Valero Energy (VLO) 10-K 2010 FY Annual report

FORM 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(Mark One)

R ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

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	74-1828067
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

One Valero Way		78249
San Antonio, Texas		(Zip Code)
(Address of principal executive offices)
	Registrant’s telephone number, including area code: (210) 345-2000

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

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes R No o

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

Yes R No o

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No o

Indicate by check mark if disclosure of d elinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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. [X]

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 Rule12b-2 of the Exchange Act.

Large accelerated filer R Accelerated filer o Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No R

The aggregate market value of the voting and non-voting common stock held by non-affiliates was approximately $10.2 billion based on the last sales price quoted as of June 30, 2010 on the N ew York Stock Exchange, the last business day of the registrant’s most recently completed second fiscal quarter.

As of January 31, 2011, 568,971,156 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

We intend to file with the Securities and Ex change Commission a definitive Proxy Statement for our Annual Meeting of Stockholders scheduled for April 28, 2011, at which directors will be elected. Portions of the 2011 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 2011 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 2011 Proxy Statement
10.	Directors, Executive Officers and Corporate         Governance	Information Regarding the Board of Directors, Independent D irectors, Audit Committee, Proposal No. 1 Election of Directors, Information Concerning Nominees and Other Directors,Identification of Executive Officers,Section 16(a) Beneficial Ownership Reporting Compliance, and Governance Documents and Codes of Ethics
11.	Executive Compensation	Compensation Committee, Compensation Discussion and Analysis, Director Compensation, Executive Compensation, and Certain Relationships and Related Transactions
12.	Security Ownership of Certain Beneficial         Owners and Management and Related         Stockholder Matters	Beneficial Ownership of Valero Securities and Equity Compensation Plan Information
13.	Certain Relationships and Related         Transactions, and Director Independence	Certain Relationships and Related Transactions and Independent Directors
14.	Principal Accountant Fees and Services	KPMG Fees for Fiscal Year 2010, KPMG Fees for Fiscal Year 2009, and Audit Committee Pre-Approval Policy

Copies of all documents incorpo rated 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	13
	Environmental Matters	16
	Propert ies	16
Item 1B.	Unresolved Staff Comments	16
Item 3.	Legal Proceedings	17
Item 4.	Reserved	18
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	19
Item 6.	Selected Financial Data	22
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	53
Item 8.	Financial Statements and Supplementary Data	55
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	139
Item 9A.	Controls and Procedures	139
Item 9B.	Other Info rmation	139
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	140
Item 11.	Executive Compensation	140
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	140
Item 13.	Certain Relationships and Related Transactions, and Director Independence	140
Item 14.	Principal Accountant Fees and Services	140
PART IV
Item 15.	Exhibits and Financial Statement Schedules	140
Signatures		144

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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 23 of this report under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSE OF SAF E 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. We changed our name to Valero Energy Corporation on August 1, 1997. On January 31, 2011, we had 20,313 employees.

Our 14 petroleum refineries are located in the United States (U.S.), Canada, and Aruba. Our refineries can 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 speci fications 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 U.S. 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 U.S., Canada, and Aruba.

We also own 10 ethanol plants in the Midwest with a combined ethan ol production capacity of about 1.1 billion gallons per year.

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. In this same location, 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. These 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.

_____________________________

¹CBOB, or “conventional blendstock for oxygenate blending,” is conventiona l gasoline blendstock intended for blending with oxygenates downstream of the refinery where it was produced. CBOB becomes conventional gasoline after blending with oxygenates. RBOB is 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

&n bsp;

Our business is organized into three reportable segments: refining, ethanol, and retail. The financial information about our segments in Note 18 of Notes to Consolidated Financial Statements is incorporated herein by reference.

•     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 ethanol segment includes sales of internally produced ethanol and distillers grains. Our ethanol operation s are geographically located in the central plains region of the U.S..

•     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 the U.S. are referred to as Retail-U.S. Our retail operations in eastern Canada are referred to as Retai l-Canada.

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VALERO’S OPERATIONS

REFINING

On December 31, 2010, our refining operations included 14 refineries in the U.S., Canada, and Aruba with a combined total throughput capacity of approximately 2.6 million barrels per day (BPD). The following table presents the locations of these refineries and their approximate feedstock throughput capacities as of December 31, 2010.

Refinery	Location	Throughput Capacity (a) (BPD)
Gulf Coast:
C orpus Christi (b)	Texas	325,000
Port Arthur	Texas	310,000
St. Charles	Louisiana	270,000
Texas City	Texas	245,000
Aruba (c)	Aruba	235,000
Houston	Texas	160,000
Three Rivers	Texas	100,000
		1,645,000
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 (d):
Quebec City	Quebec, Canada	235,000
Total	& nbsp;	2,640,000

        &n bsp;                             

^(a)      “Throughput capacity” represents estimated capacity for processing crude oil, intermediates, and other feedstocks. Total estimated crude oil capacity is approximately 2.2 million BPD.

^(b)      Represents the combined capacities of two refineries – the Corpus Christi East and Corpus Christi West Refineries.

^(c)      The Aruba Refinery was idled in July 2009, but resumed operations in January 2011.

^(d)      We sold our Paulsboro, New Jersey Refinery in the fourth quarter of 2010, as described in Note 3 of Notes to Consolidated Financial Statements. Throughput capacity of this refinery was approximately 185,000 BPD.

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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, 2010. Our total combined throughput volumes averaged 2.129 million BPD for the year ended December 31, 2010. (The information presented excludes the charges and yields of the Paulsboro Refinery, which we sold in the fourth quart er of 2010, as more fully described in Note 3 of Notes to Consolidated Financial Statements.)

Combined Refining Charges and Yields
Charges:
	sour crude oil	40	%
	acidic sweet crude oil	3	%
	sweet crude oil	31	%
	residual fuel oil	10	%
	other feedstocks	5	%
	blendstocks	11	%
Yields:
	gasolines and blendstocks	49	%
	distillates	33	%
	petrochemicals	3	%
	other products (includes gas oil, No. 6 fuel oil, petroleum coke, and asphalt)	15	%

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 endedDecember 31, 2010. Total throughput volumes for the Gulf Coast refining region averaged 1.28 million BPD for the year ended December 31, 2010.

Combined Gulf Coast Region Charges and Yields
Charges:
	sour crude oil	52	%
	acidic sweet crude oil	2	%
	sweet crude oil	11	%
	residual fuel oil	16	%
	other feedstocks	6	%
	blendstocks	13	%
Yields:
	gasolines and blendstocks	45	%
	distillates	33	%
	petrochemicals	4	%
	other products (includes ga s oil, No. 6 fuel oil, petroleum coke, and asphalt)	18	%

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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 sour crude oil and residual fuel oil into premium products such as RBOB. The East Refinery processes sour 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 trans fer of various feedstocks and blending components between the two refineries and the sharing of resources. The refineries typically receive and deliver feedstocks and products by tanker and barge via deepwater docking facilities along the Corpus Christi Ship Channel. Three truck racks with a total of 16 bays service local markets for gasoline, diesel, jet fuels, liquefied petroleum gases, and asphalt. Finished products are distributed across the refinery docks into ships or barges, and are transported via third-party pipelines to the Colonial, Explorer, Valley, and other major pipelines.

Port Arthur Refinery. Our Port Arthur Refinery is located on the Texas Gulf Coast app roximately 90 miles east of Houston. The refinery processes primarily heavy sour crude oils and other feedstocks into gasoline blendstocks, 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 and across the refinery docks into ships or barges.

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 oth er 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 U.S.

Texas City Refinery. Our Texas City Refinery is located southeast of Houston on the Texas City Ship Channel. The refinery processes sour crude oils into a wide slate of products. The refinery receives and delivers its feedstocks and products by ship and barge via deepwater docking facilities along the Texas City Ship Channe l 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 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 and West Coast regions. The refinery receives crude oil by ship at its two deepwater marine docks, which can berth ultra-large crude carriers. The refinery's products are delivered by ship primarily into markets in the U.S., the Caribbea n, Europe, and South America.

Houston Refinery. Our Houston Refinery is located on the Houston Ship Channel. It processes a mix of crude oils and low-sulfur residual fuel oil into reformulated gasoline and distillates. The refinery receives its feedstocks via tanker at deepwater docking facilities along the Houston Ship Channel and interconnecting pipelines with the Texas City Refinery. It delivers its products through major refined-product pipelines, including the Colonial, Explorer, Orion, and TEPPCO pipelines.

Three Rivers Refinery. Our Three Rivers Refinery is located in South Texas between Corpus Christi and San Antonio. It processes sweet and medium sour crude oils into 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 and trucks. A 70-mile pipeline 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, 2010. Total throughput volumes for the West Coast refining region averaged approximately 256,000 BPD for the year ended December 31, 2010.

Combined West Coast Region Charges and Yields
Charges:
	sour crude oil	51	%
	acidic sweet crude oil	8	%
	sweet crude oil	14	%
	other feedstocks	12	%
	blendstocks	15	%
Yields:
	gasolines and blendstocks	63	%
	distillates	22	%
	other products (includes gas oil, No. 6 fuel oil, petroleum coke, and asphalt)	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 CARB when blended with ethanol.) The refinery receives crude oil feedstocks via a marine 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 system in California.

Wilmington Refinery. Our Wilmington Refi nery 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, 2010. Total throughput volumes for the Mid-Continent refining region averaged approximately 398,000 BPD for the year ended December 31, 2010.

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Combined Mid-Continent Region Charges and Yields
Charges:
	sour crude oil	12	%
	sweet crude oil	79	%
	other feedstocks	1	%
	blendstocks	8	%
Yields:
	gasolines and blendstocks	55	%
	distillates	35	%
	petrochemicals	3	%
	other products (includes gas oil, No. 6 fuel oil, and asphalt)	%

Memphis Refinery. Our Memphis Refinery is located in Tennessee along the Mississippi River's Lake McKellar. It processes primarily sweet crude oils. Most 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 network, including one pipeline directly to the Memphis airport.

McKee Refinery. Our McKee Refinery is located in the Texas Panhandle. It processes primarily sweet crude oils into 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 100 miles south of Oklahoma City. It processes medium sour and sweet crude oils into conventional gasoline, ultra-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 third-party crude oil pipelines. Foreign, mid-continent, and other domestic crude oils are received via third-party pipelines. Refined products are transported to market via railcars, trucks, and the Magellan pipeline system.

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Northeast

The following table presents the percentages of principal charges and yields for the Quebec City Refinery for the year ended December 31, 2010. Total throughput volumes for the Northeast refining region averaged approximately 195,000 BPD for the year ended December 31, 2010.

Northeast Region Charges and Yields
Charges:
	acidic sweet crude oil	10	%
	sweet crude oil	86	%
	other feedstocks	2	%
	blendstocks	2	%
Yields:
	gasolines and blendstocks	41	%
	distillates	44	%
	petrochemicals	1	%
	other products (includes gas oil, No. 6 fuel oil, petroleum coke, and asphalt)	14	%

Quebec City Refinery. Our Quebec City Refinery is located in Lévis, Canada (near Quebec City). It processes sweet, high mercaptan 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 nav igate the St. Lawrence River year-round. The refinery transports its products to its terminals in Quebec and Ontario primarily by train, and also uses ships and trucks extensively throughout eastern Canada.

Feedstock Supply

Approximately 58 percent 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 feedstoc ks 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 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 our 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 nego tiated price specific to us. About 78 percent of our crude oil feedstocks under term supply agreements are imported from foreign sources and about 22 percent are domestic. If 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 adva nce of the delivery date and holding inventories of crude oils and refined products.

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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 marine transportation facilities and interconnect with common-carrier pipeline systems, allowing us to sell products in most major geographic regions of the U.S. and eastern Canada. No customer accounted for more than 10 percent of our total operating revenues in 2010.

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 U.S..

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 4,000 branded sites. These sites are indepen dently owned and are supplied by us under multi-year contracts. For wholesale branded sites, we promote our Valero^® brand throughout the U.S. In addition, we offer the Beacon^® brand in California and the Shamrock^® brand elsewhere in the U.S.

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.

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 sell a variety of other pr oducts 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 five 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 napthenic oils at one of our refineries suitable for a wide variety of lubricant and process applications.

•     NGLs produced at our refineries include butane, isobutane, and propane. These products can b e 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.

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•     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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ETHANOL

We own 10 ethanol plants with a combined ethanol production capacity of about 1.1  billion gallons per year. Our ethanol plants are dry mill facilities¹that process corn to produce ethanol and distillers grains.² We source our corn supply from local farmers and commercial elevators. Our facilities receive corn by rail and truck. On our website, we publish a corn bid for local farmers and cooperative dealers to use to facilitate corn supply transactions.

After processing, our ethanol is held in storage tanks on-site pending loading to trucks and railcars. We sell our ethanol (i) to large customers – primarily refiners and gasoline blenders – under term and spot contracts, and (ii) in bulk markets such as New York, Chicago, Dallas, Florida, and the West Coast. We also use our ethanol for our own needs in blending gasoline. We ship our dry distillers grains (DDG) by truck or rail primarily to animal feed customers in the U.S. and Mexico, with some sales into the Far East. We also sell modified distillers grains locally at our plant sites.

The following table presents the locations of our ethanol plants, their approximate ethanol and DDG production capacit ies, and their approximate corn processing capacities.

State	City	Ethanol Production (in gallons per year)	Production of DDG (in tons per year)	Corn Processed (in bushels per year)
Indiana	Linden	110 million	350,000	40 million
Iowa	Albert City	110 million	350,000	40 million
	Charles City	110 million	350,000	40 million
	Fort Dodge	110 million	350,000	40 million
	Hartley	110 million	350,000	40 million
Minnesota	Welcome	110 million	350,000	40 million
Nebraska	Albion	110 million	350,000	40 million
Ohio	Bloomingburg	110 million	350,000	40 million
South Dakota	Aurora	120 million	390,000	43 million
Wisconsin	Jefferson	110 million	350,000	40 million
	Total	1,110 million	3,540,000	403 million

Ethanol production from our 10 plants in the fourth quarter of 2010 averaged 3.25 million gallons per day. We acquired our Iowa, Minnesota, Nebraska, and South Dakota plants in the second quarter of 2009. We acquired our Indiana, Ohio, and Wisconsin plants in the first quarter of 2010. For additional information regarding these acquisitions, see Note 2 of Notes to Consolidated Financial Statements.

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¹    Ethanol is commercially produced using either the wet mill or dry mill process. Wet milling involves separating the grain kernel into its component parts (germ, fiber, protein, and starch) prior to fermentation. In the dry mill process, the entire grain kernel is ground into flour. The starch in the flour is converted to ethanol during the fermentation process, creating carbon dioxide and distillers grains.

  ;

²    During fermentation, nearly all of the starch in the grain is converted into ethanol and carbon dioxide, while the remaining nutrients (proteins, fats, minerals, and vitamins) are concentrated to yield modified distillers grains, or, after further drying, dried distillers grains. Distillers grains generally are an economical partial replacement for corn, soybean, and dicalcium phosphate in feeds for livestock, swine, and poultry.

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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 and services 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 U.S. 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 and services through our company-operated retail sites. For the year ended December 31, 2010, total sales of refined products through Retail-U.S.’s retail sites averaged approximately 119,900 BPD. In addition to transportation fuels, our company-operated convenience stores sell tobacco products, beer, fast food s and sandwiches, snacks, fountain drinks, bagged ice, and candy.  Our stores also offer services such as ATM access, money orders, lottery tickets, car wash facilities, air and water, and video rentals. On December 31, 2010, we had 994 company-operated sites in Retail-U.S. (of which 80 percent were owned and 20 percent were leased). Our company-operated stores are operated primarily under the Corner Store^® brand name. 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 th rough 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, 2010, total retail sales of refined products through Retail-Canada averaged approximately 75,400 BPD. Transportation fuels are sold under the Ultramar^® brand through a network of 812 outlets throughout eastern Canada. On December 31, 2010, we owned or leased 392 retail stores in Retail-Canada and distributed gasoline to 420 dealers and independent jobbers. In addition, Retail-Canada operates 83 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 138,000 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 sup pliers, 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 U.S. 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 prospect s.

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 benchm ark crude oils, such as West Texas Intermediate and Louisiana Light Sweet crude oils. 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 that we do not control. 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, or Fitch were to downgrade our long-term rating, particularly below investment grade, our borrowing costs would increase,

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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 below investment g rade 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 generated from operations 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 in financial markets may materially impact the ability of the participating financial institutions to fun d their commitments to us under our various financing facilities. Accordingly, we may not be able to obtain the full amount of the funds available under our financing facilities to satisfy our cash requirements, and our failure to do so could have a material adverse effect on our operations and financial position.

Compliance with and changes in environmental laws, including proposed climate change laws and regulations, 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.&nb sp; 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, the level of expenditures required for environmental matters could increase in the future.  In particular, current and future legislative action and regulatory initiatives could result in changes to operating permits, additional remedial actions, material changes in operations, increased capital expenditures and operating costs, increased cost s of the goods we sell, and decreased demand for our products that cannot be assessed with certainty at this time. Our refining processes produce significant amounts of carbon dioxide and the fuels we manufacture are the primary source of carbon dioxide emitted from transportation activities. Federal and state restrictions on greenhouse gas emissions - including so-called “cap-and-trade” programs targeted at reducing carbon dioxide emissions - could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

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.

