261
Income taxes paid, net of tax refunds received		1,428		2,014		2,349

17. FAIR VALUE MEASUREMENTS

As discussed in Note 1, we adopted Statement No. 159 effective January 1, 2008, but have not made any significant fair value elections with respect to any of our eligible assets or liabilities. Also as discussed in Note 1, effective January 1, 2008, we adopted Statement No. 157, which defines fair value, establishes a consistent framework for measuring fair value, establishes a fair value hierarchy (Level 1, Level 2, or Level 3) based on the quality of inputs used to measure fair value, and expands disclosure requirements for fair value measurements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Pursuant to the provisions of Statement No. 157, fair values determined by Level 1 inputs utilize quoted prices in active markets for identical assets or liabilities. Fair values determined by Level 2 inputs are based on quoted prices for similar assets or liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. We use appropriate valuation techniques based on the available inputs to measure the fair values of our applicable assets and liabilities. When available, we measure fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

The table below presents information (dollars in millions) about our assets and liabilities measured and recorded at fair value on a recurring basis and indicates the fair value hierarchy of the inputs utilized by us to determine the fair values as of December 31, 2008. These assets and liabilities have previously been measured and recorded at fair value in accordance with existing GAAP, and our accounting for these assets and liabilities was not impacted by our adoption of Statement No. 157 and Statement No. 159.

	Fair Value Measurements Using
	Quoted Prices		Significant Other		Significant
	in Active		Observable		Unobservable		Total as of
	Markets		Inputs		Inputs		December 31,
	(Level 1)		(Level 2)		(Level 3)		2008
Assets:
Commodity derivative contracts	$	40	$	610	$	–	$	650
Nonqualified benefit plans		98		–		–		98
Alon earn-out agreement		–		–		13		13
Liabilities:
Commodity derivative contracts		–		7		–		7
Certain nonqualified benefit plans		26		–		–		26

The valuation methods used to measure our financial instruments at fair value are as follows:

• Commodity derivative contracts, consisting primarily of exchange-traded futures and swaps, are measured at fair value using the market approach pursuant to the provisions of Statement No. 157. Exchange-traded futures are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy. Swaps are priced using third-party broker quotes, industry pricing services, and exchange-traded curves, but since they have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, these financial instruments are categorized in Level 2 of the fair value hierarchy.

• Nonqualified benefit plan assets and certain nonqualified benefit plan liabilities are measured at fair value using a market approach based on quotations from national securities exchanges and are categorized in Level 1 of the fair value hierarchy.

• The Alon earn-out agreement, which we received as partial consideration for the sale of our Krotz Springs Refinery as discussed in Note 2, is measured at fair value using a discounted cash flow model and is categorized in Level 3 of the fair value hierarchy. Significant inputs to the model include expected payments and discount rates that consider the effects of both credit risk and the time value of money.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

An $86 million obligation to pay cash collateral to brokers under master netting arrangements is netted against the fair value of the commodity derivatives reflected in Level 1. Certain of our commodity derivative contracts under master netting arrangements include both asset and liability positions. Under the guidance of FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39,” we have elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty, including any related cash collateral asset or obligation.

The following is a reconciliation of the beginning and ending balances (in millions) for fair value measurements developed using significant unobservable inputs for the year ended December 31, 2008.

Beginning balance	$	–
Alon earn-out agreement (see Note 2)		171
Net unrealized losses included in earnings		(158	)
Transfers in and/or out of Level 3		–
Balance as of December 31, 2008	$	13

Unrealized losses for the year ended December 31, 2008, which relate to a Level 3 asset still held at the reporting date, are reported in “other income, net” in the consolidated statement of income. These unrealized losses were more than offset by the recognition in “other income, net” of gains on derivative instruments entered into to hedge the risk of changes in the fair value of the Alon earn-out agreement as discussed in Note 2. These derivative instruments are included in the “commodity derivative contracts” amounts reflected in the fair value table above.

18. PRICE RISK MANAGEMENT ACTIVITIES

Commodity Price Risk
We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refining operations. To reduce the impact of this price volatility, we use derivative commodity instruments (swaps, futures, and options) to manage our exposure to:

• changes in the fair value of a portion of our refinery feedstock and refined product inventories and a portion of our unrecognized firm commitments to purchase these inventories (fair value hedges);

• changes in cash flows of certain forecasted transactions such as forecasted feedstock and product purchases, natural gas purchases, and refined product sales (cash flow hedges); and

• price volatility on a portion of our refinery feedstock and refined product inventories and on certain forecasted feedstock and product purchases, refined product sales, and natural gas purchases that are not designated as either fair value or cash flow hedges (economic hedges).

In addition, we use derivative commodity instruments for trading purposes based on our fundamental and technical analysis of market conditions.

Interest Rate Risk
We are exposed to market risk for changes in interest rates related to certain of our 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, 2008 and 2007, we did not have any interest rate swap agreements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 2008, we had commitments to purchase $280 million of U.S. dollars. These commitments matured on or before January 30, 2009, resulting in a 2009 gain 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,
	2008			2007			2006
Fair value hedges	$	4		$	(17	)	$	(11	)
Cash flow hedges		(11	)		(18	)		8

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 2008, 2007, and 2006, we recognized in “cost of sales” gains of $13 million, $37 million, and $4 million, respectively, associated with trading activities.

For cash flow hedges, gains and losses reported in “accumulated other comprehensive income (loss)” in the consolidated balance sheets are reclassified into “cost of sales” when the forecasted transactions affect income. During the years ended December 31, 2008, 2007, and 2006, we recognized in “other comprehensive income (loss)” unrealized after-tax gains (losses) of $85 million, $(11) million, and $70 million, respectively, on certain cash flow hedges, primarily related to forward sales of gasoline and distillates and associated forward purchases of crude oil, with $169 million, $17 million, and $45 million of cumulative after-tax gains on cash flow hedges remaining in “accumulated other comprehensive income (loss)” as of December 31, 2008, 2007, and 2006, respectively. We expect that substantially all of the deferred gains at December 31, 2008 will be reclassified into “cost of sales” over the next 12 months 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, 2008, 2007, and 2006, there were no amounts reclassified from “accumulated other comprehensive income (loss)” into income as a result of the discontinuance of cash flow hedge accounting.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Market and Credit Risk
Our price risk management activities involve the receipt or payment of fixed price commitments into the future. These transactions give rise to market risk, the risk that future changes in market conditions may make an instrument less valuable. We closely monitor and manage our exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Market risks are monitored by a risk control group to ensure compliance with our stated risk management policy. Concentrations of customers in the refining industry may impact our overall exposure to credit risk, in that these customers may be similarly affected by changes in economic or other conditions. In addition, financial services companies are the counterparties in certain of our price risk management activities, and such financial services companies may be adversely affected by periods of uncertainty and illiquidity in the credit and capital markets.

19. INCOME TAXES

Income (loss) from continuing operations before income tax expense from domestic and foreign operations was as follows (in millions):

	Year Ended December 31,
	2008			2007		2006
U.S. operations	$	(255	)	$	5,846	$	7,290
Canadian operations		605			458		289
Aruban operations		(14	)		422		319
Income from continuing operations before income tax expense	$	336		$	6,726	$	7,898

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,
	2008			2007			2006
Federal income tax expense at the U.S. statutory rate	$	118		$	2,354		$	2,764
U.S. state income tax expense, net of U.S. federal income tax effect		4			83			46
U.S. manufacturing deduction		(53	)		(88	)		(71	)
Canadian operations		(27	)		(48	)		(45	)
Aruban operations		7			(144	)		(108	)
Goodwill impairment		1,367			–			–
Permanent differences		26			16			9
Other, net		25			(12	)		16
Income tax expense	$	1,467		$	2,161		$	2,611

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 had an immaterial effect on our consolidated results of operations for the years ended December 31, 2008, 2007, and 2006.

99

VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Components of income tax expense (benefit) related to continuing operations were as follows (in millions):

	Year Ended December 31,
	2008			2007			2006
Current:
U.S. federal	$	732		$	1,764		$	2,198
U.S. state		13			96			76
Canada		45			202			51
Aruba		2			3			3
Total current		792			2,065			2,328
Deferred:
U.S. federal		543			155			285
U.S. state		(8	)		31			(5	)
Canada		140			(90	)		3
Total deferred		675			96			283
Income tax expense	$	1,467		$	2,161		$	2,611

The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows (in millions):

	December 31,
	2008			2007
Deferred income tax assets:
Tax credit carryforwards	$	91		$	95
Net operating losses (NOL)		78			36
Compensation and employee benefit liabilities		394			175
Environmental		93			86
Inventories		72			224
Other assets		298			360
Total deferred income tax assets		1,026			976
Less: Valuation allowance		(62	)		(54	)
Net deferred income tax assets		964			922
Deferred income tax liabilities:
Turnarounds		(250	)		(264	)
Property, plant and equipment		(4,530	)		(4,297	)
Inventories		(628	)		(302	)
Other		(106	)		(126	)
Total deferred income tax liabilities		(5,514	)		(4,989	)
Net deferred income tax liabilities	$	(4,550	)	$	(4,067	)

100

VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of December 31, 2008, 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	$	57	2009 through 2029
U.S. state income tax credits		36	Unlimited
Foreign tax credit		30	2011
U.S. state NOL		1,606	2009 through 2028

We have recorded a valuation allowance as of December 31, 2008 and 2007, 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, 2008 is primarily dependent upon our ability to generate future taxable income in certain states and foreign source income in the United States.

Subsequently recognized tax benefits related to the valuation allowance for deferred income tax assets as of December 31, 2008 will be allocated as follows (in millions):

Income tax benefit in consolidated statement of income	$	57
Additional paid-in capital		5
Total	$	62

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, 2008, 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.

101

VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following is a reconciliation of the change in unrecognized tax benefits (in millions):

	Year Ended December 31,
	2008			2007
Balance as of beginning of year	$	164		$	160
Additions based on tax positions related to the current year		17			32
Additions for tax positions related to prior years		67			13
Reductions for tax positions related to prior years		(5	)		(36	)
Reductions for tax positions related to the lapse of applicable statute of limitations		(5	)		–
Settlements		–			(5	)
Balance as of end of year	$	238		$	164

Included in the balance as of December 31, 2008 and 2007 are $136 million and $65 million, respectively, 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, 2008, 2007, and 2006, we recognized approximately $22 million, $1 million, and $25 million in interest and penalties. We had accrued approximately $68 million and $46 million for the payment of interest and penalties as of December 31, 2008 and 2007, respectively.

Our tax years through 1999 and UDS’s tax years through 2001 are closed to adjustment by the Internal Revenue Service.  Valero’s separate tax years 2000 and 2001 (prior to the UDS Acquisition) have been settled with the exception of a depreciation method.  In addition, our tax years 2002 through 2005 are currently under examination and Premcor’s separate tax years 2004 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. During 2008, Valero settled Premcor’s 2002-2003 separate tax year audit. We believe that adequate provisions for income taxes have been reflected in the consolidated financial statements.

20. SEGMENT INFORMATION

We have two reportable segments, refining and retail. Our refining segment includes refining operations, wholesale marketing, product supply and distribution, and transportation operations. The retail segment includes company-operated convenience stores, Canadian dealers/jobbers and truckstop facilities, cardlock facilities, and home heating oil operations. Operations that are not included in either of the two reportable segments are included in the corporate category.

The reportable segments are strategic business units that offer different products and services. They are managed separately as each business requires unique technology and marketing strategies. Performance is evaluated based on operating income. Intersegment sales are generally derived from transactions made at prevailing market rates.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Refining		Retail		Corporate			Total
Year ended December 31, 2008:	(in millions)
Operating revenues from external customers	$	108,586	$	10,528	$	–		$	119,114
Intersegment revenues		7,703		–		–			7,703
Depreciation and amortization expense		1,327		105		44			1,476
Operating income (loss)		797		369		(603	)		563
Total expenditures for long-lived assets		2,957		104		141			3,202
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

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. Other product revenues 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, 2008, 2007, and 2006 were as follows (in millions):

	Year Ended December 31,
	2008		2007		2006
Refining:
Gasolines and blendstocks	$	48,052	$	43,014	$	40,458
Distillates		45,672		31,552		28,524
Petrochemicals		4,221		3,797		3,254
Lubes and asphalts		2,770		1,837		1,863
Other product revenues		7,871		6,243		5,307
Total refining operating revenues		108,586		86,443		79,406
Retail:
Fuel sales (gasoline and diesel)		8,750		7,235		6,709
Merchandise sales and other		1,446		1,356		1,272
Home heating oil		332		293		253
Total retail operating revenues		10,528		8,884		8,234
Consolidated operating revenues	$	119,114	$	95,327	$	87,640

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Operating revenues by geographic area for the years ended December 31, 2008, 2007, and 2006 are shown in the table below (in millions). The geographic area is based on location of customer.

	Year Ended December 31,
	2008		2007		2006
United States	$	101,141	$	82,168	$	76,604
Canada		9,961		8,142		7,275
Other countries		8,012		5,017		3,761
Consolidated operating revenues	$	119,114	$	95,327	$	87,640

For the years ended December 31, 2008, 2007, and 2006, no customer accounted for more than 10% of our consolidated operating revenues.

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,
	2008		2007
United States	$	21,327	$	19,438
Canada		1,999		2,412
Aruba		1,045		972
Consolidated long-lived assets	$	24,371	$	22,822

Total assets by reportable segment were as follows (in millions):

	December 31,
	2008		2007
Refining	$	30,801	$	37,703
Retail		1,818		2,098
Corporate		1,798		2,921
Total consolidated assets	$	34,417	$	42,722

The entire balance of goodwill as of December 31, 2007 was included in the total assets of the refining reportable segment. As of December 31, 2008, we no longer reflected any goodwill in our consolidated balance sheet due to the goodwill impairment loss in the fourth quarter of 2008 (see discussion in Note 8). Assets held for sale related to the Krotz Springs Refinery as of December 31, 2007 were included in the refining reportable segment.

21. EMPLOYEE BENEFIT PLANS

Pension Plans and Postretirement Benefits Other Than Pensions
We have several qualified non-contributory defined benefit pension 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

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, 2008 and 2007 were as follows (in millions):

							Other Postretirement
	Pension Plans						Benefit Plans
	2008			2007			2008			2007
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,292		$	1,252		$	477		$	477
Service cost		92			95			13			13
Interest cost		76			71			28			27
Participant contributions		–			–			7			7
Plan amendments		–			(1	)		–			–
Special termination benefits		–			14			–			1
Medicare subsidy for prescription drugs		–			–			2			1
Benefits paid		(75	)		(78	)		(27	)		(20	)
Actuarial (gain) loss		107			(61	)		26			(34	)
Foreign currency exchange rate changes		–			–			(6	)		5
Benefit obligation at end of year	$	1,492		$	1,292		$	520		$	477
Change in plan assets:
Fair value of plan assets at beginning of year	$	1,358		$	1,156		$	–		$	–
Actual return on plan assets		(400	)		125			–			–
Valero contributions		122			155			18			12
Participant contributions		–			–			7			7
Medicare subsidy for prescription drugs		–			–			2			1
Benefits paid		(75	)		(78	)		(27	)		(20	)
Fair value of plan assets at end of year	$	1,005		$	1,358		$	–		$	–
Reconciliation of funded status:
Fair value of plan assets at end of year	$	1,005		$	1,358		$	–		$	–
Less: Benefit obligation at end of year		1,492			1,292			520			477
Funded status at end of year	$	(487	)	$	66		$	(520	)	$	(477	)

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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, 2008 and 2007 were as follows (in millions):

							Other Postretirement
	Pension Plans						Benefit Plans
	2008			2007			2008			2007
Deferred charges and other assets	$	–		$	239		$	–		$	–
Accrued expenses		(13	)		(13	)		(22	)		(18	)
Other long-term liabilities		(474	)		(160	)		(498	)		(459	)
Accumulated other comprehensive loss		645			38			43			13

The pre-tax amounts in “accumulated other comprehensive (income) loss” as of December 31, 2008 and 2007 that have not yet been recognized as components of net periodic benefit cost were as follows (in millions):

					Other Postretirement
	Pension Plans				Benefit Plans
	2008		2007		2008			2007
Prior service cost (credit)	$	19	$	22	$	(84	)	$	(93	)
Net actuarial loss		626		16		127			106
Total	$	645	$	38	$	43		$	13

The following amounts included in “accumulated other comprehensive income (loss)” as of December 31, 2008 are expected to be recognized as components of net periodic benefit cost during the year ending December 31, 2009 (in millions):

			Other
	Pension		Postretirement
	Plans		Benefit Plans
Amortization of prior service cost (credit)	$	3	$	(9	)
Amortization of loss		10		6
Total	$	13	$	(3	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of December 31, 2008 and 2007, the accumulated benefit obligation for our Pension Plans was $1.2 billion and $1.0 billion, respectively. With the exception of our main Qualified Plan as of December 31, 2007, which was overfunded at that date, the accumulated benefit obligation for each of our Pension Plans was in excess of the fair value of plan assets as of December 31, 2008 and 2007. The fair value of plan assets for our main Qualified Plan was in excess of the projected benefit obligation and the accumulated benefit obligation by $239 million and $464 million, respectively, as of December 31, 2007. However, due primarily to a significant decline in the fair value of the assets of the main Qualified Plan caused by unfavorable economic and market conditions during 2008, our main Qualified Plan was underfunded as of December 31, 2008, thus resulting in the increased amounts reflected in the table below. The aggregate projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for our Pension Plans for which the accumulated benefit obligation exceeded the fair value of plan assets were as follows (in millions):

	December 31,
	2008		2007
Projected benefit obligation	$	1,492	$	232
Accumulated benefit obligation		1,201		192
Fair value of plan assets		1,005		59

The percentage of fair value of plan assets by asset category for the Qualified Plans as of December 31, 2008 and 2007 are shown below. There are no plan assets for other postretirement benefit plans.

	December 31,
	2008			2007
Equity securities		48	%		50	%
Mutual funds		11			22
Corporate debt securities		16			9
Government securities		17			8
Insurance contracts		2			1
Cash and cash equivalents		6			10
Total		100	%		100	%

Equity securities in the Qualified Plans include our common stock in the amounts of approximately $20 million (2% of total Qualified Plan assets) and $55 million (4% of total Qualified Plan assets) as of December 31, 2008 and 2007, respectively.

The investment policies and strategies for the assets of our Qualified Plans incorporate a diversified approach that is expected to earn long-term returns from capital appreciation and a growing stream of current income. This approach recognizes that assets are exposed to risk and the market value of the Qualified Plans’ assets may fluctuate from year to year. Risk tolerance is determined based on our financial ability to withstand risk within the investment program and the willingness to accept return volatility. In line with the investment return objective and risk parameters, the Qualified Plans’ mix of assets includes a diversified portfolio of equity and fixed-income investments. Equity investments include international stocks and a blend of domestic growth and value stocks of various sizes of capitalization. The aggregate asset allocation is reviewed on an annual basis.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The overall expected long-term rate of return on plan assets for the Qualified Plans is estimated using models of asset returns. Model assumptions are derived using historical data given the assumption that capital markets are informationally efficient. Three methods are used to derive the long-term expected returns for each asset class. Because each method has distinct advantages and disadvantages and differing results, an equal weighted average of the methods’ results is used.

Although we have only $8 million of minimum required contributions to our Qualified Plans during 2009 under the Employee Retirement Income Security Act, we plan to contribute approximately $130 million to our Qualified Plans during 2009. In January 2009, $50 million of this total expected contribution was contributed to our main Qualified Plan.