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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 U.S. and foreign countries have affected our operations in the past and will continue to do so in the future.

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 co mpetitive 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 competitor s 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 w ere 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 ded uctibles 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. Significant disruptions in financial markets could lead to a 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

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unlikely to perform in the event of a covered incident. However, in light of this uncertainty and the risk of a volatile financial market, we c an make no assurances that we will be able to obtain the full amount of our insurance coverage for insured events.

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

We are subject to extensive tax liabilities, including U.S., 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 liabiliti es 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.

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, including proposed climate change laws and regulations, could adversely affect our performance,”

•     I tem 3 “Legal Proceedings” under the caption “Environmental Enforcement Matters,” and

•     Item 8 “Financial Statements and Supplementary Data” in Note 10 of Notes to Consolidated Financial Statements under the caption “E nvironmental Liabilities.”

Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2010, our capital expenditures attributable to compliance with environmental regulations were approximately $730 million, and are currently estimated to be $260 million for 2011 and $80 million for 2012. The estimates for 2011 and 2012 do not include amounts related to capital investments at our facilities that management has deemed to be strategic investments. These amounts could materially change as a result of federal and state legislative and regulatory actions.

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 and transportation 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, 2010, we were the lessee under a number of cancelable and noncancelable leases for certain properties. Our leases are discussed more fully in Notes 11 and 12 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.

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 12 of Notes to Consolidated Financial Statements under the caption “Litigation Matters.”

•     Retail Fuel Temperature Litigation

•     Other Litigation

Environmental Enforcement Matters

While it is not possible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against us, we believe that there would be no material effect on our financial position or results of operations. We are reporting these proceedings to comply with SEC regulations, which require us to disclose certain information about proceedings arising under federal, state, or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.

United States Environmental Protection Agency (EPA) (mobile source enforcement). In November 201 0, the EPA issued a letter to us formalizing a proposed penalty of $585,000 in connection with eight alleged violations of federal fuels regulations (most of which were self-reported) purportedly occurring from March 2004 to 2006 at various refineries and terminals. We are negotiating with the EPA to resolve this matter.

Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery). In the fourth quarter of 2010, we settled 22 violation notices (VN’s) with the BAAQMD that were issued in 2006 and 2007. We presently have outstanding 78 VN’s issued by the BAAQMD from 2008 to 2010 for various alleged air regulation and air permit violations at our Benicia Refinery and asphalt plant. No penalties have been specified in these VN’s. We are pursuing settlement of all VN’s.

New Jersey Department of Environmental Protection (NJDEP) (Paulsboro Refinery). We previously disclosed certain outstanding proceedings between the NJDEP and the Paulsboro Refinery in our Annual Report on Form 10-K for the year ended December 31, 2009; our Quarterly Report on Form 10-Q for the quarter ended March 31, 2010; and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010. Most of these proceedings were resolved in the first quarter of 2011 through a negotiated settlement with the NJDEP. The other proceedings were resolved with entry of Administrative Compliance Orders in the second quarter and fourth quarter of 2010.

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 notices of violation alleging violations of air and waste regulations at Premcor’s Hartford, Illinois terminal and closed refinery. We are negotiating the terms of a consent order for corrective action.

Texas Commission on Environmental Quality(TCEQ) (Corpus Christi East Refinery). In October 2010, we received a proposed agreed order from the TCEQ relating to unauthorized air emissions during a flaring event and excess air emissions from three plant boilers at our Corpus Christi East Refinery. The gross penalty demand was stated to be more than $100,000, but following our discussions with the TCEQ to clarify certain issues under question, we reasonably believe that the ultimate penalty amount for this matter will fall below $100,000.

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TCEQ (Corpus Christi West Refinery and Texas City Refinery). In the second quarter of 2009, the TCEQ issued a notice of enforcement (NOE) to our Corpus Christi West Refinery. The NOE alleged excess air emissions relating to two cooling tower leaks that occurred in 2008. The penalty demanded in t he TCEQ’s Preliminary Report and Petition was $1,100,424. In the fourth quarter of 2010, the TCEQ issued a proposed agreed order with a combined penalty of $591,858 pertaining to alleged cooling tower emissions at our Corpus Christi West Refinery and alleged flaring emissions at our Texas City Refinery. We are negotiating with the TCEQ to resolve this matter.

TCEQ (Three Rivers Refinery). In January 2011, we received a proposed agreed order from the TCEQ relating to our Three Rivers Refinery. In the order, the TCEQ alleges unauthorized discharge of wastewater and oily storm water and the unauthorized storage of industrial solid waste. The gross penalty demand is stated to be $105,9 25, but is subject to reduction to $84,740 under certain circumstances. We are in discussions with the TCEQ to resolve this matter.

ITEM 4. RESERVED

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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, 2011 there were 7,660holders 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 2010 and 2009.

	Sales Prices of the Common Stock							Dividends Per Common Share
Quarter Ended	High			Low
2010:
December 31	$	23.35		$	17.25			$	0.05
September 30	18.31			15.65				0.05
June 30	21.37			16.36				0.05
March 31	20.69			17.45				0.05
2009:
December 31	$	20.67		$	15.89			$	0.15
September 30	20.50		15.57				0.15
June 30	23.30			16.03				0.15
March 31	25.85			16.24		&nb sp;		0.15

On January 25, 2011, our board of directors declared a quarterly cash dividend of $0.05 per common share payable March 16, 2011 to holders of record at the close o f business on February 16, 2011.

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 2010.

Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Not Purchased as Part of Publicly Announced Plans or Programs (a)	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (b)
October 2010	160,072	$	18.11	160,072	—		$ 3.46 billion
November 2010	183,109	$	18.64	183,109	—		$ 3.46 billion
December 2010	249,985	$	21.11	249,985	—	&n bsp;	$ 3.46 billion
Total	593,166	$	19.54	593,166	—		$ 3.46 billion

(a)    The shares reported in this column represent purchases settled in the fourth quarter of 2010 relating to (a) our purchases of shares in open-market transactions to meet our obligations under employee stock compensation 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.

(b)    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 $3&nbs p;billion common stock purchase program, which is in addition to the $6 billion program. This $3 billion program has no expiration date.

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The following p erformance 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.

The following line graph compares the cumulative total return¹ 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, 2005 and ending December 31, 2010. Our 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., Ex xon Mobil Corporation, Frontier Oil Corporation, Hess Corporation, Holly Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Sunoco, Inc., Tesoro Corporation, and Western Refining, Inc.

	12/2005		12/2006		12/2007		12/2008		12/2009		12/2010
Valero Common Stock	$	100.00	$	99.67	$	137.46	$	43.23	$	34.29	$	48.12
S&P 500	100.00		115.80		122.16		76.96		97.33		111.99
Peer Group	100.00		134.75		172.48		132.99		127.12		151.36

¹Assumes that an investment in Valero common stock and each index was $100 on December 31, 2005. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from December 31, 2005 through December 31, 2010.

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ITEM 6. SELECTED FINANCIAL DATA

The selected financial data for the five-year period ended December 31, 2010 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,
	2010 (a) (b)		2009 (a) (b)				2008 (a)			2007 (a)		2006 (a)
Operating revenues	$	82,233	$	64,599			$	106,676		$	85,079	$	78,187
Operating income	1,876		83				531			6,375		7,076
						&nbs p;
Income (loss) from   continuing operations	923		(273		)		(1,154		)	4,230		4,866
Earnings (loss) per common   share from continuing   operations - assuming dilution	1.62		(0.50		)		(2.20		)	7.31		7.69
Dividends per common share	0.20		0.60				0.57			0.48		0.30
Property, plant and equipment, net	22,669		21,615				20,205			18,873		17,419
Goodwill	—		—				—			3,943		4,019
Total assets	37,621		35,572				34,417			42,722		37,753
Debt and capital lease   obligations, less current portion	7,515		7,163				6,264			6,470		4,619
Stockholders’ equity	15,025		14,725				15,620			18,507		18,605

___________________________

(a)     The information presented in this table excludes the results of operations related to the Paulsboro Refinery, which have been presented as discontinued operations due to the sale of the refinery in December 2010. In addition, the assets related to the Paulsboro Refinery have been presented as asse ts held for sale for all years presented. As a result, the property, plant and equipment and goodwill amounts reflected herein have changed from the amounts presented in our annual report on Form 10-K for the year ended December 31, 2009.

(b)     We acquired three ethanol plants in the first quarter of 2010 and seven ethanol plants in the second quarter of 2009. The information presented for 2010 and 2009 includes the results of operations of those plants commencing on their respective acquisition closing dates.

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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, per-share amounts include the effect of common equivalent shares for periods reflecting income from continuing operations and exclude the effect of common equivalent shares for periods reflecting a loss from continuing operations.

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 “OVERVIEW AND 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, includ ing gasoline, diesel, home heating oil, and convenience store merchandise margins;

•     future ethanol margins;

•     expectations regarding feedstock costs, including crude oil differentials, and operating expenses;

•     anticipated levels of crude oil and refined product inventories;

•   &nb sp; 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 U.S., Canada, and elsewhere;

•     expectations regarding environmental, tax, and other regulatory initiatives; and

•     the effect of general economic and other conditions on refining 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;

•     domestic and foreign demand for, and supplies of, refined products such as gasoline, diesel fuel, jet fuel, home heating oil, and petrochemicals;

•     domestic and foreign demand for, and supplies of, crude oil and other feedstocks;

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•     the ability of the members of the Organization of Petroleum Exporting Countries (OPEC) to agree on and to maintain crude oil price and production controls;

•     the level of consumer demand, including seasonal fluctuations;

•     refinery overcapacity or undercapacity;

•     our ability to successfully integrate any acquired businesses into our operations;

•     the actions taken by competitors, including both pricing and adjustments to refining capacity in response to market conditions;

•     the level of foreign imports of refined products;

•     accidents or other unscheduled shutdowns affecting our refineries, machinery, pipelines, or equi pment, 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;

•     the levels of government subsidies for ethanol and other alternative fuels;

•     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;

•     lower than expected ethanol margins;

•     earthquakes, hurricanes, tornadoes, and irregular weather, which can unforeseeably affect the price or availability of natural gas, crude oil, grain and other feedstocks, and refined products and ethanol;

•     ru lings, 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, including tax and environmental regulations, such as those to be implemented under the California Global Warming Solutions Act (also known as AB32) and the EPA’s regulation of greenhouse gases, which may adverse ly 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 and 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-lookin g 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 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.

24

OVERVIEW AND OUTLOOK

We reported income from continuing operations of $923 million, or $1.62 per share, for the year ended December 31, 2010, compared to a loss from continuing operations of $273 million, or $0.50 per share, for the year ended December 31, 2009. These results were primarily due to our refining segment operations, which generated operating income of $1.9 billion for the year ended December 31, 2010, compared to operating income of $247 million for the year ended December 31, 2009. The increase in refining operating income was primarily due to improved margins for the distillate products we produce and wider sour crude oil differentials. The sour crude oil differential is the difference between the price of sweet crude oil and the price of sour crude oil. We believe that the improved distillate margins are due to an increase in the demand for refined products resulting from the improving U.S. and worldwide economies. Although improving, refined product demand has not returned to levels experienced prior to the economic slowdown that began in 2008. Excess worldwide refinery capacity and high levels of refined product inventories continue to constrain refined product margins.

In response to the worldwide economic slowdown, and as a result of our assessment of the operating performance and profitability of our refineries, we temporarily shut down our Aruba Refinery in July 2009 and p ermanently shut down our Delaware City Refinery in November 2009. In June 2010, we sold our shutdown Delaware City Refinery assets and associated terminal and pipeline assets for $220 million of cash proceeds, and in December 2010, we sold our Paulsboro Refinery and associated inventory for $547 million of cash proceeds and a $160 million one-year note. Our Aruba Refinery remained idle throughout 2010, but in the third quarter of 2010, we began refinery-wide maintenance to prepare the refinery’s production units for restart due to improved sour crude oil differentials and a general improvement in refining economics. The Aruba Refinery resumed operations in January 2011.

Our retail segment generated operating income of $346 million for the year ended December 31, 2010 compared to operating income of $293 million for the year ended December 31, 2009. The 2010 results benefited from the blending of ethanol into gasoline sold by our retail segment. For most of 2010, ethanol was a lower cost product than gasoline and this lower cost results in an increase in retail fuel margins. During the latter part of 2010, the difference between the cost of gasoline and the cost of et hanol began to narrow and the benefit that our retail segment experienced through most of 2010 from the blending of ethanol into gasoline narrowed. Should this trend continue in 2011, our retail fuel margins may be negatively impacted as compared to 2010.

In the second quarter of 2009, we entered the ethanol business through the acquisition of seven ethanol facilities, and we acquired three additional facilities in the first quarter of 2010. We believe that ethanol is a natural fit for us because we manufacture transportation fuels. During the year ended December 31, 2010, our ethanol segment generated operating in come of $209 million, compared to $165 million for the year ended December 31, 2009. The ethanol business is dependent on margins between ethanol and corn feedstocks and can be impacted by U.S. government subsidies and biofuels (including ethanol) mandates.

To support our financial strength and liquidity, we issued $1.25 b illion in debt during the first quarter of 2010 at interest rates favorable to those on our existing debt. We used a portion of the proceeds to redeem $484 million of debt with a higher interest rate, and the remainder was used for general corporate purposes. In December 2010, we received proceeds of $300 million under a financing agreement associated with the issuance of $300 million of Gulf Opportunity Zone Revenue Bonds (GO Zone Bonds). In February 2011, we paid $300 million to acquire the GO Zone Bonds, which we expect to hold and reissue in future years to help fund the construction costs of a capital project at our St. Charles Refinery.

& nbsp;

25

We expect the U.S. and worldwide economies to continue to recover slowly, and we expect refined product demand to increase. The increase in anticipated refined product demand is expected to result in an increase in crude oil production, which we believe will result in the production of more sour crude oils and continued improvement in sour crude oil differentials. The expected increases in refined product demand and sour crude oil production should favorably impact our refined product margins. However, we expect that the current excess global refining capacity will put pressure on refining margins and could result in ongoing production constraints or refinery shutdowns in the refining industry. We will continue to optimize our refining assets based on market conditions.

26

RESULTS OF OPERATIONS

The following tables highlight our results of operations, our operating performance, and market prices that directly impact our operations. The narrative following these tables provides an analysis of our results of operations.

2010 Compared to 2009

Financial Highlights (a) (b) (c)

(millions of dollars, except per share amounts)

	Year Ended December 31,
	2010			2009		Change
Operating revenues	$	82,233	$	64,599	$	17,634
Costs and expenses:
Cost of sales (d)	74,458			58,686		15,772
Operating expenses:
Refining	2,944			2,880		64
Retail (d)	654			626		28
Ethanol	363			169		194
General and administrative expenses	531			572		(41	)
Depreciation and amortization expense:
Refining	1,210			1,194		16
Retail	108			101		7
Ethanol	36			18		18

Corporate51  48  3 Asset impairment loss (e)2  222  (220)Total costs and expenses80,357  64,516  15,841 Operating income1,876  83  1,793 Other income, net106  17  89 Interest and debt expense:     Incurred(574) (521) (53)Capitalized90  105  (15)      

Income (loss) from continuing operations

    before income tax expense (benefit)

1,498  (316) 1,814 Income tax expense (benefit)575  (43) 618 Income (loss) from continuing operations923  (273) 1,196 Loss from discontinued operations, net of income taxes(599) (1,709) 1,110 Net income (loss)$324  $(1,982) $2,306 Earnings (loss) per common share – assuming dilution:     Continuing operations$1.62  $(0.50) $2.12 Discontinued operations(1.05) (3.17) 2.12 Total$0.57  $(3.67) $4.24 

________________

See note references on pages 31 and 32.

27

Operating Highlights

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

	Year Ended December 31,
	2010			2009			Change
Refining (a) (b):
Operating income (e)	$	1,903		$	247		$	1,656
Throughput margin per barrel (f)	$	7.80		$	6.00		$	1.80
Operating costs per barrel (e):
Operating expenses	$	3.79		$	3.71		$	0.08
Depreciation and amortization expense	1.56			1.55			0.01
Total operating costs per barrel	$	5.35		$	5.26		$	0.09
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude	458			457			1
Medium/light sour crude	386			417			(31		)
Acidic sweet crude	60			64			(4		)
Sweet crude	668			616			52
Residuals	204			170			34
Other feedstocks	110			136		(26		)
Total feedstocks	1,886		& nbsp;	1,860			26
Blendstocks and other	243			264			(21		)
Total throughput volumes	2,129

2,124  5       Yields (thousand barrels per day):     Gasolines and blendstocks1,048  1,040  8 Distillates712  692  20 Other products (g)395  402  (7)Total yields2,155  2,134  21       Retail–U.S. (d):     Operating income$200  $170  $30Company-operated fuel sites (average)990  999  (9)Fuel volumes (gallons per day per site)5,086  4,983  103 Fuel margin per gallon$0.140  $0.126  $0.014 Merchandise sales$1,205  $1,171  $34 Merchandise margin (percentage of sales)28.3% 28.1% 0.2%Margin on miscellaneous sales$86  $87  $(1)Operating expenses$412 $405  $7 Depreciation and amortization expense$73  $70  $3       Retail–Canada (d):     Operating income$146  $123  $23 Fuel volumes (thousand gallons per day)3,168  3,159  9 Fuel margin per gallon$0.271  $0.247  $0.024 Merchandise sales$240  $201  $39 Merchandise margin (percentage of sales)30.1% 28.3

%

 1.8%Margin on miscellaneous sales$38  $33  $5 Operating expenses$242  $221  $21 Depreciation and amortization expense$35  $31  $4 __________

See note references on pages 3 1 and 32.