The following benefit payments, which reflect expected future service and anticipated Medicare subsidy, as appropriate, are expected to be paid (received) for the years ending December 31 (in millions):

	Pension		Other		Health Care
	Benefits		Benefits		Subsidy Receipts
2009	$	63	$	24	$	(2	)
2010		72		27		(3	)
2011		76		30		(3	)
2012		85		32		(3	)
2013		97		34		(4	)
Years 2014-2018		647		204		(27	)

The components of net periodic benefit cost were as follows for the years ended December 31, 2008, 2007, and 2006 (in millions):

										Other Postretirement
	Pension Plans									Benefit Plans
	2008			2007			2006			2008			2007			2006
Components of net periodic benefit cost:
Service cost	$	92		$	95		$	96		$	13		$	13		$	14
Interest cost		76			71			64			28			27			24
Expected return on plan assets		(105	)		(84	)		(57	)		–			–			–
Amortization of:
Prior service cost (credit)		3			3			3			(9	)		(9	)		(9	)
Net loss		2			9			13			3			6			6
Net periodic benefit cost before special charges		68			94			119			35			37			35
Charge for special termination benefits		–			14			–			–			1			–
Net periodic benefit cost	$	68		$	108		$	119		$	35		$	38		$	35

Amortization of prior service cost (credit) shown in the above table was based on the average remaining service period of employees expected to receive benefits under each respective plan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Pre-tax amounts recognized in “other comprehensive (income) loss” for the years ended December 31, 2008 and 2007 were as follows (in millions):

							Other Postretirement
	Pension Plans						Benefit Plans
	2008			2007			2008			2007
Net (gain) loss arising during the year:
Net actuarial loss (gain)	$	612		$	(102	)	$	25		$	(33	)
Prior service cost (credit)		–			(1	)		–			–
Net gain (loss) reclassified into income:
Net actuarial (loss) gain		(2	)		(9	)		(3	)		(6	)
Prior service (cost) credit		(3	)		(3	)		9			9
Total recognized in other comprehensive (income) loss	$	607		$	(115	)	$	31		$	(30	)

The pre-tax increase in the additional minimum pension liability that was recognized in “other comprehensive income (loss)” was $1 million for the year ended December 31, 2006.

The weighted-average assumptions used to determine the benefit obligations as of December 31, 2008 and 2007 were as follows:

							Other Postretirement
	Pension Plans						Benefit Plans
	2008			2007			2008			2007
Discount rate		5.40	%		6.00	%		5.39	%		6.00	%
Rate of compensation increase		5.19	%		5.43	%		–			–

The discount rate assumptions used to determine the pension plan and other postretirement benefit plan obligations at December 31, 2008 were based on the Hewitt Bond Universe yield curve (HBU). The HBU was designed by Hewitt Associates LLC to provide a means for plan sponsors to value the liabilities of their pension plans and other postretirement benefit plans. The HBU is a hypothetical yield curve represented by a series of annualized individual discount rates for certain high-yield bonds. Each bond issue underlying the HBU is required to have a rating of Aa or better by Moody’s Investors Service or a rating of AA or better by Standard & Poor’s Ratings Services.

Prior to 2008, we selected the discount rate based on a review of long-term bonds that received one of the two highest ratings given by a recognized rating agency as of December 31 of each year. The average timing of benefit payments from our plans was compared to the average timing of cash flows from the long-term bonds to assess potential timing adjustments. Based on this analysis, there were no significant differences in the timing of the cash flows, and therefore no adjustments were necessary.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The weighted-average assumptions used to determine the net periodic benefit cost for the years ended December 31, 2008, 2007, and 2006 were as follows:

										Other Postretirement
	Pension Plans									Benefit Plans
	2008			2007			2006			2008			2007			2006
Discount rate		6.00	%		5.75	%		5.50	%		6.00	%		5.75	%		5.50	%
Expected long-term rate of return on plan assets		8.23	%		8.25	%		8.25	%		–			–			–
Rate of compensation increase		5.43	%		5.46	%		4.75	%		–			–			–

The assumed health care cost trend rates as of December 31, 2008 and 2007 were as follows:

	2008			2007
Health care cost trend rate assumed for next year		8.30	%		8.87	%
Rate to which the cost trend rate was assumed to decline (the ultimate trend rate)		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate		2015			2015

Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one percentage-point change in assumed health care cost trend rates would have the following effects on other postretirement benefits (in millions):

	1% Increase		1% Decrease
Effect on total of service and interest cost components	$	3	$	(3	)
Effect on accumulated postretirement benefit obligation		37		(32	)

Defined Contribution Plans
Valero Energy Corporation Thrift Plan
We are the sponsor of the Valero Energy Corporation Thrift Plan, which is a defined contribution plan. Participation in the Thrift Plan is voluntary. Through June 30, 2006, employees were eligible to participate in the plan upon the completion of one month of continuous service. Effective July 1, 2006, participants may participate in the plan as soon as practicable following enrollment.

Thrift Plan participants can make basic contributions up to 8% of their total annual salary, which includes overtime and cash bonuses. In addition, participants who make a basic contribution of 8% can also make a supplemental contribution of up to 22% of their total annual salary. We match 75% of each participant’s total basic contributions up to 8% based on the participant’s total annual salary, excluding cash bonuses.

Our contributions to the Thrift Plan for the years ended December 31, 2008, 2007, and 2006 were $38 million, $38 million, and $37 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Valero Savings Plan
The Valero Savings Plan is a defined contribution plan covering our retail store employees and certain other employees supporting the retail organization. Under the Valero Savings Plan, participants can contribute from 1% to 30% of their compensation. We contribute $0.60 for every $1.00 of the participant’s contribution up to 6% of compensation.

Our contributions to the Valero Savings Plan were $5 million for each of the years ended December 31, 2008, 2007, and 2006.

Premcor Retirement Savings Plan
The Premcor Retirement Savings Plan is a defined contribution plan covering former Premcor employees who became employees of Valero effective September 1, 2005. Under this plan, participants can contribute from 1% to 50% of their eligible compensation. We contribute 200% of the first 3% of a participant’s pre-tax contribution. In addition, we contribute 100% of a participant’s pre-tax contribution above 3% up to 6% for certain union participants who contribute to the plan.

Our contributions to the Premcor Retirement Savings Plan for the years ended December 31, 2008, 2007, and 2006 were $6 million, $7 million, and $9 million, respectively.

22. STOCK-BASED COMPENSATION

As discussed in Note 1, on January 1, 2006, we adopted Statement No. 123(R), which requires the expensing of the fair value of stock compensation awards.

We have various fixed and performance-based stock compensation plans under which awards have been granted, which are summarized as follows:

• The 2005 Omnibus Stock Incentive Plan (the OSIP) authorizes the grant of various stock and stock-based awards to our employees and our non-employee directors. Awards available under the OSIP include options to purchase shares of common stock, performance awards that vest upon the achievement of an objective performance goal, and restricted stock that vests over a period determined by our compensation committee. As of December 31, 2008, a total of 15,988,740 shares of our common stock remained available to be awarded under the OSIP.

• A non-employee director stock option plan provided our non-employee directors with grants of stock options to purchase our common stock. Effective January 1, 2007, each director was granted an option to purchase 10,000 shares of our common stock upon initial election to our board of directors. Prior to January 1, 2007, the plan provided automatic grants of stock options upon their election to our board of directors and annual grants of stock options upon their continued service on the board. These options expire seven years from the date of grant. Effective April 23, 2007, no further options may be granted under this plan; subsequent option grants are made under the OSIP.

• Through December 31, 2006, our restricted stock plan for non-employee directors provided non-employee directors, upon their election to the board of directors, a grant of our common stock valued at $60,000 that vested in three equal annual installments. Effective January 1, 2007, each non-employee director received an annual grant of our common stock valued at $80,000 that vested in three equal annual installments. Effective January 1, 2008, each non-employee director receives an annual grant of our common stock valued at $160,000. Vesting will occur based on the number of grants received as follows: (i) initial grants will vest in three equal annual

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

installments, (ii) second grants will vest one-third on the first anniversary of the grant date and the remaining two-thirds on the second anniversary of the grant date, and (iii) all grants thereafter will vest 100% on the first anniversary of the grant date. As of December 31, 2008, a total of 218,617 shares of our common stock remained available to be awarded under this plan.

•

The 2003 Employee Stock Incentive Plan authorizes the grant of various stock and stock-related awards to employees and prospective employees. Awards include options to purchase shares of common stock, performance awards that vest upon the achievement of an objective performance goal, stock appreciation rights, and restricted stock that vests over a period determined by our compensation committee. As of December 31, 2008, a total of 148,285 shares of our common stock remained available to be awarded under this plan.

In addition, we formerly maintained other stock option and incentive plans under which previously granted equity awards remain outstanding. No additional grants may be awarded under these plans.

Each of our current stock-based compensation arrangements is discussed below. The tax benefit realized for tax deductions resulting from exercises and vestings under all of our stock-based compensation arrangements totaled $17 million, $313 million, and $264 million for the years ended December 31, 2008, 2007, and 2006, respectively.

Stock Options
Under the terms of our various stock option plans, the exercise price of options granted is not less than the fair market value of our common stock on the date of grant. Stock options become exercisable pursuant to the individual written agreements between the participants and us, usually in three or five equal annual installments beginning one year after the date of grant, with unexercised options generally expiring seven or ten years from the date of grant.

The fair value of each stock option grant was estimated on the grant date using the Black-Scholes option-pricing model. The expected life of options granted is the period of time from the grant date to the date of expected exercise or other expected settlement. The expected life for each of the years in the table below was calculated using the safe harbor provisions of SEC Staff Accounting Bulletin No. 107 and No. 110 related to share-based payments. Because the vesting period for almost all of the stock options granted during the year ended December 31, 2008 was three years rather than five years as in the prior periods presented, historical exercise patterns do not provide a reasonable basis for estimating the expected life. Expected volatility is based on closing prices of our common stock for periods corresponding to the expected life of options granted. Expected dividend yield is based on annualized dividends at the date of grant. The risk-free interest rate used is the implied yield currently available from the U.S. Treasury zero-coupon issues with a remaining term equal to the expected life of the options at the grant date. A summary of the weighted-average assumptions used in our fair value measurements is presented in the table below:

	Year Ended December 31,
	2008			2007			2006
Expected life in years		4.5			5.0			5.0
Expected volatility		43.2	%		33.7	%		36.3	%
Expected dividend yield		3.5	%		0.7	%		0.6	%
Risk-free interest rate		2.8	%		4.0	%		4.7	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

A summary of the status of our stock option awards is presented in the table below.

				Weighted-		Weighted-
				Average		Average
	Number			Exercise		Remaining		Aggregate
	of Stock			Price		Contractual		Intrinsic
	Options			Per Share		Term		Value
						(in years)		(in millions)
Outstanding at January 1, 2008		23,178,212		$	25.41
Granted		3,752,075			17.17
Exercised		(1,506,387	)		10.93
Forfeited		(354,347	)		46.00
Outstanding at December 31, 2008		25,069,553			24.76		4.6	$	153
Exercisable at December 31, 2008		16,565,130			18.81		4.0		136

The weighted-average grant-date fair value of stock options granted during the years ended December 31, 2008, 2007, and 2006 was $5.03, $24.51, and $19.76 per stock option, respectively. The total intrinsic value of stock options exercised during the years ended December 31, 2008, 2007, and 2006 was $47 million, $881 million, and $385 million, respectively. Cash received from stock option exercises for the years ended December 31, 2008, 2007, and 2006 was $16 million, $130 million, and $77 million, respectively.

As of December 31, 2008, there was $58 million of unrecognized compensation cost related to outstanding unvested stock option awards, which is expected to be recognized over a weighted-average period of approximately three years.

Restricted Stock
Restricted stock is granted to employees and non-employee directors. Restricted stock granted to employees vests in accordance with individual written agreements between the participants and us, usually in equal annual installments over a period of five years beginning one year after the date of grant. Restricted stock granted to our non-employee directors vests from one to three years following the date of grant. A summary of the status of our restricted stock awards is presented in the table below.

				Weighted-
				Average
				Grant-Date
	Number of			Fair Value
	Shares			Per Share
Nonvested shares at January 1, 2008		1,394,075		$	49.63
Granted		989,491			18.14
Vested		(522,645	)		39.72
Forfeited		(31,626	)		51.09
Nonvested shares at December 31, 2008		1,829,295			35.41

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of December 31, 2008, there was $43 million of unrecognized compensation cost related to outstanding unvested restricted stock awards, which is expected to be recognized over a weighted-average period of approximately three years. The total fair value of restricted stock that vested during the years ended December 31, 2008, 2007, and 2006 was $12 million, $44 million, and $24 million, respectively.

Performance Awards
In 2007 and 2006, we issued to certain key employees performance awards, which represent rights to receive shares of Valero common stock only upon Valero’s achievement of an objective performance measure. Performance awards are subject to vesting in three annual amounts beginning approximately one year after the date of grant. The number of common shares earned each year is based on the vested award adjusted by a factor determined by our total shareholder return over a rolling three-year period compared to the total shareholder return of a defined peer group for the same time period.

During the year ended December 31, 2008, no performance awards were issued or forfeited. The fair value of performance awards subject to vesting for the year ended December 31, 2008 was based on an expected conversion to common shares at a rate of 100% and a weighted-average fair value of $70.97 per share, representing the market price of our common stock on the grant date reduced by expected dividends over the vesting period. The total fair value of performance awards that vested during the years ended December 31, 2008, 2007, and 2006 was $4 million, $11 million, and $263 million, respectively.

Restricted Stock Units
As of December 31, 2008, 98,688 unvested restricted stock units were outstanding. Restricted stock units vest in equal annual amounts over a three-year or five-year period beginning one year after the date of grant. These restricted stock units are payable in cash based on the price of our common stock on the date of vesting, and therefore they are accounted for as liability-based awards. For the years ended December 31, 2008, 2007, and 2006, cash payments of $1 million, $8 million, and $25 million, respectively, were made for vested restricted stock units. During the year ended December 31, 2008, 29,530 restricted stock units were granted, 31,218 units vested, and 436 units were forfeited. Based on the price of our common stock on December 31, 2008, there was $1 million of unrecognized compensation cost related to outstanding unvested restricted stock units, which is expected to be recognized over a weighted-average period of approximately four years.

23. COMMITMENTS AND CONTINGENCIES

Leases
We have long-term operating lease commitments for land, office facilities, retail facilities and related equipment, transportation equipment, time charters for ocean-going tankers and coastal vessels, dock facilities, and various facilities and equipment used in the storage, transportation, production, and sale of refinery feedstocks and refined products.

Certain leases for processing equipment and feedstock and refined product storage facilities provide for various contingent payments based on, among other things, throughput volumes in excess of a base amount. Certain leases for vessels contain renewal options and escalation clauses, which vary by charter, and provisions for the payment of chartering fees, which either vary based on usage or provide for payments, in addition to established minimums, that are contingent on usage. Leases for convenience stores may also include provisions for contingent rental payments based on sales volumes. In most cases, we expect that in the normal course of business, our leases will be renewed or replaced by other leases.

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As of December 31, 2008, our future minimum rentals and minimum rentals to be received under subleases for leases having initial or remaining noncancelable lease terms in excess of one year were as reflected in the following table (in millions).

	Operating			Capital
	Leases			Leases
2009	$	397		$	6
2010		282			6
2011		179			6
2012		90			6
2013		55			6
Remainder		270			22
Total minimum rental payments		1,273			52
Less minimum rentals to be received under subleases		(24	)		–
Net minimum rental payments	$	1,249			52
Less interest expense					(13	)
Capital lease obligations				$	39

Consolidated rental expense for all operating leases was as follows (in millions):

	Year Ended December 31,
	2008			2007			2006
Minimum rental expense	$	554		$	552		$	545
Contingent rental expense		23			24			22
Total rental expense		577			576			567
Less sublease rental income		(4	)		(4	)		(4	)
Net rental expense	$	573		$	572		$	563

Other Commitments
We have various purchase obligations under certain industrial gas and chemical supply arrangements (such as hydrogen supply arrangements), crude oil and other feedstock supply arrangements, and various throughput and terminalling agreements. We enter into these contracts to ensure an adequate supply of utilities 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. None of these obligations are associated with suppliers’ financing arrangements. These purchase obligations are not reflected in the consolidated balance sheets.

Contingent Earn-Out Agreements
In connection with our acquisitions of Basis Petroleum, Inc. in 1997 and the St. Charles Refinery in 2003, the sellers were entitled to receive payments in any of the ten and seven years, respectively, following these acquisitions if certain average refining margins during any of those years exceeded a specified level. In connection with the Premcor Acquisition in 2005, we assumed Premcor’s obligation under a contingent earn-out agreement related to Premcor’s acquisition of the Delaware City Refinery from Motiva Enterprises LLC (Motiva). Under this agreement, Motiva was entitled to receive two separate annual earn-out payments depending on (a) the amount of crude oil processed at the refinery and the level of

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refining margins through May 2007, and (b) the achievement of certain performance criteria at the gasification facility through May 2006. As described below, final payments under all of these agreements have been made, and, consequently, our obligations have been fulfilled under the agreements.

The following table summarizes the aggregate payments we had made through December 31, 2008 and payment limitations related to the following acquisitions (in millions). The amounts reflected for the Delaware City Refinery represent amounts applicable only to the throughput/margin earn-out contingency because the earn-out contingency related to the refinery’s gasification facility expired during the second quarter of 2006 with no payment required. The amounts reflected represent only amounts for which we were liable subsequent to the Premcor Acquisition.

	Basis				Delaware
	Petroleum,		St. Charles		City
	Inc.		Refinery		Refinery
Payments made during the year ended December 31:
2006	$	26	$	50	$	25
2007		–		50		25
2008		–		25		–
Aggregate payments made through 2008		200		175		50
Annual maximum limit		35		50		25
Aggregate limit		200		175		50

For the acquisition of Basis Petroleum, Inc., we accounted for payments under this arrangement as an additional cost of the acquisition when the payments were made. Of the aggregate payments made related to this acquisition, $47 million was attributed to “property, plant and equipment” and is being depreciated over the remaining lives of the assets to which the additional cost was allocated and $153 million was attributed to “goodwill.” A final payment under this agreement was made in May 2006.

As part of the purchase price allocation related to the acquisition of the St. Charles Refinery, a liability was accrued for the aggregate limit of potential earn-out payments totaling $175 million. The offsetting amount was reflected in “property, plant and equipment” and is being depreciated over the remaining lives of the assets to which the cost was allocated. In January 2008, we made a final earn-out payment of $25 million related to the acquisition of the St. Charles Refinery.

In connection with the Premcor Acquisition, a liability of $50 million was accrued as of September 1, 2005 as we believed it was probable that the maximum payments would be made related to the Delaware City Refinery margin contingency. The offsetting amount was recorded in “goodwill.” A final payment under this agreement was made in June 2007.

In July 2008, we received contingent consideration in the form of a three-year earn-out agreement from Alon related to the sale of our Krotz Springs Refinery (as discussed in Note 2 and Note 17).

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Insurance Recoveries
During the third quarter of 2005, certain of our refineries experienced property damage and business interruption losses associated with Hurricanes Katrina and Rita. As a result of these losses, we submitted claims to our insurance carriers under our insurance policies. During 2006, we reached a final business interruption settlement with our insurance carriers, the proceeds from which were recorded as a reduction to “cost of sales.” The amount received was immaterial to our results of operations and financial position.

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 submitted claims to our insurance carriers under our insurance policies. We reached a settlement with the insurance carriers on our claims, resulting in pre-tax income of approximately $100 million in the first quarter of 2008 that was recorded as a reduction to “cost of sales.”

Tax Matters
We are subject to extensive tax liabilities, including federal, state, and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise, withholding, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. 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 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. Accordingly, no expense or liability has been recognized in our consolidated financial statements with respect to this turnover tax on exports. We commenced arbitration proceedings with the Netherlands Arbitration Institute pursuant to which we are seeking to enforce our rights under the tax holiday and other agreements related to the refinery. The arbitration hearing was held on February 3-4, 2009. We anticipate a decision sometime later this year. We have also filed protests of these assessments through proceedings in Aruba. In April 2008, we entered into an escrow agreement with the GOA and Caribbean Mercantile Bank NV (CMB), pursuant to which we agreed to deposit an amount equal to the disputed turnover tax on exports into an escrow account with CMB, pending resolution of the tax protest proceedings in Aruba. Under this escrow agreement, we are required to continue to deposit an amount equal to the disputed tax on a monthly basis until the tax dispute is resolved through the Aruba proceedings. Amounts deposited under this escrow agreement, which totaled $102 million as of December 31, 2008, are reflected as “restricted cash” in our consolidated balance sheet.

In addition to the turnover tax described above, the GOA has also asserted other tax amounts aggregating approximately $25 million related to dividends and other tax items. The GOA, through the arbitration, is also now questioning the validity of the tax holiday generally, although the GOA has never issued any formal assessment for profit tax at any time during the tax holiday period. We believe that the provisions of our tax holiday agreement exempt us from all of these taxes and, accordingly, no expense or liability has been recognized in our consolidated financial statements. We are also challenging approximately $30 million in foreign exchange payments made to the Central Bank of Aruba as payments exempted

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under our tax holiday, as well as other reasons. These taxes and assessments are also being addressed in the arbitration proceedings discussed above.