28

Operating Highlights (continued)

(millions of dollars, except per gallon amounts)

	Year Ended December 31,
	2010		2009		Change
Ethanol (c):
Operating income	$	209	$	165	$	44
Ethanol production (thousand gallons per day)	3,021		1,479		1,542
Gross margin per gallon of ethanol production	$	0.55	$	0.65	$	(0.10	)
Operating costs per gallon of ethanol production:
Operating expenses	$	0.33	$	0.31	$	0.02
Depreciation and amortization expense	0.03		0.03

— Total operating costs per gallon of ethanol production$0.36  $0.34  $0.02 

__________

See note references on pages 31 and 32.

29

Refining Operating Highlights by Region (e) (h)

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2010			2009			Change
Gulf Coast:
Operating income (loss)	$	1,349		$	(56	)	$	1,405
Throughput volumes (thousand barrels per day)	1,280			1,274			6
Throughput margin per barrel (f)	$	8.20		$	5.13		$	3.07
Operating costs per barrel:
Operating expenses	$	3.71		$	3.71		$	—
Depreciation and amortization expense	1.60			1.54			0.06
Total operating costs per barrel	$	5.31		$	5.25		$	0.06
Mid-Continent:
Operating income	$	339		$	189		$	150
Throughput volumes (thousand barrels per day)	398			387			11
Throughput margin per barrel (f)	$	7.33		$	6.52		$	0.81
Operating costs per barrel:
Operating expenses	$	3.60		$	3.66		$	(0.06	)
Depreciation and amortization expense	1.40			1.53			(0.13		)
Total operating costs per barrel	$	5.00		$	5.19		$	(0.19	)
Northeast (a) (b):
Operating income	$	129		$	196		$	(67	)
Throughput volumes (thousand barrels per day)	195			196			(1		)
Throughput margin per barrel (f)	$	6.18		$	6.36		$	(0.18	)
Operating costs per barrel:
Operating expenses	$	2.99		$	2.31		$	0.68
Depreciation and amortization expense	1.39			1.33			0.06
Total operating costs per barrel	$	4.38		$	3.64		$	0.74
West Coast:
Operating income	$	88		$	252		$	(164	)
Throughput volumes (thousand barrels per day)	256			267			(11		)
Throughput margin per barrel (f)	$	7.73		$	9.16		$	(1.43	)
Operating costs per barrel:
Operating expenses	$	5.09		$	4.83		$	0.26
Depreciation and amortization expense	1.69			1.74			(0.05		)
Total operating cos ts per barrel	$	6.78		$	6.57		$	0.21
Operating income for regions above	$	1 ,905		$	581		$	1,324
Asset impairment loss applicable to refining	(2		)	(220		)	218
Loss contingency accrual related to Aruba tax matter (i)	—			(114		)	114
Total refining operating income	$	1,903		$	247		$	1,656

__________

See note references on pages 31 and 32.

30

Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)

	Year Ended December 31,
	2010		2009			Change
Feedstocks:
West Texas Intermediate (WTI) crude oil	$	79.41	$	61.69		$	17.72
Louisiana Light Sweet crude oil	81.62		62.25			19.37
WTI less Mars crude oil	1.41		1.36			0.05
WTI less Maya crude oil	9.13		5.19			3.94
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI	7.51		7.61			(0.10		)
Ultra-low-sulfur diesel less WTI	11.14		8.02			3.12
Propylene less WTI	7.92		(1.31		)	9.23
U.S. Mid-Continent:
Conventional 87 gasoline less WTI	8.20		8.01			0.19
Ultra-low-sulfur diesel less WTI	11.91		8.26			3.65
U.S. Northeast:
Conventional 87 gasoline less WTI	8.50		7.99			0.51
Ultra-low-sulfur diesel less WTI	12.76		9.55			3.21
U.S. West Coast:
CARBOB 87 gasoline less WTI	13.88		15.75			(1.87		)
CARB diesel less WTI	13.45		9.86			3.59
New York Harbor corn crush (dollars per gallon)	0.39		0.47			(0.08		)

__________

The following notes relate to references on pages 27 through 31.

(a)     On December 17, 2010, we sold our Paulsboro Refinery and associated inventory to PBF Holding Company LLC (PBF Holding) for $547 million of cash proceeds and a $160 million one-year note, resulting in a pre-tax loss on the sale of $980 million ($610 million after taxes). The results of operations of the refinery, including the loss on the sale, have been presented as discontinued operations for both years presented. The refining segment and Northeast Region operating highlights exclude the Paulsboro Refinery for both years presented.

(b)     During the fourth quarter of 2009, we permanently shut down our Delaware City Refinery and wrote down the book value of the refinery assets to net realizable value, resulting in a pre-tax loss on the shutdown of $1.9 billion ($1.2 billion after taxes). On June 1, 2010, we sold the shutdown refinery assets and associated terminal and pipeline assets to wholly owned subsidiaries of PBF Energy Partners LP (PBF) for $220 million of cash proceeds, resulting in a pre-tax gain on the sale of the refinery assets of $92 million ($58 million after taxes) and an insignificant gain on the sale of the terminal and pipeline assets. The results of operations of the shutdown refinery, including the gain on the sale in 2010 and the loss on the shutdown in 2009, have been presented as discontinued operations for both years presented. The ref ining segment and Northeast Region operating highlights exclude the Delaware City Refinery for both years presented. The terminal and pipeline assets associated with the refinery were not shut down in 2009 and continued to be operated until they were sold; the results of these operations are reflected in continuing operations for both years presented.

(c)     We acquired three ethanol plants in the first quarter of 2010 and seven ethanol plants in the second quarter of 2009. The information presented includes the results of operations of those plants comme ncing on their respective acquisition or closing dates. Ethanol production volumes are based on total production during each year divided by actual calendar days per year.

(d)     Credit card transactions processing fees incurred by our retail segment of $76 million for the year ended December 31, 2009 have been reclassified from retail operating expenses to cost of sales. The Retail–U.S. and Retail–Canada operating highlights

31

have been restated to reflect this reclassification.

(e)     The asset impairment loss relates primarily to the permanent cancellation of certain capital projects classified as “construction in progress” as a result of the unfavorable impact of the economic slowdown on refining industry fundamentals. The asset impairment loss amounts are included in the refining segment operating income but are excluded from the regional operating income amounts and the consolidated and regional operating costs per barrel.

(f)     Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.

(g)     Other produc ts primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, and asphalt.

(h)     The refining 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, 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 Refinery; and the West Coast refining region includes the Benicia and Wilm ington Refineries.

(i)     A loss contingency accrual of $140 million was recorded in the third quarter of 2009 related to our dispute with the Government of Aruba (GOA) regarding a turnover tax on export sales as well as other tax matters. The portion of the loss contingency accrual that relates to the turnover tax was recorded in cost of sales during the year ended December 31, 2009, and therefore is included in refining operating income (loss) but has been excluded in determining throughput margin per barrel.

General

Operating revenues increased 27 percent (or $17.6 billion) for the year ended December 31, 2010 compared to the year ended December 31, 2009 primarily as a result of higher average refined product prices between the two years. Operating income increased $1.8 billion and income from continuing operations before taxes also increased $1.8 billion for the year ended December 31, 2010, compared to the amounts reported for the year ended December 31, 2009, primarily due to a $1.7 billion increase in refining segment operating income discussed below.

Refining

Operating income for our refining segment increased from $247 million for the year ended December 31, 2009 to $1.9 billion for the year ended December 31, 2010, primarily due to an overall improvement in operating results of $1.3 billion (discussed below), reduced asset impairment losses of $218 million, and the nonrecurrence of a $114 million loss contingency accrual in 2009. The asset impairment loss recorded in 2009 related to our decision to p ermanently cancel certain construction projects in response to the economic slowdown that began in 2008. We continue to evaluate our ongoing construction projects, but the number and significance of projects cancelled has substantially declined in 2010. The loss contingency accrual recorded in the third quarter of 2009 related to our dispute of a turnover tax on export sales in Aruba.

The $1.3 billion improvement in operating results was primarily due to a 30 percent increa se in throughput margin per barrel (an overall $1.80 per barrel increase between the comparable years). The increase in throughput margin per barrel was caused by a significant improvement in distillate margins and petrochemical (primarily propylene) margins, but those improvements were somewhat offset by a decline in gasoline margins in two of our refining regions. Throughput margin per barrel also benefited from wider sour crude oil differentials. The impact of these factors on our throughput margin per barrel is described below.

Changes in the margin that we receive for our products have a material impact on our resul ts of operations. For example, the benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel, which is a type of distillate, was $11.14 per barrel for the year ended December 31, 2010, compared to $8.02 per barrel for the year ended December 31, 2009, representing a favorable increase of $3.12 per barrel. Similar increases in distillate margins were experienced in other regions. We estimate that the increase in margin for distillates had an $820 million positive impact to our overall refining margin, year over year, as we produced 712,000 barrels per day of distillates during the year ended December 31, 2010. Similarly, the benchmark reference margin for U.S. Gulf Coast propylene was $7.92 per barrel for the year ended December 31, 2010, compared to a negative margin of $1.31 for the year ended December 31, 2009, representing a favorable increase of $9.23 per barrel. We estimate that the increase in margin for petrochemicals (primarily propylene) had a $199 million positive impact on our refining margin, year over year. Distillate and propylene margins

32

were higher in 2010 as compared to 2009 due to an increase in the industrial demand for these products resulting from the ongoing recovery of the U.S. and worldwide economies and exports.

The benchmark reference margin for U.S. Gulf Coast Conventional 87 gasoline (Gulf Coast 87 gasoline) was $7.51 per barrel for the year ended December 31, 2010, compared to $7.61 per barrel for the year ended December 31, 2009, representing an unfavorable decrease of $0.10 per barrel. CARBOB 87 gasoline benchmark reference margins decreased year over year to an even greater extent in the West Coast region (a $1.87 per barrel unfavorable decrease). We estimate that the decrease in gasoline margins had a $119 million negative impact to our overall refining margin, year over year, as we produced 1.05 million barrels per day of gasoline during the year ended December 31, 2010. Gasoline margins were lower in 2010 as compared to 2009 despite an increase in gasoline prices during 2010. We believe that the margins for gasoline were constrained due to continued weak consumer demand and high levels of inventory. In addition, our downstream customers increased the use of ethanol as a component in transportation fuels because its price was lower than the price of gasoline.

For the year ended December 31, 2010, the differential applicable to the price of sour crude oil as compared to the price of sweet crude oil was wider than the differential for the year ended December 31, 2009. For example, Maya crude oil, which is a type of sour crude oil, sold at a discount of $9.13 per barrel to WTI crude oil, a type of sweet crude oil, during the year ended December 31, 2010. This compares to a discount of $5.19 per barrel during the year ended December 31, 2009, representing a favorable increase of $3.94 per barrel. The benefit of this wider differential, however, was offset by a reduction of 30,000 barrels per day of sour crude oil that we processed during 2010 as compared to 2009. We estimate that the wider differentials for all types of sour crude oil that we process, offset by reduced throughput volumes, had a $196 million positive impact to our overall refining margin for 2010 as we processed 844,000 barrels per day of sour crude oils.

Retail

Retail operating income wa s $346 million for the year ended December 31, 2010 compared to $293 million for the year ended December 31, 2009. This 18 percent (or $53 million) increase was primarily due to increases in retail fuel margins of $57 million and merchandise margins of $27 million, partially offset by a $28 million increase in operating expenses.

Retail fuel margins are affected by the blending of ethanol with the gasoline sold by our retail segment. For most of 2010, ethanol was a lower cost product than gasoline and this lower cost resulted in an increase in retail fuel margins. For example, the Chicago Board of Trade (CBOT) price for a gallon of ethanol was $0.23 less than a gallon of Gulf Coast 87 gasoline for the year ended December 31, 2010, but there was little difference between the prices of these products for the year ended December 31, 2009. We estimate that the lower cost of ethanol had a $32 million positive impact to our U.S. retail fuel margins for 2010 as approximately 80 percent of the gasoline we sold during the year ended December 31, 2010 contained 10 percent ethanol. Retail fuel margins in our Canadian retail op erations increased by $27 million due to the favorable impact from the strengthening of the Canadian dollar relative to the U.S. dollar in 2010 compared to 2009. On average, Cdn$1 was equal to $0.96 during 2010 compared to $0.88 in 2009, representing an increase in value of nine percent.

Retail merchandise margins increased due to increased product pricing combined with improved product mix, and a favorable impact from the stronger Canadian dollar relative to the U.S. dollar in 2010 compared to 2009, as described above.

33

The increase in operating expenses was also due to the stronger Canadian dollar relative to the U.S. dollar in 2010 compared to 2009. The stronger Canadian dollar had a $21 million unfavorable impact on the 2010 operating expenses of our Canadian retail operations compared to 2009.

Ethanol

Ethanol operating income was $209 million for the year ended December 31, 2010, compared to $165 million for the year ended December 31, 2009. This increase of $44 million was primarily due to a full year of operations of the seven ethanol plants acquired in the second quarter of 2009 and the addition of three ethanol plants acquired in the first quarter of 2010, as described in Note 2 of Notes to Consolidated Financial Statements.

Corporate Expenses and Other

General and administrative expenses decreased $41 million for the year ended December 31, 2010 compared to the year ended December 31, 2009 primarily due to a favorable settlement with an insurance company for $40 million recorded in 2010, which offset an increase in litigation costs of $40 million recorded in 2009. After adjusting for these items, the $40 million increase in general and administrative expenses year over year resulted from an increase of $21 million for incentive compensation expenses and an increase of $18 million for environmental remed iation expenses.

“Other income, net” for the year ended December 31, 2010 increased $89 million from the year ended December 31, 2009 due to a pre-tax gain of $55 million related to the sale of our 50 percent interest in Cameron Highway Oil Pipeline Company (CHOPS) in November 2010 and the effect of a $42 million loss in 2009 on changes in the fair values of an earn-out agreement and associated derivative instruments that were entered into in connection with the sale of our Krotz Springs Refinery in 2008.

Interest and debt expense increased $68 million from the year ended December 31, 2009 to the year ended December 31, 2010. This increase is composed of a $53 million increase in interest incurred on $1.25 billion of debt issued in February 2010 and $1.0 billion of debt issued in March 2009 (see Note 11 of Notes to Consolidated Financial Statements) and a $15 million decrease in capitalized interest due to a reduction in capital expenditures between the years and the temporary suspension of activity on certain construction projects. We do not capitalize interest with respect to suspended construction projects until significant construction activities resume. We anticipate that significant construction activities will resume on certain construction projects in 2011.

Income tax expense increased $618 million from a $43 million benefit in 2009 to $575 million of expense in 2010 mainly as a result of higher operating income in 2010.

“Loss from discontinued operations, net of income taxes” decreased $1.1 billion from the year ended December 31, 2009 to the year ended December 31, 2010 due to the after-tax loss of $1.2 billion related to the permanent shutdown of the Delaware City Refinery in the fourth quarter of 2009. The results of operations for the Pauls boro and Delaware City Refineries, including the loss and gain, respectively, on their sales, are reflected in “Loss from discontinued operations, net of income taxes” as discussed in Note 3 of Notes to Consolidated Financial Statements.

34

2009 Compared to 2008

Financial Highlights (a) (b) (c)

(millions of dollars, except per share amounts)

(43

	Year Ended December 31,
	2009			2008			Change
Operating revenues	$	64,599		$	106,676		$	(42,077	)
Costs and expenses:
Cost of sales (d)	58,686			96,087			(37,401		)
Operating expenses:
Refining	2,880			3,731			(851		)
Retail (d)	626			676			(50		)
Ethanol	169			—			169
General and administrative expenses	572			559			13
Depreciation and amortization expense:
Refining	1,194			1,155			39
Retail	101			105			(4		)
Ethanol	18			—			18
Corporate	48			44			4
Asset impairment loss (e)	222			86			136
Gain on sale of Krotz Springs Refinery (f)	—			(305		)	305
Goodwill impairment loss (g)	—			4,007			(4,007		)
Total costs and expenses	64,516			106,145			(41,629		)
Operating income	83			531			(448		)
Other income, net	17			113			(96		)
Interest and debt expense:
Incurred	(521		)	(452		)	(69		)
Capitalized	105			92			13
Income (loss) from continuing operations     before income tax expense (benefit)	(316		)	284			(600		)
Income tax expense (benefit)	)		1,438

 (1,481)Loss from continuing operations(273) (1,154) 881 

Income (loss) from discontinued operations,

    net of income taxes

(1,709) 23  (1,732)Net loss$(1,982) $(1,131) $(851)Loss per common share – assuming dilution:  &n bsp;  Continuing operations$(0.50) $

(2.20

) $1.70 Discontinued operations(3.17) 0.04  (3.21)Total$(3.67) $(2.16) $(1.51)

__________

See note references on pages 39 and 40.