Keystone Pipeline
In July 2008, we entered into an agreement to participate as a prospective shipper on the 500,000 barrel-per-day expansion of the Keystone crude oil pipeline system, which is expected to be completed by 2012. Once completed, the pipeline will enable crude oil to be transported from Western Canada to the U.S. Gulf Coast at Port Arthur, Texas. In addition to our commitment to ship crude oil through the pipeline, we have an option to acquire an equity interest in the Keystone partnerships. We have also secured commitments from several Canadian oil producers to sell to us heavy sour crude oil for shipment through the pipeline.

24. ENVIRONMENTAL MATTERS

Remediation Liabilities
Liabilities for future remediation costs are recorded when environmental assessments and/or remedial efforts are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Environmental liabilities are based on best estimates of probable undiscounted future costs using currently available technology and applying current regulations, as well as our own internal environmental policies.

The balance of and changes in the accruals for environmental matters, which are principally included in “other long-term liabilities” described in Note 13, were as follows (in millions):

	Year Ended December 31,
	2008			2007			2006
Balance as of beginning of year	$	285		$	298		$	294
Premcor Acquisition		–			–			7
Adjustments to estimates, net		72			36			53
Payments, net of third-party recoveries		(51	)		(55	)		(56	)
Foreign currency translation		(9	)		6			–
Balance as of end of year	$	297		$	285		$	298

The balance of accruals for environmental matters is included in the consolidated balance sheet as follows (in millions):

	December 31,
	2008		2007
Accrued expenses	$	42	$	55
Other long-term liabilities		255		230
Accruals for environmental matters	$	297	$	285

In connection with our various acquisitions, we assumed certain environmental liabilities including, but not limited to, certain remediation obligations, site restoration costs, and certain liabilities relating to soil and groundwater remediation.

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We believe that we have adequately provided for our environmental exposures with the accruals referred to above. These liabilities have not been reduced by potential future recoveries from third parties. Environmental liabilities are difficult to assess and estimate due to unknown factors such as the timing and extent of remediation, the determination of our obligation in proportion to other parties, improvements in remediation technologies, and the extent to which environmental laws and regulations may change in the future.

25. LITIGATION MATTERS

MTBE Litigation
As of February 1, 2009, we were named as a defendant in 29 active cases alleging liability related to MTBE contamination in groundwater. The plaintiffs are generally water providers, governmental authorities, and private water companies alleging that refiners and marketers of MTBE and gasoline containing MTBE are liable for manufacturing or distributing a defective product. We have been named in these lawsuits together with many other refining industry companies. We are being sued primarily as a refiner and marketer of MTBE and gasoline containing MTBE. We do not own or operate gasoline station facilities in most of the geographic locations in which damage is alleged to have occurred. The lawsuits generally seek individual, unquantified compensatory and punitive damages, injunctive relief, and attorneys’ fees. Most of the cases are pending in federal court and are consolidated for pre-trial proceedings in the U.S. District Court for the Southern District of New York (Multi-District Litigation Docket No. 1358,In re: Methyl-Tertiary Butyl Ether Products Liability Litigation). Discovery is open in all cases. Three of the cases (City of New York,Village of Hempstead, andWest Hempstead Water District) are set for trial on June 22, 2009. Two other cases,State of New HampshireandPeople of the State of California, are pending in state court. We believe that we have strong defenses to all claims and are vigorously defending these cases.

We have recorded a loss contingency liability with respect to our MTBE litigation portfolio in accordance with FASB Statement No. 5, “Accounting for Contingencies.” However, due to the inherent uncertainty of litigation, we believe that it is reasonably possible (as defined in Statement No. 5) that we may suffer a loss with respect to one or more of the lawsuits in excess of the amount accrued. We believe that such an outcome in any one of these lawsuits would not have a material adverse effect on our results of operations or financial position. However, we believe that an adverse result in all or a substantial number of these cases could have a material effect on our results of operations and financial position. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.

Retail Fuel Temperature Litigation
As of February 1, 2009, we were named in 21 consumer class action lawsuits relating to fuel temperature. We have been named in these lawsuits together with several other defendants in the retail petroleum marketing business. The complaints, filed in federal courts in several states, allege that because fuel volume increases with fuel temperature, the defendants have violated state consumer protection laws by failing to adjust the volume of fuel when the fuel temperature exceeded 60 degrees Fahrenheit. The complaints seek to certify classes of retail consumers who purchased fuel in various locations. The complaints seek an order compelling the installation of temperature correction devices as well as monetary relief. The federal lawsuits are consolidated into a multi-district litigation case in the U.S. District Court for the District of Kansas (Multi-District Litigation Docket No. 1840,In re: Motor Fuel Temperature Sales Practices Litigation). Discovery has commenced. The court is expected to rule on

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certain class certification issues within the first half of 2009. We believe that we have several strong defenses to these lawsuits and intend to contest them. We have not recorded a loss contingency liability with respect to this matter, but due to the inherent uncertainty of litigation, we believe that it is reasonably possible (as defined in Statement No. 5) that we may suffer a loss with respect to one or more of the lawsuits. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.

Rosolowski
Rosolowski v. Clark Refining & Marketing, Inc., et al., Judicial Circuit Court, Cook County, Illinois (Case No. 95-L 014703). We assumed this lawsuit in our acquisition of Premcor Inc. The lawsuit relates in part to a 1994 release to the atmosphere of spent catalyst from the now-closed Blue Island, Illinois refinery. The case was certified as a class action in 2000 with three classes, two of which received nominal or no damages, and one of which received a sizeable jury verdict. That class consisted of local residents who claimed property damage or loss of use and enjoyment of their property over a period of several years. In 2005, the jury returned a verdict for the plaintiffs of $80 million in compensatory damages and $40 million in punitive damages. However, following our motions for new trial and judgment notwithstanding the verdict (citing, among other things, misconduct by plaintiffs’ counsel and improper class certification), the trial judge in 2006 vacated the jury’s award and decertified the class. Plaintiffs appealed, and in June 2008 the state appeals court reversed the trial judge’s decision to decertify the class and set aside the judgment. Thereafter, the Illinois Supreme Court refused to hear the case and returned it to the trial court. We have submitted renewed motions for judgment notwithstanding the verdict or, alternatively, a new trial. While we do not believe that the ultimate resolution of this matter will have a material effect on our financial position or results of operations, we have recorded a loss contingency liability with respect to this matter in accordance with Statement No. 5.

Other Litigation
We are also a party to additional claims and legal proceedings arising in the ordinary course of business. We believe that there is only a remote likelihood that future costs related to known contingent liabilities related to these legal proceedings would have a material adverse impact on our consolidated results of operations or financial position.

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26. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

In conjunction with the Premcor Acquisition on September 1, 2005, Valero Energy Corporation has fully and unconditionally guaranteed the following debt of The Premcor Refining Group Inc. (PRG), a wholly owned subsidiary of Valero Energy Corporation, that was outstanding as of December 31, 2008:

• 6.75% senior notes due February 2011,

• 6.125% senior notes due May 2011,

• 6.75% senior notes due May 2014, and

• 7.5% senior notes due June 2015.

In addition, PRG has fully and unconditionally guaranteed all of the outstanding debt issued by Valero Energy Corporation.

The following condensed consolidating financial information is provided for Valero and PRG as an alternative to providing separate financial statements for PRG. The accounts for all companies reflected herein are presented using the equity method of accounting for investments in subsidiaries.

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Condensed Consolidating Balance Sheet as of December 31, 2008
(in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	215		$	–		$	725		$	–		$	940
Restricted cash		23			2			106			–			131
Receivables, net		–			36			2,861			–			2,897
Inventories		–			360			4,277			–			4,637
Income taxes receivable		76			–			197			(76	)		197
Deferred income taxes		–			–			98			–			98
Prepaid expenses and other		–			8			542			–			550
Total current assets		314			406			8,806			(76	)		9,450
Property, plant and equipment, at cost		–			6,025			22,078			–			28,103
Accumulated depreciation		–			(483	)		(4,407	)		–			(4,890	)
Property, plant and equipment, net		–			5,542			17,671			–			23,213
Intangible assets, net		–			–			224			–			224
Investment in Valero Energy affiliates		6,300			2,718			65			(9,083	)		–
Long-term notes receivable from affiliates		15,354			–			–			(15,354	)		–
Deferred income tax receivable		883			–			–			(883	)		–
Deferred charges and other assets, net		121			136			1,273			–			1,530
Total assets	$	22,972		$	8,802		$	28,039		$	(25,396	)	$	34,417
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	209		$	–		$	103		$	–		$	312
Accounts payable		43			414			3,989			–			4,446
Accrued expenses		82			34			258			–			374
Taxes other than income taxes		–			23			569			–			592
Income taxes payable		–			6			70			(76	)		–
Deferred income taxes		485			–			–			–			485
Total current liabilities		819			477			4,989			(76	)		6,209
Debt and capital lease obligations, less current portion		5,329			899			36			–			6,264
Long-term notes payable to affiliates		–			5,966			9,388			(15,354	)		–
Deferred income taxes		–			1,200			3,846			(883	)		4,163
Other long-term liabilities		1,204			195			762			–			2,161
Stockholders’ equity:
Common stock		6			–			1			(1	)		6
Additional paid-in capital		7,190			1,598			4,349			(5,947	)		7,190
Treasury stock		(6,884	)		–			–			–			(6,884	)
Retained earnings		15,484			(1,523	)		4,507			(2,984	)		15,484
Accumulated other comprehensive income (loss)		(176	)		(10	)		161			(151	)		(176	)
Total stockholders’ equity		15,620			65			9,018			(9,083	)		15,620
Total liabilities and stockholders’ equity	$	22,972		$	8,802		$	28,039		$	(25,396	)	$	34,417