35

Operating Highlights

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

	Year Ended December 31,
	2009				2008			Change
Refining (a) (b) (f):
Operating income (e) (g) (k)	$	247			$	765		$	(518	)
Throughput margin per barrel (g) (h) (k)	$	6.00			$	11.16		$	(5.16	)
Operating costs per barrel (e):
Operating expenses	$	3.71			$	4.41		$	(0.70	)
Depreciation and amortization expense	1.55				1.37			0.18
Total operating costs per barrel	$	5.26			$	5.78		$	(0.52	)
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude	457				588			(131		)
Medium/light sour crude	417				460			(43		)
Acidic sweet crude	64				79			(15		)
Sweet crude	616				592			24
Residuals	170				189			(19		)
Other feedstocks	136				130			6
Total feedstocks	1,860				2,038			(178		)
Blendstocks and other	264				272			(8		)
Total throughput volumes	2,124				2,310			(186		)
Yields (thousand barrels per day):
Gasolines and blendstocks	1,040				1,040			—
Distillates	692				805			(113		)
Other products (i)	402				468			(66		)
Total yields	2,134				2,313			(179		)
Retail–U.S. (d):
Operating income	$	170			$	260		$	(90	)
Company-operated fuel sites (average)	999				973			26
Fuel volumes (gallons per day per site)	4,983				5,000			(17		)
Fuel margin per gallon	$	0.126			$	0.194		$	(0.068	)
Merchandise sales	$	1,171			$	1,097		$	74
Merchandise margin (percentage of sales)	28.1		%		29.2		%	(1.1		)%
Margin on miscellaneous sales	$	87			$	99		$	(12	)
Operating expenses	$	405			$	434		$	(29	)
Depreciation and amortization expense	$	70			$	70		$	—
Retail–Canada (d):
Operating income	$	123			$	109		$	14
Fuel volumes (thousand gallons per day)	3,159				3,193			(34		)
Fuel margin per gallon	$	0.247		;	$	0.252		$	(0.005	)
Merchandise sales	$	201			$	200		$	1
Merchandise margin (percentage of sales)	28.3		%		27.7		%	0.6		%
Margin on miscellaneous sales	$	33			$	36		$	(3	)
Operating expenses	$	221	& nbsp;		$	242		$	(21	)
Depreciation and amortization expense	$	31			$	35		$	(4	)

__________

See note references on pages 39 and 40.

36

Operating Highlights (continued)

(millions of dollars, except per gallon amounts)

	Year Ended December 31,
	2009		2008	Change
Ethanol (c):
Operating income	$	165	N/A	$	165
Ethanol production (thousand gallons per day)	1,479		N/A	1,479
Gross margin per gallon of ethanol production	$	0.65	N/A	$	0.65
Operating costs per gallon of ethanol production:
Operating expenses	$	0.31	N/A	$	0.31
Depreciation an d amortization expense	0.03		N/A	0.03
Total operating costs per gallon of ethanol production	$	0.34	N/A	$	0.34

__________

See note references on pages 39 and 40.

37

Refining Operating Highlights by Region (e) (h) (j)

(millions of dollars, except per barrel amounts)

Gulf Coast (f):

	Year Ended December 31,
	2009				2008			Change
				&nb sp;
Operating income (loss)	$	(56	)		$	3,267		$	(3,323	)
Throughput volumes (thousand barrels per day)	1,274				1,404			(130		)
Throughput margin per barrel (k)	$	5.13			$	11.57		$	(6.44	)
Operating costs per barrel:
Operating expenses	$	3.71			$	4.50		$	(0.79	)
Depreciation and amortization expense	1.54				1.30			0.24
Total operating costs per barrel	$	5.25			$	5.80		$	(0.55	)
Mid-Continent:
Operating income	$	189			$	580		$	(391	)
Throughput volumes (thousand barrels per day)	387				423			(36		)
Throughput margin per barrel	$	6.52			$	9.27		$	(2.75	)
Operating costs per barrel:
Operating expenses	$	3.66			$	4.24		$	(0.58	)
Depreciation and amortization expense	1.53				1.29			0.24
Total operating costs per barrel	$	5.19			$	5.53		$	(0.34	)
Northeast (a) (b):
Operating income	$	196			$	636		$	(440	)
Throughput volumes (thousand barrels per day)	196				207			(11		)
Throughput margin per barrel	$	6.36			$	12.73	&n bsp;	$	(6.37	)
Operating costs per barrel:
Operating expenses	$	2.31			$	2.90		$	(0.59	)
Depreciation and amortization expense	1.33				1.41			(0.08		)
Total operating costs per barrel	$

3.64  $4.31  $(0.67)West Coast:     Operating income$252  $375  $(123)Throughput volumes (thousand barrels per day)267  276  (9)Throughput margin per barrel$9.16  $10.84  $(1.68)Operating costs per barrel:     Operating expenses$4.83  $5.36  $(0.53)Depreciation and amortization expense1.74  1.77  (0.03)Total operating costs per barrel$6.57  $7.13  $(0.56)Operating income for regions above$581  $4,858  $(4,277)Asset impairment loss applicable to refining(220) (86) (134)Loss contingency accrual related to Aruba tax matter (k)(114) —  (114)Goodwill impairment loss (g)—  (4,007) 4,007 Total refining operating income$247  $765  $(518)

__________

See note references on pages 39 and 40.

38

Average Market Reference Prices and Differentials

(dollars per barrel , except as noted)

	Year Ended December 31,
	2009			2008			Change
Feedstocks:
WTI crude oil	$	61.69	&nb sp;	$	99.56		$	(37.87	)
Louisiana Light Sweet crude oil	62.25			101.99			(39.74		)
WTI less Mars crude oil	1.36			6.13			(4.77		)
WTI less Maya crude oil	5.19			15.71			(10.52		)
Products:
U.S. Gulf Coast :
Conventional 87 gasoline less WTI	7.61			4.85			2.76
Ultra-low-sulfur diesel less WTI	8.02			22.96			(14.94		)
Propylene less WTI	(1.31		)	(3.69		)	2.38
U.S. Mid-Continent:
Conventional 87 gasoline less WTI	8.01			4.46			3.55
Ultra-low-sulfur diesel less WTI	8.26			24.12			(15.86		)
U.S. Northeast:
Conventional 87 gasoline less WTI	7.99			3.22			4.77
Ultra-low-sulfur diesel less WTI	9.55			24.53			(14.98		)
U.S. West Coast:
CAR BOB 87 gasoline less WTI	15.75			9.93			5.82
CARB diesel less WTI	9.86			22.59			(12.73		)
New York Harbor corn crush (dollars per gallon)	0.47			0.42			0.05

__________

The following notes relate to references on pages 35 through 39.

(a)     On December 17, 2010, we sold our Paulsboro Refinery and associated inventory to PBF Holding. The results of operations of the refinery have been presented as discontinued operations for both years presented. The refining segment and Northeast Region operating highlights exclude the Paulsboro Refinery for both years presented.

(b)     During the fourth quarter of 2009, we permanently shut down our Delaware City Refinery and wrote down the book value of the refinery assets to net realizable value, resulting in a pre-tax loss on the shutdown of $1.9 billion ($1.2 billion after taxes). The results of operations of the shutdown refinery, including the loss on the shutdown in 2009, have been presented as discontinued operations for both years presented. The refining segment and Northeast Region operating highlights exclude the Delaware City Refinery for both years presented.

(c)     We acquired seven ethanol plants in the second quarter of 2009. The information presented for 2009 includes the results of operations of these plants commencing on their respective closing dates . Ethanol production volumes are based on total production during 2009 divided by actual calender days in 2009.

(d)     Credit card transactions processing fees incurred by our retail segment of $76 million and $92 million for the years ended December 31, 2009 and 2008, respectively, have been reclassified from retail operating expenses to cost of sales. The Retail–U.S. and Retail–Canada operating highlights have been restated to reflect this reclassification.

(e)     The asset impairment loss relates primarily to the permanent cancellation of certain capital projects classified as “construction in progress” as a result of the unfavorable impact of the economic slowdown on refining industry fundamentals. The asset impairment loss amounts are included in the refining segment operating income but are excluded from the regional operating income amounts and the consolidated and regional operating costs per barrel.

(f)     On July 1, 2008, we sold our Krotz Springs Refinery to Alon Refining Krotz Springs, Inc. (Alon). The nature and significance of our post-closing participation in an offtake agreement with Alon 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 addition, all refining operating highlights, both consolidated and for the Gulf Coast

39

region, include the Krotz Springs Refinery for the year ended December 31, 2008. The pre-tax gain of $305 million on the sale of the Krotz Springs Refinery is included in the Gulf Coast operating income for the year ended December 31, 2008 but is excluded from the per-barrel operating highlights.

(g)     During the fourth quarter of 2008, we determ ined that the goodwill in all four of our refining segment reporting units was impaired, which resulted in a pre-tax and after-tax goodwill impairment loss of $4.0 billion related to continuing operations. 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 for the year ended December 31, 2008.

(h)     Throughput margin per barrel represents operating revenues less cost of sales divided by throu ghput volumes.

(i)     Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, and asphalt.

(j)     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 on 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 Refinery and the West Coast refining region includes the Benicia and Wilmington Refineries.

(k)     A loss contingency accrual of $140 million was recorded in the third quarter of 2009 related to our dispute with the GOA regarding a turnover tax on export sales as well as other tax matters. The portion of the loss contingency accrual that relates to the turnover tax was recorded in cost of sales for the year ended December 31, 2009, and therefore is included in refining operating income (loss) but has been excluded in determining throughput margin per barrel.

General

Operating revenues decreased 39 percent (or $42.1 billion) for the year ended December 31, 2009 compared to the year ended December 31, 2008. Operating income decreased by $448 million and income from continuing operations before taxes decreased by $600 million over the same period. These decreases were primarily the result of the negative impact of the U.S. and worldwide economic slowdown on the demand and prices for our refined products. The economic slowdown began in late 2008 and persisted throughout 2009. The decreases in operating income and income from continuing operations before taxes, however, were significantly affected by the $4.0 billion goodwill impairment loss and the $305 million gain on the sale of our Krotz Springs Refinery that we recorded in 2008. Excluding these two items, operating income and income from continuing operations before taxes for the year ended December 31, 2009 decreased by $4.2 billion and $4.3 billion, respectively, from the prior year. These decreases were primarily related to our refining segment, which experienced a $518 million decrea se in operating income in 2009 compared to 2008 (a $4.3 billion decrease after excluding the effect of the goodwill write-off and other items) as discussed below.

Refining

Operating income for our refining segment decreased from $765 million for the year ended December 31, 2008 to $247 million for the year ended December 31, 2009, due to a decrease in operating results of $4.3 billion (discussed below), a reduced goodwill impairment loss of $4.0 billion, an increased asset impairment loss of $134 million, and an increased loss contingency accrual of $114 million. The goodwill impairment loss related to our determination in 2008 that our goodwill was impaired, which was based on the significant decline in our equity market capitalization. That decline was caused by severe disruptions in the U.S. and worldwide capital and commodities markets in 2008 and the resulting economic slowdown. The asset impairment loss of $220 million and $86 million reported in 2009 and 2008, respectively, related to our decision to permanently cancel certain construction projects in response to the economic slowdown that began in 2008. The loss contingency accrual recorded in 2009 related to our dispute of a turnover tax on export sales in Aruba.

The $4.3 billion decrease in operating results was primarily due to a 46 perc ent decrease in throughput margin per barrel (a $5.16 per barrel decrease between the comparable years) and an 8 percent decrease in throughput volumes (an 186,000 barrel per day decrease between the comparable years). The decreases were primarily the result of the negative impact of the economic slowdown on the demand for and prices of refined products. The decrease in throughput margin per barrel was caused by a significant decrease in distillate margins, but

40

the decrease in distillate margins was somewhat offset by an increase in gasoline margins in all of our refining regions. Throughput margin per barrel was also negatively impacted by narrow sour crude oil differentials. The impact of these factors on our throughput margin per barrel is described below.

Changes in the margin we receive for our products have a material impact on our results of operations. For example, the benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $8.02 per barrel for the year ended December 31, 2009, compared to $22.96 per barrel for the year ended December 31, 2008, representing an unfavorable decrease of $14.94 per barrel. We experienced similar decreases in distillate margins in other regions. We estimate that the decrease in distillate margins negatively impacted our overall refining margin by $4.4 billion, as we produced 692,000 barrels per day of distillates during the year ended December 31, 2009.

The benchmark reference margin for Gulf Coast 87 gasoline was $7.61 per barrel for the year ended December 31, 2009, compared to $4.85 per barrel for the year ended December 31, 2008, representing a favorable increase of $2.76 per barrel. CARBOB 87 gasoline benchmark reference margins increased year over year to an even greater extent in the West Coast region (a $5.82 per barrel favorable increase). We estimate that the increase in gasoline margins had a $1.0 billion favorable impact t o our overall refining margin, year over year, as we produced 1.04 billion barrels per day of gasoline during the year ended December 31, 2009. Gasoline margins were higher in 2009 as compared to 2008 despite a decrease in gasoline prices during 2009. We believe that the margins for gasoline improved due to a greater percentage decrease in the cost of crude oil as compared to the percentage decrease in the price of gasoline.

In addition, the margins we received for other products, such as petroleum coke and sulfur, for the year ended December 31, 2009 improved by $2.1 billion as compared to 2008. We believe that the margins were higher in 2009 due to the decrease in the cost of crude oil in 2009 as compared to 2008. For example, the benchmark reference price of WTI crude oil was $61.69 per barrel for the year ended December 31, 2009, compared to $99.56 per barrel for the year ended December 31, 2008, representing a decrease of $37.87 per barrel. Because the prices for these other products are not significantly influenced by the cost of crude oil, changes in the cost of crude oil have a significant effect of the margins we receive for these products.

For the year ended December 31, 2009, the differential applicable to the price of sour crude oil as compared to the price of sweet crude oil was lower than the differential for the year ended December 31, 2008. For example, Maya crude oil, which is a type of sour crude oil, sold at a discount of $5.19 per barrel to WTI crude oil, a type of sweet crude oil, during the year ended December 31, 2009. This compared to a discount of $15.71per barrel during the year ended December 31, 2008, representing an unfavorable decrease of $10.52 per barrel. However, this narrower differential in 2009 was offset by a reduction of 174,000 barrels per day of sour crude oil that we processed during 2009 as compared to 2008, which resulted primarily from the temporary shutdown of our Aruba Refinery commencing in July 2009. We estimate that the narrower differentials for all types of sour crude oil that we process, offset by reduced throughput volumes, negatively impacted our overall refining margin for 2009 by $2.6 billion as we processed 874,000 barrels per day of sour crude oils.

Refining operating expenses were 23 percent lower (or $851 million) for the year ended December 31, 2009 compared to the year ended December 31, 2008 primarily due to a decrease of $490 million in energy costs, a decrease of $171 million in maintenance expenses, a decrease of $48 million in sales and use taxes, and a decrease of $43 million resulting from no longer operating the Krotz Springs Refinery, which was sold in 2008.

41

Retail

Retail operating income was $293 million for the year ended December 31, 2009 compared to $369 million for the year ended December 31, 2008. This 21 percent decrease (or $76 million) was primarily due to decreased retail fuel margins of $124 million, offset by a $50 million decrease in operating expenses.

The decrease in retail fuel margins was due to the effect of significantly higher margins in 2008. The hi gher margins in 2008 were caused by a decrease in the supply of fuel in connection with the temporary shutdown of refineries along the U.S. Gulf Coast in the wake of Hurricane Ike during the third quarter of 2008. Many of those refineries became operational by the fourth quarter of December 2008, and fuel supply and margins returned to normal levels. There were no similar events that occurred in 2009.

The decrease in operating expenses was primarily due to a $24 million decrease in bad debt expense and a decrease in operating expenses due to the weakening of the Canadian dollar relative to the U.S. dollar in 2009 compared to 2008. On average, Cdn.$1 was equal to $0.88 during 2009 compared to $0.95 during 2008, representing a decrease in value of seven percent. The weaker Canadian dollar had an $18 million favorable impact on the 2009 operating expenses of our Canadian retail operatio ns compared to 2008.

Ethanol

Ethanol operating income was $165 million for the year ended December 31, 2009, which represents the operations of the seven ethanol plants acquired in the second quarter of 2009, as described in Note 2 of Notes to Consolidated Financial Statements. We did not own or operate any ethanol plants prior to this acquisition.

Corporate Expenses and Other

General and administrative expenses increased $13 million for the year ended December 31, 2009 compared to the year ended December 31, 2008 mainly due to an increase of $39 million in litigation costs, an increase of $10 million in severance expenses, and acquisition costs of $10 million related to the acquisition of seven ethanol plants. These increases were partially offset by reductions of $29 million in environmental remediation expenses and $16 million in professional fees.

“Other income, net” for the year ended December 31, 2009 decreased $96 million from the year ended December 31, 2008 primarily due to a $128 million unfavorable change in fair value adjustments related to the Alon earn-out agreement and associated derivative instruments as discussed in Notes 20 and 21 of Notes to Consolidated Financial Statements, reduced interest income of $37 million resulting from lower cash balances and interest rates, and a $14 million gain recognized in 2008 on the redemption of our 9.5% senior notes as discussed in Note 11 of Notes to Consolidated Financial Statements. These decreases were partially offset by a $55 milli on increase in the fair value of certain nonqualified benefit plan assets and $27 million of income resulting from the reversal of an accrual for potential payments related to a prior acquisition in connection with the expiration of the statute of limitations.