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet as of December 31, 2007
(in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	1,414		$	–		$	1,050		$	–		$	2,464
Restricted cash		23			2			6			–			31
Receivables, net		1			119			7,571			–			7,691
Inventories		–			569			3,504			–			4,073
Deferred income taxes		–			–			247			–			247
Prepaid expenses and other		–			11			164			–			175
Assets held for sale		–			–			306			–			306
Total current assets		1,438			701			12,848			–			14,987
Property, plant and equipment, at cost		–			6,681			18,918			–			25,599
Accumulated depreciation		–			(420	)		(3,619	)		–			(4,039	)
Property, plant and equipment, net		–			6,261			15,299			–			21,560
Intangible assets, net		–			2			288			–			290
Goodwill		–			1,816			2,203			–			4,019
Investment in Valero Energy affiliates		7,080			1,183			73			(8,336	)		–
Long-term notes receivable from affiliates		17,321			–			–			(17,321	)		–
Deferred charges and other assets, net		386			165			1,315			–			1,866
Total assets	$	26,225		$	10,128		$	32,026		$	(25,657	)	$	42,722
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	7		$	382		$	3		$	–		$	392
Accounts payable		234			302			9,051			–			9,587
Accrued expenses		79			55			366			–			500
Taxes other than income taxes		–			25			607			–			632
Income taxes payable		227			115			157			–			499
Deferred income taxes		21			272			–			–			293
Liabilities related to assets held for sale		–			–			11			–			11
Total current liabilities		568			1,151			10,195			–			11,914
Debt and capital lease obligations, less current portion		5,527			903			40			–			6,470
Long-term notes payable to affiliates		–			7,763			9,558			(17,321	)		–
Deferred income taxes		852			57			3,112			–			4,021
Other long-term liabilities		771			181			858			–			1,810
Stockholders’ equity:
Common stock		6			–			2			(2	)		6
Additional paid-in capital		7,111			75			2,486			(2,561	)		7,111
Treasury stock		(6,097	)		–			–			–			(6,097	)
Retained earnings		16,914			–			5,764			(5,764	)		16,914
Accumulated other comprehensive income (loss)		573			(2	)		11			(9	)		573
Total stockholders’ equity		18,507			73			8,263			(8,336	)		18,507
Total liabilities and stockholders’ equity	$	26,225		$	10,128		$	32,026		$	(25,657	)	$	42,722

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income for the Year Ended December 31, 2008
(in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	26,083		$	117,582		$	(24,551	)	$	119,114
Costs and expenses:
Cost of sales		–			25,282			106,698			(24,551	)		107,429
Refining operating expenses		–			909			3,646			–			4,555
Retail selling expenses		–			–			768			–			768
General and administrative expenses		(9	)		40			528			–			559
Depreciation and amortization expense		–			253			1,223			–			1,476
Gain on sale of Krotz Springs Refinery		–			–			(305	)		–			(305	)
Goodwill impairment loss		–			1,837			2,232			–			4,069
Total costs and expenses		(9	)		28,321			114,790			(24,551	)		118,551
Operating income (loss)		9			(2,238	)		2,792			–			563
Equity in earnings (losses) of subsidiaries		(1,436	)		882			(1,523	)		2,077			–
Other income (expense), net		1,083			(69	)		868			(1,769	)		113
Interest and debt expense:
Incurred		(577	)		(552	)		(1,091	)		1,769			(451	)
Capitalized		–			24			87			–			111
Income (loss) before income tax expense (benefit)		(921	)		(1,953	)		1,133			2,077			336
Income tax expense (benefit) (1)		210			(430	)		1,687			–			1,467
Net income (loss)	$	(1,131	)	$	(1,523	)	$	(554	)	$	2,077		$	(1,131	)

(1) The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.

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Condensed Consolidating Statement of Income for the Year Ended December 31, 2007
(in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	24,650		$	94,058		$	(23,381	)	$	95,327
Costs and expenses:
Cost of sales		–			22,280			82,746			(23,381	)		81,645
Refining operating expenses		–			874			3,142			–			4,016
Retail selling expenses		–			–			750			–			750
General and administrative expenses		(6	)		30			614			–			638
Depreciation and amortization expense		–			305			1,055			–			1,360
Total costs and expenses		(6	)		23,489			88,307			(23,381	)		88,409
Operating income		6			1,161			5,751			–			6,918
Equity in earnings of subsidiaries		4,556			668			1,320			(6,544	)		–
Other income (expense), net		1,446			(245	)		869			(1,903	)		167
Interest and debt expense:
Incurred		(520	)		(574	)		(1,275	)		1,903			(466	)
Capitalized		–			7			100			–			107
Income from continuing operations before income tax expense		5,488			1,017			6,765			(6,544	)		6,726
Income tax expense (1)		254			187			1,720			–			2,161
Income from continuing operations		5,234			830			5,045			(6,544	)		4,565
Income from discontinued operations, net of income tax expense		–			490			179			–			669
Net income	$	5,234		$	1,320		$	5,224		$	(6,544	)	$	5,234

(1) The income tax expense reflected in each column does not include any tax effect of the equity in earnings of subsidiaries.

125

VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income for the Year Ended December 31, 2006
(in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	22,961		$	86,427		$	(21,748	)	$	87,640
Costs and expenses:
Cost of sales		–			21,233			74,378			(21,748	)		73,863
Refining operating expenses		–			770			2,852			–			3,622
Retail selling expenses		–			–			719			–			719
General and administrative expenses		8			39			551			–			598
Depreciation and amortization expense		–			254			862			–			1,116
Total costs and expenses		8			22,296			79,362			(21,748	)		79,918
Operating income (loss)		(8	)		665			7,065			��			7,722
Equity in earnings of subsidiaries		4,887			777			906			(6,570	)		–
Equity in earnings of NuStar Energy L.P.		–			–			45			–			45
Other income (expense), net		1,342			(136	)		1,357			(2,213	)		350
Interest and debt expense:
Incurred		(489	)		(703	)		(1,398	)		2,213			(377	)
Capitalized		–			57			108			–			165
Minority interest in net income of NuStar GP Holdings, LLC		–			–			(7	)		–			(7	)
Income from continuing operations before income tax expense (benefit)		5,732			660			8,076			(6,570	)		7,898
Income tax expense (benefit) (1)		269			(70	)		2,412			–			2,611
Income from continuing operations		5,463			730			5,664			(6,570	)		5,287
Income from discontinued operations, net of income tax expense		–			176			–			–			176
Net income		5,463			906			5,664			(6,570	)		5,463
Preferred stock dividends		2			–			–			–			2
Net income applicable to common stock	$	5,461		$	906		$	5,664		$	(6,570	)	$	5,461

(1) The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings of subsidiaries.

126

VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2008
(in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG (1)			Subsidiaries (1)			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	46		$	(46	)	$	2,992		$	–		$	2,992
Cash flows from investing activities:
Capital expenditures		–			(593	)		(2,197	)		–			(2,790	)
Deferred turnaround and catalyst costs		–			(93	)		(315	)		–			(408	)
Proceeds from sale of Krotz Springs Refinery		–			–			463			–			463
Contingent payments in connection with acquisitions		–			–			(25	)		–			(25	)
Return of investment in Cameron Highway Oil Pipeline Company, net		–			–			24			–			24
Investments in subsidiaries		(1,235	)		–			(1,523	)		2,758			–
Return of investment		629			265			–			(894	)		–
Proceeds from minor dispositions of property, plant and equipment		–			–			25			–			25
Net intercompany loan repayments		596			–			–			(596	)		–
Minor acquisitions		–			–			(144	)		–			(144	)
Other investing activities, net		–			–			(7	)		–			(7	)
Net cash used in investing activities		(10	)		(421	)		(3,699	)		1,268			(2,862	)
Cash flows from financing activities:
Non-bank debt repayments		(6	)		(368	)		–			–			(374	)
Bank credit agreements:
Borrowings		296			–			–			–			296
Repayments		(296	)		–			–			–			(296	)
Purchase of common stock for treasury		(955	)		–			–			–			(955	)
Issuance of common stock in connection with employee benefit plans		16			–			–			–			16
Benefit from tax deduction in excess of recognized stock-based compensation cost		9			–			–			–			9
Common stock dividends		(299	)		–			–			–			(299	)
Net intercompany borrowings (repayments)		–			(688	)		92			596			–
Dividends to parent		–			–			(894	)		894			–
Capital contributions from parent		–			1,523			1,235			(2,758	)		–
Other financing activities		–			–			(4	)		–			(4	)
Net cash provided by (used in) financing activities		(1,235	)		467			429			(1,268	)		(1,607	)
Effect of foreign exchange rate changes on cash		–			–			(47	)		–			(47	)
Net decrease in cash and temporary cash investments		(1,199	)		–			(325	)		–			(1,524	)
Cash and temporary cash investments at beginning of year		1,414			–			1,050			–			2,464
Cash and temporary cash investments at end of year	$	215		$	–		$	725		$	–		$	940

(1) The information presented herein excludes a $918 million noncash capital contribution of property and other assets, net of certain liabilities, from PRG to Valero Refining Company-Tennessee, L.L.C. (included in “Other Non-Guarantor Subsidiaries”) on April 1, 2008.

127

VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2007
(in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG (1)			Subsidiaries (1)			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	736		$	(51	)	$	4,573		$	–		$	5,258
Cash flows from investing activities:
Capital expenditures		–			(293	)		(1,967	)		–			(2,260	)
Deferred turnaround and catalyst costs		–			(64	)		(454	)		–			(518	)
Proceeds from sale of Lima Refinery		–			1,873			555			–			2,428
Contingent payments in connection with acquisitions		–			(25	)		(50	)		–			(75	)
Investment in Cameron Highway Oil Pipeline Company, net		–			–			(209	)		–			(209	)
Investments in subsidiaries		(2,742	)		(58	)		–			2,800			–
Return of investment		2,383			–			1,346			(3,729	)		–
Proceeds from minor dispositions of property, plant and equipment		–			3			60			–			63
Net intercompany loan repayments		3,969			–			–			(3,969	)		–
Other investing activities, net		–			1			(12	)		–			(11	)
Net cash provided by (used in) investing activities		3,610			1,437			(731	)		(4,898	)		(582	)
Cash flows from financing activities:
Non-bank debt:
Borrowings		2,245			–			–			–			2,245
Repayments		(280	)		(183	)		–			–			(463	)
Bank credit agreements:
Borrowings		3,000			–			–			–			3,000
Repayments		(3,000	)		–			–			–			(3,000	)
Purchase of common stock for treasury		(5,788	)		–			–			–			(5,788	)
Issuance of common stock in connection with employee benefit plans		159			–			–			–			159
Benefit from tax deduction in excess of recognized stock-based compensation cost		311			–			–			–			311
Common stock dividends		(271	)		–			–			–			(271	)
Dividends to parent		–			(1,346	)		(2,383	)		3,729			–
Capital contributions from parent		–			–			2,800			(2,800	)		–
Net intercompany borrowings (loan repayments)		–			143			(4,112	)		3,969			–
Other financing activities		(20	)		–			(4	)		–			(24	)
Net cash used in financing activities		(3,644	)		(1,386	)		(3,699	)		4,898			(3,831	)
Effect of foreign exchange rate changes on cash		–			–			29			–			29
Net increase in cash and temporary cash investments		702			–			172			–			874
Cash and temporary cash investments at beginning of year		712			–			878			–			1,590
Cash and temporary cash investments at end of year	$	1,414		$	–		$	1,050		$	–		$	2,464

(1) The information presented herein excludes a $686 million noncash capital contribution of property and other assets, net of certain liabilities, from PRG to Lima Refining Company (included in “Other Non-Guarantor Subsidiaries”) on April 1, 2007.