Interest and debt expense increased $56 million mainly due to interest incurred on $1.0 billion of notes issued in March 2009.

Income tax expense decreased $1.5 billion from $1.4 billion of expense in 2008 to a $43 million benefit in 2009 mainly as a result of lower operating income in 2009 and the nondeductibility of a significant portion of the $4.0 billion goodwill impairment loss in 2008.

“Income (loss) from discontinued operat ions, net of income taxes” for the year ended December 31, 2009 increased $1.7 billion from the year ended December 31, 2008 primarily due to the $1.2 billion after tax loss on the permanent shut down of our Delaware City Refinery in the fourth quarter of 2009.

42

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Year Ended December 31, 2010

Net cash provided by operating activities for the year ended December 31, 2010 was $3.0 billion compared to $1.8 billion for the year ended December 31, 2009. The increase in cash generated from operating activities was due primarily to the receipt of a $923 million tax refund in 2010. Changes in cash provided by or used for working capital during the years ended December 31, 2010 and 2009 are shown in Note 19 of Notes to Consolidated Financial Statements. Both receivables and accounts payable increased in 2010 due to significant increases in prices for gasoline, distillate, and crude oil at the end of 2010 compared to such prices at the end of 2009.

The net cash generated from operating activities during the year ended December 31, 2010, combined with $1.5 billion of proceeds from the issuance of $400 million of 4.50% notes due in February 2015, $850 million of 6.125% notes due in February 2020, and $300 million of GO Zone Bonds as discussed in Note 11 of Notes to Consolidated Financial Statements, $547 million of proceeds from the Paulsboro Refinery sale, $220 million of proceeds from the sale of the shutdown Delaware City Refinery assets and associated terminal and pipeline assets, and $330 million of proceeds from the sale of our 50 percent interest in CHOPS as discussed in Note 3 of Notes to Consolidated Financial Statements, were used mainly to:

•     fund $2.3 billion of capital expenditures and deferred turnaround and catalyst costs;

•     redeem our 7.5% senior notes for $294 million and our 6.75% senior notes for $190 million;

•     make scheduled long-term note repayments of $33 million;

•     make net repayments under our accounts receivable sales facility of $100 million;

•     pay common stock dividends of $114 million;

purchase additional ethanol facilities for $260 million; and

•    

•     increase available cash on hand by $2.5 billion.

Cash Flows for the Year Ended December 31, 2009

Net cash provided by operating activities for the year ended December 31, 2009 was $1.8 billion compared to $3.1 billion for the year ende d December 31, 2008. The decrease in cash generated from operating activities was due primarily to the $4.2 billion decrease in operating income discussed above under “RESULTS OF OPERATIONS,” after excluding the effect of the goodwill impairment loss and gain on the sale of the Krotz Springs Refinery, both of which had no effect on cash flows from operating activities. This decrease was partially offset by a $1.6 billion favorable change in the amount of income tax payments and refunds in 2008 and 2009 and a net $1.4 billion favorable eff ect from changes in receivables, inventories, and accounts payable between the two years. Changes in cash provided by or used for working capital during the years ended December 31, 2009 and 2008 are shown in Note 19 of Notes to Consolidated Financial Statements. Both receivables and accounts payable increased in 2009 due to significant increases in prices for gasoline, distillate, and crude oil at the end of 2009 compared to such prices at the end of 2008.

The net cash generated from operating activities during the year ended December 31, 2009, combined with $998 million of proceeds from the issuance of $1.0 billion of notes in March 2009 as discussed in Note 11 of Notes to Consolidated Financial Statements, $799 million of net proceeds from the issuance of 46 million shares of common stock in June 2009 as discussed in Note 13 of Notes to Consolidated Financial Statements, $100 million of additional proceeds from the sale of receivables, and $115 million of available cash on hand were used mainly to:

•     fund $2.7 billion of capital expenditures and deferred turnaround and catalyst costs;

•     fund the acquisition of seven ethanol plants for $556 million;

•     make scheduled long-term note repayment s of $285 million; and

•     pay common stock dividends of $324 million.

43

Cash flows related to the discontinued operations of the Paulsboro and Delaware City Refineries have been combined with the cash flows from continuing operations within each category in the consolidated statements of cash flows for all years presented and are summarized as follows (in millions):

	Year Ended December 31,
	2010			2009			2008
Cash provided by (used in)   operating activities:
Paulsboro Refinery	$	88		$	10		$	246
Delaware City Refinery	(26		)	(126		)	81
Cash used in investing activities:
Paulsboro Refinery	(41		)	(121		)	(212		)
Delaware City Refinery	—			(153		)	(268		)

Capital Investments

During the year ended December 31, 2010, we expended $1.7 billion for capital expendi tures and $535 million for deferred turnaround and catalyst costs. Capital expenditures for the year ended December 31, 2010 included $740 million of costs related to environmental projects.

For 2011, we expect to incur approximately $2.9 billion for capital investments, including approximately $2.4 billion for capital expenditures (approximately $260 million of which is for environmental projects) and approximately $510 million for deferred turnaround an d catalyst costs. The capital expenditure estimate excludes expenditures related to future strategic acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.

In January 2010, we acquired two ethanol plants and inventories for a total purchase price of $202 million. The plants are located in Linden, Indiana and Bloomingburg, Ohio. In February 2010, we acquired an additional ethanol plant located near Jefferson, Wisconsin plus certain receivables and inventories for a total consideration of $ 79 million. Of the $281 million of total consideration paid for these acquisitions, $21 million was paid in the fourth quarter of 2009.

On June 1, 2010, we sold the shutdown Delaware City Refinery assets and associated terminal and pipeline assets to PBF for$220 million of cash proceeds, and on December 17, 2010, we sold our Paulsboro Refinery to PBF Holding for $547 million of cash proceeds and a $160 million one-year note secured by the Paulsboro Refinery.

44

Contractual Obligations

Our contractual obligations as of December 31, 2010 are summarized below (in millions).

	Payments Due by Period
	2011		2012		2013		2014		2015		Thereafter		Total
Debt and capital  lease obligations (including  interest on capital lease  obligations)	$	825	$	765	$	495	$	214	$	489	$	5,623	$	8,411
Operating lease obligations	353		237		160		104

85  324  1,263 Purchase obligations28,599  4,602  1,413  249  203 1,105  36,171 Other long-term liabilities—  206  168  149  139  1,105  1,767 Total$29,777  $5,810  $2,236  $716  $916  $8,157  $47,612 

Debt and Capital Lease Obligations

During 2010, the following activity occurred related to our non-bank debt:

•     in February 2010, we issued $400 million of 4.50% notes due in February 2015 and $850 million of 6.125% notes due in February 2020 for total net proceeds of $1.244 billion;

•     in March 2010, we redeemed our 7.50% senior notes with a maturity date of June 15, 2015 for $294 million, or 102.5% of stated value, resulting in a $2 million gain;

•     in April 2010, we made scheduled debt repayments of $8 million related to our Series A 5.45%, Series B 5.40%, and Series C 5.40% industrial revenue bonds;

•     in May 2010, we redeemed our 6.75% senior notes with a maturity date of May 1, 2014 for $190 million, or 102.25% of stated value, resulting in a $3 million loss;

•     in June 2010, we made scheduled debt repayments of $25 million related to our 7.25% debentures; and

•&nb sp;    in December 2010, we received proceeds of $300 million under a financing agreement associated with the issuance of $300 million of GO Zone Bonds.

On February 1, 2011, we made a scheduled debt repayment of $210 million related to our 6.75% senior notes. On February 2, 2011, we paid $300 million to acquire the GO Zone Bonds, which were subject to mandatory tender on that date. We expect to hold the GO Zone Bonds for our own account until conditions permit the rema rketing of these bonds at an interest rate acceptable to us.

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 $1.0 billion of eligible trade receivables, which matures in June 2011. As of December 31, 2010, the amount of eligible receivables sold was $100 million. During the year ended December 31, 2010, we reduced the net eligible receivables sold under this program by $100 million. Proceeds from the sale of receivables under this facility are reflected as debt.

45

Our agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt to below investment grade ratings by Moody’s Investors Service and Standard & Poor’s Ratings Services, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. As of December 31, 2010, 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 (negative outlook)
Moody’s Investors Service	Baa2 (negative outlook )
Fitch Ratings	BBB (negative 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 below investment grade 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, 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 product and corn inventories. Operating lease obligations include all operating leases that have initial or remaining noncancelable terms in excess of one year, and are not reduced by minimum rentals to be received by us under subleases.

Purchase Obligations

A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchase d, (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, 2010, our short-term and long-term purchase obligations increased by $6.4 billion from the amount reported as of December 31, 2009. The increase is primarily attributable to higher crude oil and other feedstock prices at December 31, 2010 compared to December 31, 2009.

Other Long-term Liabilities

Our other long-term liabilities are described in Note 10 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, 2010.

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Other Commercial Commitments

As of December 31, 2010, our committed lines of credit were as follows:

	Borrowing Capacity	Expiration	Outstanding Letters of Credit
Letter of credit facility	$200 million	June 2011	$ -
Letter of credit facility	$300 million	June 2011	$100 million
Revolving credit facility	$2.4 billion	November 2012	$399 million
Canadian revolving credit facility	Cdn. $115 million	December 2012	Cdn. $20 milli on

As of December 31, 2010, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of December 31, 2010 expire during 2011 and 2012.

Stock Purchase Programs

As of December 31, 2010, we have approvals under common stock purchase programs previously approved by our board of directors to purchase approximately $3.5 billion of our common stock.

Pension Plan Funded Status

During 2010, we contributed $50 million to our qualified pension plans. Based on a 5.40 percent discount rate and fair values of plan assets as of December 31, 2010, the fair value of the assets in our qualified pension plans was equal to approximately 95 percent of the projected benefit obligation under those plans as of the end of 2010.

We have no minimum required contributions to our pension plans during 2011 under the Employee Retirement Income Security Act; however, we plan to contribute approximately $100 million to our pension plans during 2011.

Environmental Matters

We are subject to extensive federal, state, and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our refineries could require material additional expenditures to comply with environmental laws and regulations.

While debate continues in the U.S. Congress regarding greenhouse gas legislation, the regulation of greenhouse gases at the federal level has now shifted to the U.S. Environmental Protection Agency (EPA), which began regulating greenhouse gases on January 2, 2011 under the Clean Air Act Amendments of 1990 (Clean Air Act). According to statements by the EPA, any new construction or material expansions will require that, among other things, a greenhouse gas permit be issued at the state or federal level in accordance with the Clean Air Act and regulations, and we will be required to undertake a technology review to determine appropriate controls to be implemented with the project in order to reduce greenhouse gas emissions. The determination will be on a case by case basis, and the EPA has provided only general guidance on which controls will be required. Any such controls, however, could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, wh ich could have a material adverse effect on our financial position, results of operations, and liquidity.

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In addition, certain states have pursued independent regulation of greenhouse gases at the state level. For example, the California Global Warming Solutions Act, also known as AB 32, directs the CARB to develop and issue regulations to reduce greenhouse gas emissions in California to 1990 levels by 2020. CARB has issued a variety of regulations aimed at reaching this goal, including a Low Carbon Fuel Standard (LCFS) as well as a state-wide cap-and-trade program. The LCFS is effective in 2011, with small reductions in the carbon intensity of transportation fuels sold in California. The mandated reductions in carbon intensity are scheduled to increase through 2020, after which another step-change in reductions is anticipated. The LCFS is designed to encourage substitution of traditional petroleum fuels, and, over time, it is anticipated that the LCFS will lead to a greater use of electric cars and alternative fuels, such as E85, as companies seek to generate more cre dits to offset petroleum fuels. The state-wide cap-and-trade program will begin in 2012. Initially, the program will apply only to stationary sources of greenhouse gases (e.g., refinery and power plant greenhouse gas emissions). Greenhouse gas emissions from fuels that we sell in California will be covered by the program beginning in 2015. We anticipate that free allocations of credits will be available in the early years of the program, but we expect that compliance costs will be significant, particularly beginning in 2015, when fuels are included in the program. Complying with AB 32, including the LCFS and the cap-and-trade program, could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce. To the degree we are unable to recover these increased costs, these matters could have a material adverse effect on our financial position, results of operations, and liquidity.

On June 30, 2010, the EPA formally disapproved the flexible permits program submitted by the TCEQ in 1994 for inclusion in its clean-air implementation plan.  The EPA determined that Texas’ flexible permit program did not meet several requirements under the federal Clean Air Act.  Our Port Arthur, Texas City, Three Rivers, McKee and Corpus Christi East and West Refineries formerly operated under flexible permits administered by the TCEQ.  In the fourth quarter of 2010, we completed the conversion of our flexible permits into federally enforc eable conventional state NSR permits (“de-flexed permits”). We are now in the process of incorporating these de-flexed permits into our Title V permits. Continued discussions with EPA regarding this matter are likely.

Meanwhile, EPA has formally disapproved other TCEQ permitting programs that historically have streamlined the environmental permitting process in Texas. For example, EPA has disapproved the TCEQ pollution control standard permit, thus requiring conventional permitting for future pollution control equipment. Litigation is pending from industry groups and others against EPA for each of these actions. EPA has also objected to numerous Title V permits in Texas and other states, including permits at our Port Arthur, Corpus Christi East, and McKee Refineries. Environmental activist groups have filed a notice of intent to sue EPA, seeking to require EPA to assume control of these permits from the TCEQ. All of these developments have created substantial uncertainty regarding existing and future permitting. Because of this uncertainty, we are unable to determine the costs or effects of EPA’s actions on our permitting activity. But EPA’s disruption of the Texas permitting system could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

Tax Matters

As discussed in Note 12 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

48

our tax liabilities as a result of these audits may subject us to interest and penalties.

Effective June 1, 2010, the GOA enacted a new tax re gime applicable to refinery and terminal operations in Aruba. Under the new tax regime, we are subject to a profit tax rate of 7 percent and a dividend withholding tax rate of 0 percent. In addition, all imports and exports are exempt from turnover tax and throughput fees. Beginning June 1, 2012, we will also make a minimum annual tax payment of $10 million (payable in equal quarterly installments) with the ability to carry forward any excess tax prepayments to future tax years.

The new tax regime was the result of a settlement agreement that we entered into on February 24, 2010 with the GOA that established the terms for settlement of a lengthy and complicated tax dispute between the parties. On May 30, 2010, the Aruban Parliament adopted several laws that implement ed the provisions of the settlement agreement, which became effective June 1, 2010. Pursuant to the terms of the settlement agreement, we relinquished the provisions of the previous tax holiday regime. On June 4, 2010, we made a payment to the GOA of $118 million (primarily from restricted cash held in escrow) in consideration of a full release of all tax claims prior to June 1, 2010.

Financial Regulatory Reform

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Wall Street Reform Act). The Wall Street Reform Act, among many things, creates new re gulations for companies that extend credit to consumers and requires most derivative instruments to be traded on exchanges and routed through clearinghouses. Rules to implement the Wall Street Reform Act are being finalized and therefore, the impact to our operations is not yet known. However, implementation could result in higher margin requirements, higher clearing costs, and more reporting requirements with respect to our derivative activities.

Other

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 c apital 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.

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CRITICAL ACCOUNTING POLICIES INVOLVING CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires us 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, which include property, plant and equipment, intangible assets, and refinery turnaround and catalyst costs, are 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 if the carrying amount of the asset exceeds its fair value.

In order to test for recoverability, we 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. Our impairment evaluations are based on assumptions that we deem to be reasonable. Providing sensitivity analyses if other assumptions were used in performing the impairment evaluations is not practicable due to the significant number of assumptions involved in the estimates. See Note 4 of Notes to Consolidated Financial Statements for a further discussion of our asset impairment evaluations and certain losses resulting from those evaluations.

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.

Environmental Matters

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, as discussed in “LIQUIDITY AND CAPITAL RESOURCES – Environmental Matters,” 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 laws

50

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 amount of and changes in our accruals for environmental matters as of and for the years ended December 31, 2010, 2009, and 2008 is included in Note 10 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 pl an assets is based on a compounded return calculated assuming an asset allocation that 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 percent decrease in the assumptions related to the discount rate or expected return on plan assets or a 0.25 percent 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, 2010 and net periodic benefit cost for the year ending December 31, 2011 (in millions):

	Pension Benefits		Other Postretirement Benefits
Increase in projected benefit obligation resulting from:
Discount rate decrease	$	70	$	12
Compensation rate increase	29		—
Health care cost trend rate increase	—		5
Increase in expense resulting from:

Discount rate decrease9  1 Expected return on plan assets decrease4  — Compensation rate increase6  — Health care cost t rend rate increase—  1 

See Note 14 of Notes to Consolidated Financial Statements for a further discussion of our pension and other postretirement benefit obligations.

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Tax Matters

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 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. See Note 12 of Notes to Consolidated Financial Statements for a further discussion of our tax liabilities.

Legal Matters

A variety of claims have been made against us in various lawsuits. 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 rele vant 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. See Note 12 of Notes to Consolidated Financial Statements for a further discussion of our litigation matters.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

COMMODITY PRICE RI SK

We are exposed to market risks related to the price of crude oil, refined products (primarily gasoline and distillate), grain (primarily corn), and natural gas used in our refining operations. To reduce the impact of price volatility on our results of operations and cash flows, we enter into commodity derivative instruments, including swaps, futures, and options to hedge:

•     inventories and firm commitments to purchase inventories generally for amounts by which our current year LIFO inventory levels differ from our previous year-end LIFO inventory levels and

•     forecasted feedstock and refined product purchases, refined product sales, natural gas purchases, and corn purchases to lock in the price of those forecasted transactions at existing market prices that we deem favorable.

We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations.  We use swaps primarily to manage our price exposure. We also enter into certain commodity derivative instruments for trading purposes to take advantage of existing market conditions related to commodities that we perceive as opportunities to benefit our results of operations and cash flows, but for which there are no related physical transactions.

Our positions in commodity derivative instruments are monito red 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.

The following sensitivity analysis includes all positions at the end of the reporting period with which we have market risk (in millions):

	Derivative Instruments Held For
	Non-Trading Purposes			Trading Purposes
December 31, 2010
Gain (loss) in fair value due to:
10% increase in underlying commodity prices	$	(199	)	$	—
10% decrease in underlying commodity prices	189			(1		)
December 31, 2009
Gain (loss) in fair value due to:
10% increase in underlying commodity prices	(6		)	(8		)
10% decrease in underlying commodity prices	6			—

See Note 21 of Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of December 31, 2010.

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I NTEREST RATE RISK

The following table provides information about our debt instruments (dollars in millions), the fair values of which are sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented. We had no interest rate derivative instruments outstanding as of December 31, 2010 and 2009.

	December 31, 2010
	Expected Maturity Dates
	2011			2012			2013			2014			2015			There- after			Total			Fair Value
Debt (excluding     capital lease obligations):
Fixed rate	$	418		$	759		$	489		$	209		$	484		$	5,605		$	7,964		$	9,092
Average interest rate	6.4		%	6.9		%	5.5		%	4.8		%	5.2		%	7.2		%	6.9		%
Floating rate	$	400		—			—			—			—			—			$	400		$	400
Average interest rate	0.5		%	—		%	—		%	—		%	—		%	—		%	0.5		%

December 31, 2009

Expected Maturity Dates

2010

2011 2012 2013 2014 

There-

after

 Total 

Fair

Value

Debt (excluding

   capital lease obligations):

               Fixed rate$33  $418  $759  $489  $395  $5,126  $7,220  $8,028 Average interest rate6.8% 6.4% 6.9% 5.5% 5.7% 7.5% 7.1%  Floating rate$200  —  —  —  —  —  $200  $200 Average interest rate0.9% —% —% —% —% —% 0.9%  

FOREIGN CURRENCY RISK

As of December 31, 2010, we had commitments to purchase $487 million of U.S. dollars. Our market risk was minimal on the contracts, as they matured on or before January 31, 2011, resulting in a $2 million loss in the first quarter of 2011.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEME NTARY 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 effectivenes s of Valero’s internal control over financial reporting as of December 31, 2010. In its evaluation, management used the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management believes that as of December 31, 2010, our internal control over financial reporting was effective based on those criteria.

Our independent registered public accounting fir m has issued an attestation report on the effectiveness of our internal control over financial reporting, which begins on page 57 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, 2010 and 2009, 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, 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility i s 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, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, 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, 2010, 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 25, 2011, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

San Antonio, Texas

February 25, 2011

��

56

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 repor ting as of December 31, 2010, 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 ou r 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 th at 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, effect ive internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by COSO.

57

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, 2010 and 2009, 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, 2010, and our report dated February 25, 2011 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

San Antonio, Texas

February 25, 2011

58

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Par Value)

	December 31,
	2010			2009
ASSETS
Current assets:
Cash and temporary cash investments	$	3,334		$	825
Receivables, net	4,583			3,779
Inventories	4,947			4,578
Income taxes receivable	343			887
Deferred income taxes	190			180
Prepaid expenses and other	121			384
Assets held for sale	—			289
Total current assets	13,518			10,922
Property, plant and equipment, at cost	28,921			26,885
Accumulated depreciation	(6,252		)	(5,270		)
Property, plant and equipment, net	22,669			21,615
Intangible assets, net	224			227
Deferred charges and other assets, net	1,210			1,347
Long-term assets held for sale	—			1,461
Total assets	$	37,621		$	35,572
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	822		$	237
Accounts pay able	6,441			5,825
Accrued expenses	590			641
Taxes other than income taxes	671			725
Income taxes payable	3			95
Deferred income taxes	257			253
Liabilities related to assets held for sale	—			33
Total current liabilities	8,784			7,809
Debt and capital lease obligations, less current portion	7,515			7,163
Deferred income taxes	4,530			4,006
Other long-term liabilities	1,767			1,869
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 673,501,593 and 673,501,593 shares issued	7			7
Additional paid-in capital	7,704			7,896
Treasury stock, at cost; 105,113,545 and 108,798,847 common shares	(6,462		)	(6,721		)
Retained earnings	13,388			13,178
Accumulated other comprehensive income	388			365
Total stockholders’ equity	15,025			14,725
Total liabilities and stockholders’ equity	$	37,621		$	35,572

See Notes to Consolidated Financial Statements.

59

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STA TEMENTS OF INCOME

(Millions of Dollars, Except per Share Amounts)

Year Ended December 31,

	2010		2009		2008
Operating revenues (a)	$	82,233	$	64,599	$	106,676
Costs and expe nses:
Cost of sales	74,458		58,686		96,087
Operating expenses:
Refining	2,944		2,880		3,731
Retail	654		626		676
Ethanol	363		169		—
General and administrative expenses	531		572		559
Depreciation and amortization expense	1,405		1,361		1,304
Asset impairment loss	2		222		86
Gain on sale of Krotz Springs Refinery	—		—		(305		)
Goodwill impairment loss	—		—		4,007
Total costs and expenses	80,357		64,516		106,145
Operating income	1,876

  83  531 Other income, net106  17  113 Interest and debt expense:     Incurred(574) (521) (452)Capitalized90  105  92 

Income (loss) from continuing operations

     before income tax e xpense (benefit)

1,498  (316) 284 Income tax expense (bene fit)575  (43) 1,438 Income (loss) f rom continuing operations923  (273) (1,154)Income (loss) from discontinued operations, net of income taxes(599) 

(1,709

) 23 Net income (loss)$324  $(1,982) $(1,131)

Earnings (loss) per common share:

     Continuing operations$1.63  $(0.50) $(2.20)Discontinued operations(1.06) (3.17) 0.04 Total$0.57  $(3.67)$(2.16)Weighted-average common shares outstanding (in millions)563  541 524 Earnings (loss) per common share – assuming dilution:     Continuing operations$1.62  $(0.50) 

$

(2.20)Discontinued operations(1.05) (3.17) 0.04 Total$0.57  $(3.67) $(2.16)

Weighted-average common shares outstanding –

   assuming dilution (in millions)

568  541  524 Dividends per common share$0.20  $0.60  $0.57 

______________________________

Supplemental information:
(a) Includes excise taxes on sales by our U.S. retail system	$	891	$	873	$	816

See Notes to Consolidated Financial Statements.

60

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Millions of Dollars)

	Common Stock		Additional Paid-in Capital		Treasury Stock			Retained Earnings				Accumulated Other Comprehensive Income (Loss)
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			& nbsp;	(176		)
Net loss	—		—		—			(1,982		)		—
Dividends on common stock

—  — —  (324) — Sale of common stock1  798  —  —  — 

Stock-based compensation

   expense

—  68  —  —  — 

Shares issued, net of shares

   repurchased, in connection with

   employee stock plans and other

—  (160) 163  —  — Other comprehensive income—  —  —  —  541 Balance as of December 31, 20097  7,896   ;(6,721) 1 3,178  365 Net income—  —  —  324  — Dividends on common stock—  —  —  (114) — 

Stock-based compensation

   expense

—  54  &mdas h;  —  — 

Shares issued, net of shares

   repurchased, in connection with

   employee stock plans and other

—  (246) 259  —  —Other comprehensive income—  —  —  —  23 Balance as of December 31, 2010$7  $7,704  $(6,462) $13,388  $388 

See Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

	Year Ended December 31,
	2010			2009			2008
Cash flows from operating activities:
Net income (loss)	$	324		$	(1,982	)	$	(1,131	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	1,473			1,527			1,476
Asset impairment loss	2			607			103
Goodwill impairment loss	—			—			4,069
Loss (gain) on sale of refinery assets, net	888			—			(305		)
Loss on shutdown of Delaware City Refinery	—			1,868			—
Gain on sale of investment in Cameron Highway Oil Pipeline Company	(55		)	—			—
Noncash interest expense and other income, net	3			(2		)	(76		)
Stock-based compensation expense	54			66			59
Deferred income tax expense (benefit)	347			(343		)	675
Changes in current assets and current liabilities	68			255			(1,630		)
Changes in deferred charges an d credits and other operating activities, net	(59		)	(173		)	(145		)
Net cash provided by operating activities	3,045			1,823			3,095
Cash flows from investing activities:
Capital expenditures	(1,730		)	(2,306		)	(2,893		)
Deferred turnaround and catalyst costs	(535		)	(415		)	(408		)
Acquisitions of ethanol plants	(260		)	(556		)	—
Advance payments related to acquisition of ethanol plants	—			(21		)	—
Proceeds from the sale of the Paulsboro Refinery	547			—			—
Proceeds from the sale of the Delaware City Refinery assets and     associated terminal and pipeline assets	220			—			—
Proceeds from the sale of the Krotz Springs Refinery	—			—			463
Proceeds from the sale of investment in Cameron Highway Oil Pipeline Company	330			—			—
Minor acquisitions	—			(29		)	(144		)
Other investing activities, net	23			35			17
Net cash used in investing activities	(1,405		)	(3,292		)	(2,965		)
Cash flows from financing activities:
Non-bank debt:
Borrowings	1,544			998			—
Repayments	(517		)	(285		)	(374		)
Bank credit agreements:
Borrowings	—			39			296
Repayments	—			(39		)	(296		)
Accounts receivable sales program:

   Proceeds from sale of receivables1,225  950  — Repayments(1,325) (850) — Proceeds from the sale of common stock, net of issuance costs—  799  — Purchase of common stock for treasury(13) (4) (955)Issuance of common stock in connection with stock-based compensation plans20  11  16 Common stock dividends(114) (324) (299)Other financing activities, net(4) (6) 5  Net cash provided by (used in) financing activities816  1,289  (1,607)Effect of foreign exchange rate changes on cash53  65  (47)Net increase (decrease) in cash and temporary cash investments2,509  (115) (1,524)Cash and temporary cash investments at beginning of year825  940  2,464 Cash and temporary cash investments at end of year$3,334  $825  $940 

See Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions of Dollars)

	Year Ended December 31,
	2010			2009			2008
Net income (loss)	$	324		$	(1,982	)	$	(1,131	)
Other comprehensive income (loss):
Foreign currency translation adjustment, net of income tax expense of $ - , $ - , and $ -	158			375			(490		)
Pension and other postretirement benefits:
Net gain (loss) arising during the period, net of income tax (expense) benefit of $5, $(132), and $227	(14		)	219			(410		)
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $3, $(2), and $ -	(4		)	(1		)	(1		)
Net gain (loss) on pension    and other postretirement benefits	(18		)	218			(411		)
Derivative instruments designated    and qualifying as cash flow hedges:
Net gain (loss) arising during the period, net of income tax (expense) benefit of $1, $(44), and $(46)	(1		)	81			85
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $62, $72, and $(36)	(116		)	(133		)	67
Net gain (loss) on cash flow hedges	(117		)	(52		)	152
Other comprehensive income (loss)	23			541			(749		)
Comprehensive income (loss)	$	347		$	(1,441	)	$	(1,880	)

See Notes to Consolidated Financial Statements.

63

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.     BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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 petroleum refining and marketing company and own 14 refineries with a combined total throughput capacity of approximately 2.6 million barrels per day as of December 31, 2010. 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 (U.S.) and eastern Canada under various brand names including Valero^®, Diamond Shamrock^®, Shamrock^®,Ultramar^®, and Beacon^®. We also produce ethanol, and as of December 31, 2010, we operated ten ethanol plants in the Midwest with a combined capacity of approximately 1.1 billion gallons per year. 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 differentials between grades of crude oil, the demand for and prices of refined products, industry supply capacity, and competitor refinery maintenanc e turnarounds.

The terms UDS Acquisition and Premcor Acquisition used elsewhere in these notes refer to the merger of Ultramar Diamond Shamrock Corporation (UDS) into Valero effective December 31, 2001 and the merger of Premcor Inc. (Premcor) into Valero effective September 1, 2005, respectively.

We have evaluated subsequent events that occurred after December 31, 2010 through the filing of this Form 10-K. Any material subsequent events that occurred during this time have been properly recognized or disclosed in our financial statements.

Significant Accounting Policies

Reclassifications

As discussed in Note 3, we sold our Paulsboro Refinery in December 2010. As a result, the assets and liabilities sold have been presented in the consolidated balance sheet as assets held for sale and liabilities related to assets held for sale as of December 31, 2009, and the results of operations of the Paulsboro Refinery have been presented as discontinued operations in the consolidated statements of income for all years presented.

Also as discussed in Note 3, we sold our shutdown Delaware City Refinery assets and associated terminal and pipeline assets in June 2010. As a result, these assets have been presented in the consolidated balance sheet as assets held for sale as of December  ;31, 2009. The results of operations of the Delaware City Refinery have been presented as discontinued operations in the consolidated statements of income for all years presented.

In addition, certain amounts previously reported in our annual report on Form 10-K for the year ended December 31, 2009 have been reclassified to conform to the 2010 presentation. Credit card fees previously recognized in 2009 and 2008 in retail operating expenses have been reclassified to cost of sales as such fees are directly and jointly related to the sale transaction. This reclassification resulted in an increase in cost of

64

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

sales and a decrease in retail operating expenses of $76 million and $92 million for the years ended December 31, 2009 and 2008, respectively.

Principles of Consolidation

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.

In June 2009, the Financial Accounting Standards Board amend ed Accounting Standards Codification (ASC) Topic 810, “Consolidation,” to modify provisions related to variable interest entities to include entities previously considered qualifying special-purpose entities, as the concept of these entities was eliminated. This modification also clarified consolidation requirements and expanded disclosure requirements related to variable interest entities. These provisions of ASC Topic 810 were effective for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2009, and earlier application was prohibited. The adoption of these provisions of ASC Topic 810 effective January 1, 2010 did not affect our financial position or results of operations.

Use o f Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires us 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, we review our estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

Cash and Temporary Cash Investments

Our tempo rary cash investments are highly liquid, low-risk debt instruments that have a maturity of three months or less when acquired.

Receivables

Trade receivables are carried at original invoice amount. We maintain an allowance for doubtful accounts which is adjusted based on management’s assessment of our customers’ historical collection experience, known credit risks and industry and economic conditions.

Inventories

Inventories are carried at the lower of cost or market. The cost of refinery feedstocks purchased for processing, refined products, and grain and ethanol inventories 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.

65

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The costs of minor property units (or components of property units), net of salvage value, that are retired or abandoned are charged or credited to accumulated depreciation under the com posite 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, unless such amounts are reported separately due to materiality.

Depreciation of property, plant and equipment used in the refining and retail segments is recorded on a straight-line basis over the estimated useful lives of the related facilities primarily using the composite method of depreciation. Depreciation of property, plant and equipment used in the ethanol segment is recorded on a straight-line basis over the estimated useful lives of each individual asset. Leasehold improvements and assets acquired under capital leases are amortized using the straight-line method over the sho rter of the lease term or the estimated useful life of the related asset.

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 es timated useful life of the specific catalyst;

•     investments in entities that we do not control; and

•     other noncurrent assets such as convenience store dealer incentive programs, nonqualified pension plan assets, debt issuance costs, and various other costs.

Impairment of Assets

Long-lived assets, which include property, plant and equipment, intangible assets, and refinery turnaround and catalysts costs, are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset 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 or other appropriate methods. See Note 4 for our impairment evaluation of our long-lived assets.

Goodwill was tested for impairment annually or more frequently if events or changes in circumstances indicated that the asset was impaired. We used October 1 of each year as our valuation date for annual impairment testing purposes. See Note 4 for our impairment evaluation of goodwill in 2008, which resulted in the write-off of all of our goodwill.

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

66

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

of the investment and its carrying amount. See Notes 3 and 9 regarding the sale of our equity method investment in Cameron Highway Oil Pipeline Company (CHOPS).

Environmental Matters

Liabilities for future reme diation costs are recorded when environmental assessments from governmental regulatory agencies and/or remedial efforts are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Environmental liabilities are based on best estimates of probable undiscounted future costs over a 20-year time period using currently available technology and applying current regulations, as well as our own internal environmental policies, without establishing a range of loss for these liabilities. Environmental liabilities are difficult to assess and estimate due to uncertainties related to the magnitude of possible remediation, the timing of such remediation, and the determination of our obligation in proportion to other parties. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts, and potential improvements in remediation technologies. Amounts recorded for environmental liabilities have not been reduced by possible recoveries from third parties.

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 tan gible 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.

Transfers of Financial Assets

In June 2009, ASC Topic 860, “Transfers and Servicing,” was modified to clarify the requirements fo r derecognizing transferred financial assets, remove the concept of a qualifying special-purpose entity and related exceptions, and require additional disclosures related to transfers of financial assets. This guidance was effective for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2009, and earlier application was prohibited. The adoption of these provisions of ASC Topic 860 effective January 1, 2010 did not affect the manner in which we account for our accounts receivable sales facility as discussed in Note 11, our financial position, or our results of operations.