128

VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2006
(in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	496		$	1,097		$	4,719		$	–		$	6,312
Cash flows from investing activities:
Capital expenditures		–			(1,074	)		(2,113	)		–			(3,187	)
Deferred turnaround and catalyst costs		–			(198	)		(371	)		–			(569	)
Proceeds from sale of NuStar GP Holdings, LLC		–			–			880			–			880
Contingent payments in connection with acquisitions		–			(25	)		(76	)		–			(101	)
Investment in Cameron Highway Oil Pipeline Company, net		–			–			(26	)		–			(26	)
Return of investment		4,912			777			906			(6,595	)		–
Proceeds from minor dispositions of property, plant and equipment		–			4			60			–			64
Net intercompany loans		(2,556	)		–			–			2,556			–
Other investing activities, net		–			(4	)		(28	)		–			(32	)
Net cash provided by (used in) investing activities		2,356			(520	)		(768	)		(4,039	)		(2,971	)
Cash flows from financing activities:
Non-bank debt repayments		(220	)		(29	)		–			–			(249	)
Bank credit agreements:
Borrowings		8			–			822			–			830
Repayments		(8	)		–			(822	)		–			(830	)
Termination of interest rate swaps		(54	)		–			–			–			(54	)
Purchase of common stock for treasury		(2,020	)		–			–			–			(2,020	)
Issuance of common stock in connection with employee benefit plans		122			–			–			–			122
Benefit from tax deduction in excess of recognized stock-based compensation cost		206			–			–			–			206
Common and preferred stock dividends		(184	)		–			–			–			(184	)
Dividends to parent		–			(906	)		(5,689	)		6,595			–
Net intercompany borrowings		–			354			2,202			(2,556	)		–
Other financing activities		(1	)		(1	)		(7	)		–			(9	)
Net cash used in financing activities		(2,151	)		(582	)		(3,494	)		4,039			(2,188	)
Effect of foreign exchange rate changes on cash		–			–			1			–			1
Net increase (decrease) in cash and temporary cash investments		701			(5	)		458			–			1,154
Cash and temporary cash investments at beginning of year		11			5			420			–			436
Cash and temporary cash investments at end of year	$	712		$	–		$	878		$	–		$	1,590

129

VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

27. QUARTERLY RESULTS OF OPERATIONS (Unaudited)

Our results of operations by quarter for the years ended December 31, 2008 and 2007 were as follows (in millions, except per share amounts):

	2008 Quarter Ended
	March 31		June 30		September 30 (a)		December 31 (b)
Operating revenues	$	27,945	$	36,640	$	35,960	$	18,569
Operating income (loss)		472		1,158		1,840		(2,907	)
Net income (loss)		261		734		1,152		(3,278	)
Earnings (loss) per common share (c)		0.49		1.40		2.21		(6.36	)
Earnings (loss) per common share – assuming dilution (c)		0.48		1.37		2.18		(6.36	)
	2007 Quarter Ended
	March 31		June 30		September 30		December 31
Operating revenues (d)	$	18,755	$	24,202	$	23,699	$	28,671
Operating income (d)		1,673		3,193		1,168		884
Net income		1,144		2,249		1,274		567
Earnings per common share (c)		1.91		3.99		2.31		1.04
Earnings per common share – assuming dilution (c) (e)		1.86		3.89		2.09		1.02

(a)	Operating income and net income for the quarter ended September 30, 2008 include $305 million and $170 million, respectively, related to a gain on the sale of the Krotz Springs Refinery in July 2008, as discussed in Note 2.
(b)	Operating loss and net loss for the quarter ended December 31, 2008 include charges of $4.1 billion and $4.0 billion, respectively, resulting from a goodwill impairment loss, as discussed in Note 8.
(c)	Earnings per common share amounts are computed independently for each of the quarters presented. Therefore, the sum of the quarterly earnings per share may not equal the annual earnings per share.
(d)	Operating revenues and operating income for 2007 exclude the operations related to the Lima Refinery, which are reported as discontinued operations.
(e)	Earnings per common share assuming dilution for the quarter ended September 30, 2007 reflects a reduction resulting from a $94 million cash payment upon the completion of our accelerated share repurchase program, as discussed in Note 14.

28. SUBSEQUENT EVENT

On February 6, 2009, we entered into a binding agreement with VeraSun Energy Corporation (VeraSun) pursuant to which we offered to purchase from VeraSun five existing ethanol plants and a site currently under development for $280 million, plus inventory and certain other working capital. The existing ethanol plants included in the agreement are located in Charles City, Fort Dodge, and Hartley, Iowa;

130

VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Aurora, South Dakota; and Welcome, Minnesota, and the site under development is located in Reynolds, Indiana. VeraSun previously filed for relief under Chapter 11 of the U.S. Bankruptcy Code. Our offer to purchase these ethanol facilities is subject to the completion of an auction process by VeraSun, as well as subsequent bankruptcy court approval of the transaction. If our offer is successful, we expect to consummate the purchase late in the first quarter or early in the second quarter of 2009, subject to regulatory and other customary closing conditions. We would fund the acquisition either through the use of our revolving bank credit facility or with available cash.

131

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures. Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of December 31, 2008.

Internal Control over Financial Reporting.

     (a) Management’s Report on Internal Control over Financial Reporting.

The management report on Valero’s internal control over financial reporting required by Item 9A appears in Item 8 on page 57 of this report, and is incorporated herein by reference.

     (b) Attestation Report of the Independent Registered Public Accounting Firm.

KPMG LLP’s report on Valero’s internal control over financial reporting appears in Item 8 beginning on page 59 of this report, and is incorporated herein by reference.

     (c) Changes in Internal Control over Financial Reporting.

There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

132

PART III

ITEMS 10-14.

The information required by Items 10 through 14 of Form 10-K is incorporated herein by reference to the definitive Proxy Statement for our 2009 Annual Meeting of Stockholders that we will file with the SEC before March 31, 2009. Certain information required by Item 401 of Regulation S-K concerning our executive officers appears in Part I of this report.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

  (a) 1. Financial Statements. The following consolidated financial statements of Valero Energy Corporation and its subsidiaries are included in Part II, Item 8 of this Form 10-K:

	Page
Management’s report on internal control over financial reporting		57
Reports of independent registered public accounting firm		58
Consolidated balance sheets as of December 31, 2008 and 2007		61
Consolidated statements of income for the years ended December 31, 2008, 2007, and 2006		62
Consolidated statements of stockholders’ equity for the years ended December 31, 2008, 2007, and 2006		63
Consolidated statements of cash flows for the years ended December 31, 2008, 2007, and 2006		64
Consolidated statements of comprehensive income for the years ended December 31, 2008, 2007, and 2006		65
Notes to consolidated financial statements		66

     2. Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.

     3. Exhibits. Filed as part of this Form 10-K are the following exhibits:

2.01	–	Agreement and Plan of Merger dated as of April 24, 2005 by and among Valero Energy Corporation and Premcor Inc. – incorporated by reference to Exhibit 2.1 to Valero’s Current Report on Form 8-K dated April 24, 2005, and filed April 25, 2005 (SEC File No. 1-13175).
3.01	–	Amended and Restated Certificate of Incorporation of Valero Energy Corporation, formerly known as Valero Refining and Marketing Company – incorporated by reference to Exhibit 3.1 to Valero’s Registration Statement on Form S-1 (SEC File No. 333-27013) filed May 13, 1997.
3.02	–	Certificate of Amendment (effective July 31, 1997) to Restated Certificate of Incorporation of Valero Energy Corporation – incorporated by reference to Exhibit 3.02 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2003 (SEC File No. 1-13175).
3.03	–	Certificate of Merger of Ultramar Diamond Shamrock Corporation with and into Valero Energy Corporation dated December 31, 2001 – incorporated by reference to Exhibit 3.03 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2003 (SEC File No. 1-13175).