Foreign Currency Translation

The functional currencies of our Canadian and Aruban operations are the Canadian dollar and the Aruban florin, respectively. The translation of the Canadian operations into U.S. dollars is computed for balance sheet accounts using exchange rates in effect as of the balance sheet date and for revenue and expense accounts using the weighted-average exchange rates during the year. Adjustments resulting from this translation are reported in other comprehensive income. The value of the Aruban florin is fixed to the U.S. dollar at 1.79 Aruban florins to one U.S. dollar. The translation of the Aruban operations into U.S. dollars is computed based on this fixed exchange rate for both balance sheet and income statement accounts. As a result, there are no adjustments resulting from this translation reported in other comprehensive income.

67

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Revenue Recognition

Revenues for products sold by the refining, retail, and ethanol segments are recorded upon delivery of the products to our customers, which is the point at which tit le to the products is transferred, and when payment has either been received or collection is reasonably assured.

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.

We enter into certain purchase and sale arrangements with the same counterparty that are deemed to be made in contemplation of one another. 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 refineries. 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.

Stock-Based Compensation

Compensation expense for our share-based compensation plans is based on the fair value of the awards granted and is recognized in income on a straight-line basis over the requisite service period of each award. For new grants that have retirement-eligibility provisions, we use the non-substantive vesting period approach, under which 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.

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.

We have elected to classify any interest expense and penalties related to the underpayment of income taxes in income tax expense.

Earnings per Common Share

Earnings per common share is computed by dividing net income by the weighted-average number of common shares outstanding for the year. Participating share-based payment awards are included in the computation of basic earnings per share using the two-class method. Earnings per common share assuming dilution reflects the potential dilution arising from our outstanding stock options and nonvested shares granted to employees in connection wi th our stock compensation plans. Potentially dilutive securities are excluded from the computation of earnings per common share – assuming dilution when the effect of including such shares would be antidilutive when applied to income (loss) from continuing operations.

68

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effective January 1, 2009, we adopted amendments to ASC Topic 260, “Earnings Per Share,” which require participating share-based payment awards to be included in the computation of basic earnings per share using the two-class method and require the restatement of prior period earnings per share. S hares of restricted stock granted under certain of our stock-based compensation plans represent participating share-based payment awards covered by these provisions. The adoption of these provisions did not have any effect on the calculation of the basic loss per common share from continuing operations for the year ended 2008.

Fair Value Measurements and Disclosures

In January 2010, the provisions of ASC Topic 820, “Fair Value Measurements and Disclosures,” were modi fied to require additional disclosures, including transfers in and out of Level 1 and 2 fair value measurements and the gross basis presentation of the reconciliation of Level 3 fair value measurements. This guidance was effective for interim and annual reporting periods beginning after December 15, 2009, except for disclosures related to Level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010 (including interim periods). Early adoption was permitted. The adoption of this guidance effective December 31, 2009 did not affect our financial position or results of operations because these requirements only affected our disclosures.

Financial Instruments

Our financial instruments include cash and temporary cash investments, 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, except for certain debt as discussed in Note 11. The fair values of our debt, commodity derivative contracts, and foreign currency derivative contracts were estimated primarily based on year-end quoted market prices for identical and similar assets and liabilities in active markets.

Derivatives and Hedging

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 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 3 and 20, are recorded in cost of sales while income effects of interest rate swaps (if applicable) are recorded in interest and debt expense. The cash flow effects of all of our derivative contracts are reflected in cash flows from operating activities.

69

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In March 2008, ASC Topic 815, “Derivatives and Hedging,” was modified to establish disclosure requirements for derivative instruments and for hedging activities. The required disclosures include 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. These disclosures were effective for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008. The adoption of these provisi ons of ASC Topic 815 effective January 1, 2009 did not affect our financial position or results of operations but did result in additional disclosures, which are provided in Note 21.

New Accounting Pronouncements

Business Combinations

In December 2010, the provisions of ASC Topic 805, “Business Combinations,” were modified to specify that if a public entity presents comparative financial statements, then the entity should disclose pro forma revenues and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. In addition, the supplemental pro forma disclosures were expanded to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. This guidance is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010 with early adoption permitted. The adoption of this guidance effective January 1, 2011 will not affect our fin ancial position or results of operations because these requirements only affect disclosures.

Receivables

In July 2010, the provisions of ASC Topic 310, “Receivables,” were amended to enhance the disclosures about the credit quality of an entity’s financing receivables and the related allowance for credit losses. For public entities, the disclosures as of the end of a reporting period are effective for interim and annual reporting periods ending on or after December 15, 2010; disclosures about activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. The adoption of this guidance effective December 31, 2010 did not affect our financial position or results of operations nor will it affect our future financial position or results of operations because these requirements only affect disclosures.

2.     ACQUISITIONS

Acquisitions of Ethanol Plants

The acquired ethanol businesses as discussed below involve the production and marketing of ethanol and its co-products, including distillers grains. The operations of our ethanol business complement our existing clean motor fuels business.

ASA and Renew Assets

In December 2009, we signed an agreement with ASA Ethanol Holdings, LLC (ASA) to buy two ethanol plants located in Linden, Indiana and Bloomingburg, Ohio and made a $20 million advance payment towards the acquisition of these plants. On January 13, 2010, we completed the acquisition of these plants, including certain inventories, for total consideration of $202 million.

70

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Also in December 2009, we received approval from a bankruptcy court to acquire an ethanol plant located near Jefferson, Wisconsin from Renew Energy LLC (Renew) and made a $1 million advance payment towards the acquisition of this plant. We completed the acquisition of this plant, including certain receivables and inventories, on February 4, 2010 for total consideration of $79 million.

The assets acquired from ASA and Renew were recognized at acquisition-date fair values as determined by independent appraisals and other evaluations as follows (in millions):

Current assets, primarily inventory	$	11
Property, plant and equipment	269
Identifiable intangible assets	1
Total consideration	$	281

Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the ASA and Renew acquisitions, and no contingent assets or liabilities were acquired or assumed. Because these acquisitions were not material to our results of operations, we have not presented pro forma results of operations for the years ended December 31, 2010 and 2009, or actual results of operations from the acquisition dates through December 31, 2010. The consolidated statement of income for the year ended December 31, 2010 includes the results of the ASA and Re new acquisitions from their acquisition dates in 2010.

VeraSun Assets

In the second quarter of 2009, we acquired seven ethanol plants and a site under development from VeraSun Energy Corpor ation (VeraSun). The acquisition of these ethanol plants (referred to as the VeraSun Acquisition) was completed under three separate closing transactions. The ethanol plants are located in Charles City, Fort Dodge, Hartley, and Albert City, Iowa; Aurora, South Dakota; Welcome, Minnesota; Albion, Nebraska; and the site under development is located in Reynolds, Indiana.

Consideration for the VeraSun Acquisition was $477 million plus $79 million primarily for inventory and cer tain other working capital. We incurred approximately $10 million of acquisition-related costs that were recognized in general and administrative expenses in 2009. The acquisition was funded with part of the proceeds from a $1.0 billion issuance of notes in March 2009, which is discussed in Note 11.

The assets acquired and the liabilities assumed were recognized at their acquisition-date fair values as determined by an independent appraisal and other evaluations as follows (in millions):

Current assets, primarily inventory	$	77
Property, plant and equipment	491
Identifiable intangible assets	1
Current liabilities	(10		)
Other long-term liabilities	(3		)
Total consideration	$	556

71

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the VeraSun Acquisition, and no contingent assets or liabilities were acquired or assumed.

The consolidated statements of income include the results of operations of the ethanol plants commencing on their closing dates in the second quarter of 2009. Actual and pro forma information related to the VeraSun Acquisition is presented below (in millions, except per share amounts). The pro forma information assumes the acquisition date had occurred as of January 1 of each respective year and that the purchase price was funded with proceeds from the issuance of $556 million of debt. The consolidated pro forma financ ial information is not necessarily indicative of the results of future operations.

	Year Ended
	December 31,
	2009			2008
Actual results of operations from acquired business     from the closing dates through year end:
Operating revenues	$	1,198		N/A
Net income	92			N/A
Consolidated pro forma results of operations:
Operating revenues	64,822			$	108,165
Loss from continuing operations	(279		)	(1,252		)
Loss per common share from continuing operations – assuming dilution	(0.52		)	(2.39		)

Minor Acquisitions

In June 2009, we acquired the Trans-Texas Pipeline, the Wynnewood Pipeline, and their related tank and storage facilities from NuStar Logistics, L.P. for $29 million. These assets provide transportation and storage services for moving r efined products from our McKee Refinery to Mont Belvieu, Texas, and from our Ardmore Refinery to the Magellan pipeline system in the Midwest.

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

In February 2008, we acquired 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.

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3.     SALES OF ASSETS

Paulsboro Refinery

On December 17, 2010, we sold our Paulsboro Refinery to PBF Holding Company LLC (PBF Holding). Working capital, consisting primarily of inventory, was included as part of this transaction. The results of operations of the Paulsboro Refinery, including the loss on the sale discussed below, have been presented as discontinued operations for all years presented.

We received total proceeds of $707 million, including $361 million from the sale of working capital, resulting in a pre-tax loss of $980 million ($610 million after taxes). The loss includes a $50 million charge related to a LIFO inventory liquidation that resulted from the sale of inventory to PBF Holding and the effect of a $40 million accrual to settle differences between estimated and actual inventory volumes sold. The sale proceeds consisted of $547 million of cash and a $160 million note secured by the Paulsboro Refinery. The note matures in December 2011 and bears interest at LIBOR plus 700 basis points. PBF Holding has the option to extend the note for six months, however, the interest rate for the additional six months will be LIBOR plus 900 basis points.

The following financial information summarizes the Paulsboro Refinery assets and liabilities sold on December 17, 2010 and the comparative amounts as of December 31, 2009 (in millions), which have been reclassified to assets held for sale and liabilities related to assets held for sale.

	December 17, 2010		December 31, 2009
Current assets, primarily inventory	$	329	$	289
Property, plant and equipment, net	1,227		1,256
Deferred charges and other assets, net	50		48
Assets held for sale	$	1,606	$	1,593
Current liabilities	$	9	$	33
Liabilities related to assets held for sale	$	9	$	33

Results of operations of the Paulsboro Refinery prior to its sale, excluding the loss on the sale in 2010, are shown below (in millions).

	Year Ended December 31,
	2010			2009			2008
Operating revenues	$	4,692		$	3,545		$	6,460
Income (loss) before income taxes	(53		)	(133		)	(243		)

Delaware City Refinery Assets and Associated Terminal and Pipeline Assets

On November 20, 2009, we announced the permanent shutdown of our Delaware City Refinery, and we recorded a pre-tax loss of $1.9 billion, of which $1.4 billion represented the write-down of the book value of the refinery assets to net realizable value. The results of operations of the Delaware City Refinery have been presented as discontinued operations for all years presented because of the permanent shutdown of the

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NOTE S TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

refinery. Certain terminal and pipeline assets previously associated with the refinery were not shut down and continued to be operated until the date of their sale. The results of their operations are reflected in continuing operations for all years presented due to our post-closing participation in the terminalling agreement described below.

On June 1, 2010, we sold the shutdown refinery assets and the terminal and pipeline assets to wholly owned subsidiaries of PBF Energy Partners LP (PBF) for $220 million of cash proceeds. The sale resulted in a gain of $92 million ($58 million after taxes) related to the shutdown refinery assets and a gain of $3 million related to the terminal and pipeline assets. The gain on the sale of the shutdown refinery assets primarily resulted from receiving proceeds related to the scrap value of the assets and the reversal of certain liabilities recorded in 2009 in connection with the shutdown of the refinery, which we will not incur because of the sale. This gain is presented in discontinued operations for the year ended December 31, 2010.

The following financial information summarizes the Delaware City Refinery assets sold on June 1, 2010 and the comparative amounts as of December 31, 2009 (in millions), which have been reclassified to assets held for sale.

	June 1, 2010		December 31, 2009
Inventories	$	4	$	—
Property, plant and equipment, net
Refinery	16		16
Terminal and pipeline	140		141
Assets held for sale	$	160	$	157

Results of operations of the Delaware City Refinery prior to its sale, excluding the gain on the sale in 2010 and the loss on the shut down of the refinery in 2009, are shown below (in millions).

	Year Ended December 31,
	2010			2009			2008
Operating revenues	$	—		$	2,764		$	5,978
Loss before income taxes	(29		)	(769		)	(190		)

Krotz Springs Refinery

On July 1, 2008, we sold our Krotz Spring Refinery to Alon Refining Krotz Springs, Inc. (Alon), a subsidiary of Alon USA Energy, Inc. In addition, we sold working capital, consisting primarily of inventory, to Alon as part of this transaction. The nature and significance of our post-closing participation in an offtake agreement with Alon represented 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 for the year ended December 31, 2008. Under the off take agreement, 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.

&nb sp;

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NOTES TO C ONSOLIDATED FINANCIAL STATEMENTS (Continued)

We received total cash proceeds, net of certain costs related to the sale, of $463 million, including approximately $135 million from the sale of working capital, resulting in a pre-tax gain of $305 million ($170 million afte r taxes).

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. This earn-out agreement qualified as a derivative contract and had a fair value of $171 million as of July 1, 2008. We hedged the risk of a decline in the referenced product margins by entering into certain commodity derivative contracts. On August 27, 2009, we settled the earn-out agreement with Alon for $35 million, of which $18 million was received on the settlement date and the remaining amount will be received in eight payments of $2.2 million each quarter beginning in the fourth quarter of 2009. In connection with the settlement of the earn-out agreement, we effectively closed our positions in the related commodity derivative contracts during the third quarter of 2009, and we locked in $175 millionof cash proceeds on those contracts, approximately $105 million of which was received as of December 31, 2009 with the remaining proceeds to be received in varying monthly amounts through July 2011. As such, the total amount earned on the Alon earn-out agreement, including the related commodity derivative contracts, was $210 million.

Financial information as of July 1, 200 8 related to the Krotz Springs Refinery assets and liabilities sold is summarized as follows (in millions):

Current assets, primarily inventory	$	138
Property, plant and equipment, net	153
Goodwill	42
Deferred charges and other assets, net	4
Assets held for sale	$	337
Current liabilities	$	10
Liabilities related to assets held for sale	$	10

Investment in CHOPS

In November 2010, we sold our 50 percent interest in CHOPS to Genesis Energy, L.P. for total cash proceeds of $330 million. The sale resulted in a pre-tax gain of $55 million ($36 million after taxes), which is included in “other income, net” for the year ended December 31, 2010. CHOPS is a general partnership that operates a 390-mile crude oil pipeline, which delivers up to 500,000 barrels per day from the Gulf of Mexico to major refining areas of Port Arthur and Texas City, Texas. Our investment in CHOPS was accounted for using the equity method and was included in “deferred charges and other assets, net” as of December 31, 2009.

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4.     IMPAIRMENTS

General

In late 2008, the U.S. and worldwide economies experienced severe disruptions in their capital and commodities markets that resulted in a significant slowdown that persisted th roughout 2009. This slowdown negatively impacted refining industry fundamentals and the demand and prices for our refined products. We responded to this negative economic environment and its impact on our business by assessing the operating performance and profitability of our refining segment assets. This assessment led to our decision to shut down our Aruba Refinery temporarily in July 2009, to shut down our Delaware City Refinery permanently in late 2009 and ultimately sell that refinery in June 2010, and to sell our Paulsboro Refinery in December 2010, as discussed in Note 3. We also temporarily suspended construction activity on various capital projects and permanently cancelled other projects, as discussed below under “C apital Projects.” The negative economic conditions also contributed to a significant decline in our common stock price in late 2008 and caused our equity market capitalization to fall significantly below our net book value. We determined that our goodwill was impaired, and it was written off in 2008, as discussed below under “Goodwill.”

Long-Lived Assets, Excluding Capital Projects

The U.S. and worldwide economies and refining industry fundamentals improved throughout 2010, resulting in a significant improvement in the operating results of all of our refining segment assets. These improvements led to our decision to commence refinery-wide maintenance at our temporarily shutdown Aruba Refinery during the third quarter of 2010 to prepare the refinery’s production units for restart in January 2011; however, we evaluated our Aruba Refinery for potential impairment as of December 31, 2010 because of its temporary shutdown since July 2009 and the sensitivity of its profitability to sour crude oil d ifferentials. Sour crude oil differentials improved in 2010 along with other refining industry fundamentals, but their improvement was less significant. We considered these positive developments in our impairment evaluation and concluded that our Aruba Refinery was not impaired as of December 31, 2010. Our cash flow estimates for the refinery are based on our expectation that sour crude oil differentials will continue to improve in connection with an increase in the demand for refined products and the increased production of sour crude oils. Should differentials fail to widen or fail to widen to amounts experienced in prior years, our cash flow estimates will be negatively impacted and we could ultimately determine that the refinery is impaired. The Aruba Refinery had a net book value of $980 million as of December 31, 2010; therefore, an impairment loss could be material to our results of operations.

Capital Projects

We have continually evaluated all of our capital projects classified as “construction in progress” since late 2008. These evaluations have led to the permanent cancellation of certain projects, resulting in write-offs of project costs and the recognition of asset impairment losses as shown in the table below (in millions).