133

3.04	–	Amendment (effective December 31, 2001) to Restated Certificate of Incorporation of Valero Energy Corporation - - incorporated by reference to Exhibit 3.1 to Valero’s Current Report on Form 8-K dated December 31, 2001, and filed January 11, 2002 (SEC File No. 1-13175).
3.05	–	Second Certificate of Amendment (effective September 17, 2004) to Restated Certificate of Incorporation of Valero Energy Corporation – incorporated by reference to Exhibit 3.04 to Valero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 (SEC File No. 1-13175).
3.06	–	Certificate of Merger of Premcor Inc. with and into Valero Energy Corporation effective September 1, 2005 - incorporated by reference to Exhibit 2.01 to Valero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (SEC File No. 1-13175).
3.07	–	Third Certificate of Amendment (effective December 2, 2005) to Restated Certificate of Incorporation of Valero Energy Corporation – incorporated by reference to Exhibit 3.07 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2005 (SEC File No. 1-13175).
3.08	–	Amended and Restated Bylaws of Valero Energy Corporation (as of July 12, 2007) – incorporated by reference to Exhibit 3.01 to Valero’s Current Report on Form 8-K dated July 11, 2007, and filed July 17, 2007 (SEC File No. 1-13175).
4.01	–	Indenture dated as of December 12, 1997 between Valero Energy Corporation and The Bank of New York – incorporated by reference to Exhibit 3.4 to Valero’s Registration Statement on Form S-3 (SEC File No. 333-56599) filed June 11, 1998.
4.02	–	First Supplemental Indenture dated as of June 28, 2000 between Valero Energy Corporation and The Bank of New York (including Form of 7 3/4% Senior Deferrable Note due 2005) – incorporated by reference to Exhibit 4.6 to Valero’s Current Report on Form 8-K dated June 28, 2000, and filed June 30, 2000 (SEC File No. 1-13175).
4.03	–	Indenture (Senior Indenture) dated as of June 18, 2004 between Valero Energy Corporation and Bank of New York – incorporated by reference to Exhibit 4.7 to Valero’s Registration Statement on Form S-3 (SEC File No. 333-116668) filed June 21, 2004.
4.04	–	Form of Indenture related to subordinated debt securities – incorporated by reference to Exhibit 4.8 to Valero’s Registration Statement on Form S-3 (SEC File No. 333-116668) filed June 21, 2004.
4.05	–	Third Supplemental Indenture dated as of August 31, 2005 between The Premcor Refining Group Inc. and Deutsche Bank Trust Company Americas – incorporated by reference to Exhibit 4.09 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2005 (SEC File No. 1-13175).
4.06	–	Fourth Supplemental Indenture dated as of September 1, 2005 among The Premcor Refining Group Inc., Valero Energy Corporation, and Deutsche Bank Trust Company Americas – incorporated by reference to Exhibit 4.10 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2005 (SEC File No. 1-13175).
4.07	–	Guaranty dated September 2, 2005 of The Premcor Refining Group Inc. (guaranteeing certain Valero-heritage debt) – incorporated by reference to Exhibit 4.11 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2005 (SEC File No. 1-13175).
4.08	–	Guaranty dated September 2, 2005 of Valero Energy Corporation (guaranteeing certain Premcor-heritage debt) – incorporated by reference to Exhibit 4.12 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2005 (SEC File No. 1-13175).
4.09	–	Specimen Certificate of Common Stock – incorporated by reference to Exhibit 4.1 to Valero’s Registration Statement on Form S-3 (SEC File No. 333-116668) filed June 21, 2004.
*+10.01	–	Valero Energy Corporation Annual Bonus Plan, amended and restated as of October 15, 2008.

134

+10.02	–	Valero Energy Corporation 2005 Omnibus Stock Incentive Plan, amended and restated as of October 1, 2005 – incorporated by reference to Exhibit 10.01 to Valero’s Current Report on Form 8-K dated October 20, 2005, and filed October 26, 2005 (SEC File No. 1-13175).
+10.03	–	Valero Energy Corporation 2001 Executive Stock Incentive Plan, amended and restated as of October 1, 2005 – incorporated by reference to Exhibit 10.04 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2005 (SEC File No. 1-13175).
*+10.04	–	Valero Energy Corporation Deferred Compensation Plan, amended and restated as of January 1, 2008.
*+10.05	–	Form of 2009 Elective Deferral Agreement pursuant to the Valero Energy Corporation Deferred Compensation Plan.
*+10.06	–	Form of Investment Election Form pursuant to the Valero Energy Corporation Deferred Compensation Plan.
*+10.07	–	Form of 2009 Distribution Election Form pursuant to the Valero Energy Corporation Deferred Compensation Plan.
*+10.08	–	Valero Energy Corporation Amended and Restated Supplemental Executive Retirement Plan, amended and restated as of November 10, 2008.
+10.09	–	Valero Energy Corporation 2003 Employee Stock Incentive Plan, as amended and restated effective October 1, 2005 – incorporated by reference to Exhibit 10.11 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2005 (SEC File No. 1-13175).
*+10.10	–	Valero Energy Corporation Stock Option Plan, as amended and restated effective January 1, 2009.
+10.11	–	Valero Energy Corporation Restricted Stock Plan for Non-Employee Directors, as amended and restated July 11, 2007 – incorporated by reference to Exhibit 10.02 to Valero’s Current Report on Form 8-K/A dated July 11, 2007, and filed September 18, 2007 (SEC File No. 1-13175).
+10.12	–	Valero Energy Corporation Non-Employee Director Stock Option Plan, as amended and restated effective January 1, 2007 – incorporated by reference to Exhibit 10.02 to Valero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (SEC File No. 1-13175).
+10.13	–	Form of Indemnity Agreement between Valero Energy Corporation (formerly known as Valero Refining and Marketing Company) and certain officers and directors – incorporated by reference to Exhibit 10.8 to Valero’s Registration Statement on Form S-1 (SEC File No. 333-27013) filed May 13, 1997.
+10.14	–	Schedule of Indemnity Agreements – incorporated by reference to Exhibit 10.9 to Valero’s Registration Statement on Form S-1 (SEC File No. 333-27013) filed May 13, 1997.
+10.15	–	Change of Control Agreement (Tier I) dated January 18, 2007 between Valero Energy Corporation and William R. Klesse – incorporated by reference to Exhibit 10.01 to Valero’s Current Report on Form 8-K dated January 17, 2007 and filed January 19, 2007 (SEC File No. 1-13175).
*+10.16	–	Schedule of Change of Control Agreements (Tier I).
*+10.17	–	Change of Control Agreement (Tier II) dated March 15, 2007 between Valero Energy Corporation and Kimberly S. Bowers.
+10.18	–	Form of Performance Award Agreement pursuant to the Valero Energy Corporation 2005 Omnibus Stock Incentive Plan – incorporated by reference to Exhibit 10.02 to Valero’s Current Report on Form 8-K dated January 18, 2006, and filed January 20, 2006 (SEC File No. 1-13175).

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+10.19	–	Form of Stock Option Agreement pursuant to the Valero Energy Corporation 2005 Omnibus Stock Incentive Plan – incorporated by reference to Exhibit 10.03 to Valero’s Current Report on Form 8-K dated October 20, 2005, and filed October 26, 2005 (SEC File No. 1-13175).
+10.20	–	Form of Stock Option Agreement pursuant to the Valero Energy Corporation Non-Employee Director Stock Option Plan – incorporated by reference to Exhibit 10.04 to Valero’s Quarterly Report onForm 10-Q for the quarter ended September 30, 2006 (SEC File No. 1-13175).
+10.21	–	Form of Restricted Stock Agreement pursuant to the Valero Energy Corporation 2005 Omnibus Stock Incentive Plan – incorporated by reference to Exhibit 10.02 to Valero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (SEC File No. 1-13175).
+10.22	–	Form of Restricted Stock Agreement pursuant to the Valero Energy Corporation Restricted Stock Plan for Non-Employee Directors – incorporated by reference to Exhibit 10.03 to Valero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (SEC File No. 1-13175).
*10.23	–	$2,500,000,000 5-Year Revolving Credit Agreement, dated as of August 17, 2005, among Valero Energy Corporation, as Borrower; JPMorgan Chase Bank, N.A., as Administrative Agent and Global Administrative Agent; and the lenders named therein.
*10.24	–	First Amendment to $2,500,000,000 5-Year Revolving Credit Agreement, dated as of July 24, 2006.
*10.25	–	Second Amendment to $2,500,000,000 5-Year Revolving Credit Agreement, dated as of November 9, 2007.
*12.01	–	Statements of Computations of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Fixed Charges and Preferred Stock Dividends.
14.01	–	Code of Ethics for Senior Financial Officers – incorporated by reference to Exhibit 14.01 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2003 (SEC File No. 1-13175).
*21.01	–	Valero Energy Corporation subsidiaries.
*23.01	–	Consent of KPMG LLP dated February 26, 2009.
*24.01	–	Power of Attorney dated February 26, 2009 (on the signature page of this Form 10-K).
*31.01	–	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer.
*31.02	–	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer.
*32.01	–	Section 1350 Certifications (under Section 906 of the Sarbanes-Oxley Act of 2002).
*99.01	–	Audit Committee Pre-Approval Policy.

*	Filed herewith.
+	Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto.

Copies of exhibits filed as a part of this Form 10-K may be obtained by stockholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to Jay D. Browning, Senior Vice President-Corporate Law and Secretary, Valero Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-6000.

Pursuant to paragraph 601(b)(4)(iii)(A) of Regulation S-K, the registrant has omitted from the foregoing listing of exhibits, and hereby agrees to furnish to the SEC upon its request, copies of certain instruments, each relating to debt not exceeding 10% of the total assets of the registrant and its subsidiaries on a consolidated basis.

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Disclosures Required by Section 303A.12 of the NYSE Listed Company Manual.Section 303A.12 of the NYSE Listed Company Manual requires the chief executive officer (“CEO”) of each listed company to certify to the NYSE each year that he or she is not aware of any violation by the listed company of any of the NYSE corporate governance listing standards. The CEO of Valero submitted the required certification without qualification to the NYSE on May 15, 2008. In addition, the CEO certification and the chief financial officer’s certification required by Section 302 of the Sarbanes-Oxley Act of 2002 (the “SOX 302 Certifications”) with respect to our disclosures in our Form 10-K for the year ended December 31, 2007 were filed as Exhibit 31.01 to our Form 10-K for the year ended December 31, 2007. The SOX 302 Certifications with respect to our disclosures in our Form 10-K for the year ended December 31, 2008 are being filed as Exhibits 31.01 and 31.02 to thisForm 10-K.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VALERO ENERGY CORPORATION
(Registrant)
By	/s/ William R. Klesse
	(William R. Klesse)
	Chief Executive Officer, President, and      Chairman of the Board

Date: February 27, 2009

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POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints William R. Klesse, Michael S. Ciskowski, and Jay D. Browning, or any of them, each with power to act without the other, his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ William R. Klesse(William R. Klesse)	Chief Executive Officer, President, and Chairman of the Board (Principal Executive Officer)	February 26, 2009
/s/ Michael S. Ciskowski(Michael S. Ciskowski)	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	February 26, 2009
/s/ W.E. Bradford(W.E. Bradford)	Director	February 26, 2009
/s/ Ronald K. Calgaard(Ronald K. Calgaard)	Director	February 26, 2009
/s/ Jerry D. Choate(Jerry D. Choate)	Director	February 26, 2009
/s/ Irl F. Engelhardt(Irl F. Engelhardt)	Director	February 26, 2009
/s/ Ruben M. Escobedo(Ruben M. Escobedo)	Director	February 26, 2009
/s/ Bob Marbut(Bob Marbut)	Director	February 26, 2009
/s/ Donald L. Nickles(Donald L. Nickles)	Director	February 26, 2009
/s/ Robert A. Profusek(Robert A. Profusek)	Director	February 26, 2009
/s/ Susan Kaufman Purcell(Susan Kaufman Purcell)	Director	February 26, 2009
/s/ Stephen M. Waters(Stephen M. Waters)	Director	February 26, 2009

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