	Year Ended December 31,
	2010		2009	2008
Continuing operations	$	2	$

222  $

86

 Discontinued operations:     Delaware City Refinery—  377  17 Paulsboro Refinery—  8  — Asset impairment loss$2  $607  $103 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In conjunction with our e valuation of capital projects, we suspended construction activity on various other projects in 2009, including hydrocracker projects located at our St. Charles Refinery and our Port Arthur Refinery. Due to the improvement in refining industry fundamentals in 2010, we have decided to complete the hydrocrackers and other projects, and construction activity has commenced or is planned to commence in 2011.

Goodwill

As of December 31, 2007, we had $4.0 billion of goodwill, which was allocated among our Gulf Coast, Mid-Continent, Northeast, and West Coast reportin g units. As noted above, there were severe disruptions in the capital and commodities markets in late 2008 that contributed to a significant decline in our common stock price and caused our equity market capitalization to fall significantly below our net book value. As a result, we evaluated the potential impairment of our goodwill as of December 31, 2008. For purposes of this evaluation, 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. Based on this 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 for t he year ended December 31, 2008 as follows (in millions):

Continuing operations	$	4,007
Discontinued operations:
Delaware City Refinery	41
Paulsboro Refinery	21
Goodwill impairment loss	$	4,069

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5.     RECEIVABLES

Receivables consisted of the following (in millions):

	December 31,
	2010			2009
Accounts receivable	$	4,299		$	3,616
Commodity derivative receivables	144			183
Notes receivable and other	182			25
	4,625			3,824
Allowance for doubtful accounts	(42		)	(45		)
Receivables, ne t	$	4,583		$	3,779

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

	Year Ended December 31,
	2010			2009			2008
Balance as of beginning of year	$	45		$	58		$	43
Increase in allowance charged to expense	14			28			43
Accounts charged against the allowance, net of recoveries	(17		)	(42		)	(27		)
Foreign currency translation	—			1			(1		)
Balance as of end of year	$	42		$	45		$	58

6.     INVENTORIES

Inventories consisted of the following (in millions):

	December 31,
	2010		2009
Refinery feedstocks	$	2,225	$	2,004
Refined products and blendstocks	2,233		2,161
Ethanol feedstocks and products	201		141
Convenience store merchandise	101		96
Materials and supplies	187
		176
Inventories	$	4,947	$	4,578

During 2010 and 2009, we had net liquidations of LIFO inventory layers that were established in prior years, which decreased cost of sales in 2010 by $16 million and increased cost of sales in 2009 by $66 million. There was no substantial liquida tion of LIFO inventory layers in 2008. The effect of the liquidation in 2010

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excludes the impact from the sale of inventory to PBF Holding in connection with the sale of our Paulsboro Refinery to PBF Holding. The effect of the 2010 liquidation attributable to the sale of that inventory increased the loss on the sale of the Paulsboro Refinery by $50 million ($31 million after taxes) as discussed in Note 3.

As of December 31, 2010and 2009, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $6.1 billion and $4.5 billion, respectively.

7.     PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment, which include capital lease assets, consisted of the following (in millions):

Estimated Useful Lives	December 31,
	2010

2009Land  $624 $604 Crude oil processing facilities10 - 33 years 21,200  19,274 Butane processing facilities30 years 246  

246

 Pipeline and terminal facilities10 - 44 years 686  652 Grain processing equipment22 years 656  399 Retail facilities3 - 25 years 915  851 Buildings13 - 44 years 1,067  1,010 Other3 - 44 years 1,224  1,155 Construction in progress  2,303  2,694 Property, plant and equipment, at cost  28,921  26,885 Accumulated depreciation  (6,252) (5,270)Property, plant and equipment, net  $22,669  $21,615 

We had crude oil processing facilities, pi peline and terminal facilities, and certain buildings and other equipment under capital leases totaling $59 million and $55 million as of December 31, 2010 and 2009, respectively. Accumulated amortization on assets under capital leases was $22 million and $17 million, respectively, as of December 31, 2010 and 2009.

Depreciation expense for the years ended December 31, 2010, 2009, and 2008 was $985 million, $919 million, and $875 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8.     INTANGIBLE ASSETS

Intangible assets consisted of the following (in millions):

	December 31, 2010					December 31, 2009
	Gross Cost		Accumulated Amortization			Gross Cost		Accumulated Amortization
Intangible assets subject to amortization:
Customer lists	$	121	$	(68	)	$	114	$	(57	)
Canadian retail operations	155		(35		)	147		(30		)
U.S. retail store operations	65		(54		)	78		(64		)
Air emission credits	68		(38		)	62		(34		)
Royalties and licenses	25		(15		)	25		(14		)
Intangible assets subject to amortization	$	434	$	(210	)	$	426	$	(199	)

All of our intangi ble assets are subject to amortization. Intangible assets with finite useful lives are amortized on a straight-line basis over 2 to 40 years. Amortization expense for intangible assets was $22 million, $25 million, and $33 million for the years ended December 31, 2010, 2009, and 2008, respectively. The estimated aggregate amortization expense for the years ending December 31, 2011 through December 31, 2015 is as follows (in millions):

	Amortization Expense
2011	$	17
2012	17
2013	17
2014	17
2015	17

9.     DEFERRED CHARGES AND OTHER ASSETS

“Deferred charges and other assets, net” primarily includes refinery turnaround and catalyst costs , which are deferred and amortized as discussed in Note 1. Amortization expense related to continuing operations for deferred refinery turnaround and catalyst costs was $383 million, $404 million, and $384 million for the years ended December 31, 2010, 2009, and 2008, respectively.

“Deferred charges and other assets, net” also included our equity investment in CHOPS, which was sold in November 2010 as discussed in Note 3.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10.     ACCRUED EXPENSES AND OTHER LONG-TERM LIABILITIES

Accrued expenses and other long-term liabilities consisted of the following as of December 31 (in millions):

	Accrued Expenses						Other Long-Term Liabilities
	2010			2009			2010			2009
Defined benefit plan liabilities (see Note 14)	$	54		$	44		$	636		$	625
Wage and other employee-related liabilities	172			105			85			78
Uncertain income tax position liabilities (see Note 16)	—			—			343			481
Other tax liabilities	—			—			106			103
Environmental liabilities	40		41			228			238
Accrued interest expense	116			100			—			—
Derivative liabil ities	39			109			—			—
Insurance liabilities	—			—			80			84
Asset retirement obligations	20			103			81			76
Other	149			139			208			184
Accrued expenses and other long-term liabilities	$	590		$	641		$	1,767		$	1,869

Environmental Liabilities

The table below reflects the changes in our environmental liabilities as follows (in millions):

	Year Ended December 31,
	2010			2009			2008
Balance as of beginning of year	$	279		$	297		$	285
Additions to liability	50			21			75
Reductions to liability	(21		)	(5		)	(3		)
Payments, net of third-party recoveries	(42		)	(40		)	(51		)
Foreign currency translation	2			6			(9		)
Balance as of end of year	$	268		$	279		$	297

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. In addition, 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 wit hin a specified number of years after the assets were sold and result from events occurring or conditions existing prior to the date of sale.

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Asset Retire ment Obligations

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 es timate 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.

The table below reflects the changes in our asset retirement obligations (in millions).

	Year Ended December 31,
	2010			2009		2008
Balance as of beginning of year	$	179		$	72	$	70
Additions to accrual	3			98		4
Reductions to accrual	(34		)	—		—

Accretion expense7  14  3 Settlements(54) (5) (4)Foreign currency translation—  —  (1)Balance as of end of year$101  $179  $72

Other

Other tax liabilities relate primarily to contingent liabilities for transactional tax claims that are both probable and reasonably estimable.

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NOTES TO CONS OLIDATED FINANCIAL STATEMENTS (Continued)

11.     DEBT AND CAPITAL LEASE OBLIGATIONS

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

	Final Maturity	December 31,
		2010		2009
Bank credit facilities	Various	$	—	$	—
Industrial revenue bonds:
Tax-exempt Revenue Refunding Bonds:
Series 1997A, 5.45%	2027	21		24
Series 1997B, 5.40%	2018	30		33
Series 1997C, 5.40%	2018	30		33
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
4.50% notes	2015	400		—
4.75% notes	2013	300		300
4.75% notes	2014	200		200
6.125% notes	2017	750		750
6.125% notes	2020	850		—
6.625% notes	2037	1,500		1,500
6.875% notes

2012 750  750 7.50% notes2032 750  750 8.75% notes2030 200  200 Debentures:     7.25%2010 —  25 7.65%2026 100  100 8.75%2015 75  75 Senior Notes:     6.125%2011 200  200 6.70%2013 180  180 6.75%

2011

 210  210 6.75%2014 —  185 6.75%2037 24  24 7.20%2017 200  200 7.45%2097 100  100 7.50%2015 —  287 9.375%2019 750  750 10.50%2039 250  250 Gulf Opportunity Zone Revenue Bonds, Series 2010, variable rate2040 300  — Accounts receivable sales facility2011 100  200 Net unamortized discount, including fair value adjustments  (64) (56)Total debt  8,300  7,364 Capital lease obligations, including unamortized fair value adjustments 37  36 Total debt and capital lease obligations& nbsp; 8,337  7,400 Less current portion  (822) (237)Debt and capital lease obligations, less current portion  $7,515  $7,163 

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NOTES TO CONSOLIDATED FINANCIAL ST ATEMENTS (Continued)

Bank Credit Facilities

We have a $2.4 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 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 has certain restrictive covenants, including a maximum debt-to-capitalization ratio of 60 percent. As of December 31, 2010 and 2009, our debt-to-capitalization ratios, calculated in accordance with the terms of the Revolver, were 25.0 percent and 30.9 percent, respectively. We believe that we will remain in compliance with this covenant.

During the year ended December 31, 2010, we had no borrowings or repayments under our Revolver or other revolving bank credit facilities. During the years ended December 31, 2009 and 2008, we borrowed and repaid $39 million and $296 million, respectively, under the Revolver. As of December 31, 2010 and 2009, there were no borrowings outstanding under the Revolver and letters of credit outstanding under this committed facility totaled $399 million and $104 million, respectively.

In addition to the Revolver, one of our Canadian subsidiaries has a committed revolving credit facility under which it may borrow and obtain letters of credit up to Cdn. $115 million. As of December 31, 2010 and 2009, we had no borrowings outstanding under our Cana dian credit facility and letters of credit issued under this credit facility totaled Cdn. $20 million and Cdn. $22 million, respectively. The Canadian credit facility has a maturity date of December 2012.

In June 2010, 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 to support certain of our crude oil purchases. This agreement matures in June 2011. We are charged letter of credit issuance fees in connection with this letter of credit facility. As of December 31, 2010, we had $100 million of outstanding letters of credit issued under this revolving credit facility.

In December 2010, we entered into a short-term committed revolving letter of credit facility under which we may obtain letters of credit of up to $350 million composed of a committed maximum amount of $200 million and an uncommitted maximum amount of $150 million to support certain of our crude oil purchases. The committed portion of this facility matures in June 2011, and the uncommitted portion of this facility may be terminated with a 60-day prior written notice. We are charged letter of credit issuance fees in connection with the committed portion of this letter of credit facility. As of December 31, 2010, we had no outstanding letters of credit issued under the committed and uncommitted portions of this revolving credit fa cility.

We also have various other uncommitted short-term bank credit facilities. As of December 31, 2010 and 2009, we had no borrowings outstanding under our uncommitted short-term bank credit facilities; however, there were $176 million and $259 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Non-Bank Debt

In February 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 addition, in March 2008, we made a scheduled debt repayment of $7 million related to certain of our other debt.

In March 2009, we issued $750 million of 9.375% notes due March&n bsp;15, 2019 and $250 million of 10.5% notes due March 15, 2039. Proceeds from the issuance of these notes totaled $998 million, before deducting underwriting discounts and other issuance costs of $8 million.

In April 2009, we made scheduled debt repayments of $200 million related to our 3.5% notes and $9 million related to our 5.125% Series 1997D industrial revenue bonds.

In October 2009, we redeemed $76 million of our 6.75% senior notes with a maturity date of October 15, 2037 at 100% of stated value. As a result, a $6 million charge to write off a pro rata portion of the related unamortized fair value adjustment was recognized in “other income, net.”

In February 2010, we issued $400 million of 4.50% notes due in February 2015 and $850 million of 6.125% notes due in February 2020. Proceeds from the issuance of these notes totaled $1.244 billion, before deducting underwriting discounts and other issuance costs of $10 million.

In March 2010, we redeemed our 7.50%senior notes with a maturity date of June 15, 2015 for $294 million, or 102.5% of stated value. These notes had a carrying amount of $296 million as of the redemption date, resulting in a $2 million gain that was included in “other income, net.”

In April 2010, we made scheduled debt repayments of $8 million related to our Series A 5.45%, Series B 5.40%, and Series C 5.40%industrial revenue bonds.

In May 2010, we redeemed our 6.75% senior notes with a maturity date of May 1, 2014 for $190 million, or 102.2 5% of stated value. These notes had a carrying amount of $187 million as of the redemption date, resulting in a $3 million loss that was included in “other income, net.”

In June 2010, we made scheduled debt repayments of $25 million related to our 7.25% debentures.

In December 2010, the Parish of St. Charles, State of Louisiana (Issuer) issued Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds) totaling $300 million. The GO Zone Bonds initially bear interest at a weekly rate with interest payable monthly, commencing January 5, 2011. The GO Zone Bonds mature on December 1, 2040. Pursuant to a financing agreement, the Issuer lent the proceeds of the sale of the GO Zone Bonds to us to finance a portion of the construction costs of a hydrocracker project at our St. Charles Refinery. We received proceeds of $300 million, before deducting underwriting and issuance costs of $2 million. Under the financing agreement, we are obligated to pay the Issuer amounts sufficient for the Issuer to pay principal and interest on the GO Zone Bonds.

On February 1, 2011, we made a scheduled debt repayment of $210 million related to our 6.75% senior notes. On February 2, 2011, we paid $300 million to acquire the GO Zone Bonds, which were subject to mandatory tender on that date. We expect to hold the GO Zone Bonds for our own account until conditions permit the remarketing of these bonds at an interest rate acceptable to us.

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Accounts Receivable Sales Facility

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 2010, we amended the agreement to extend the maturity date to June 2011. 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, 2010 and 2009, $2.2 billion and $1.8 billion, respectively, of our accounts receivable composed the designated pool of accounts receivable included in the program. The amount of eligible receivables sold to the third-party entities and financial institutions was $100 million and $200 million as of December 31, 2010 and 2009, respectively. Proceeds from the sale of receivables under this facility are reflected as debt. During the years ended December 31, 2010 and 2009, we sold additional eligible receivables under this program of $1.2 billion and $950 million, respectively, and repaid $1.3 billion and $850 million, respectively.

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 were $8 million, $8 million, and $6 million for the years ended December 31, 2010, 2009, and 2008, respectively. Proceeds from collections under this facility of $4.3 billion, $5.5 billion, and $3.3 billion for the years ended December 31, 2010, 2009, and 2008, 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 2010, 2009, or 2008.

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Other Disclosures

In addition to the maximum debt-to-capitalization ratio applicable to the Revolver discussed above under “Bank Credit Facilities,” our bank credit facilities and other debt arrangements contain various customary restrictive covenants, including cross-default and cro ss-acceleration clauses.

Principal payments on our debt obligations and future minimum rentals on capital lease obligations as of December 31, 2010 were as follows (in millions):

	Debt			Capital Lease Obligations
2011	$	818		$	7
2012	759			6
2013	489			6
2014	209			5
2015	484			5
Thereafter	5,605			18
Net unamortized discount   and fair value adjustments	(64		)	—
Less interest expense	—			(10		)
Total	$	8,300		$	37

As of December 31, 2010 and 2009, the estimated fair value of our debt, including current portion, was as follows (in millions):

	December 31,
	2010		2009
Carrying amount	$	8,300	$	7,364
Fair value	9,492		8,228

The carrying amount of our debt is the amount of debt that is reflected on our consolidated balance sheets. The fair value of that debt is based on quoted prices in active markets or quoted prices for debt of other companies with similar credit ratings, interest rates, and terms.

&nb sp;

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12.     COMMITMENTS AND CONTINGENCIES

Operating 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, refined product and corn inventories.

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 claus es, which vary by charter, and provisions for the payment of chartering fees, which either vary based on usage or provide for payments, in addition to established minimums, that are contingent on usage. Leases for convenience stores may also include provisions for contingent rental payments based on sales volumes. In most cases, we expect that in the normal course of business, our leases will be renewed or replaced by other leases.

As of December 31, 2010, 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):

2011	$	353
2012	237
2013	160
2014	104
2015	85
Thereafter	324
Total minimum rental payments	1,263
Less minimum rentals to be received     under subleases	(15		)
Net minimum rental payments	$	1,248

Rental expense was as follows (in millions):

	Year Ended December 31,
	2010			2009			2008
Minimum rental expense	$	485		$	519		$	500
Contingent rental expense	23			21			23
Total rental expense	508			540			523
Less sublease rental income	(3		)	(4		)	(4		)
Net rental expense	$	505		$	536		$	519

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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 as liabilities.

Environmental Matters

While debate continues in the U.S. Congress regarding greenhouse gas legislation, the regulation of greenhouse gases at the federal level has now shifted to the U.S. Environmental Protection Agency (EPA), which began regulating greenhouse gases on January 2, 2011 under the Clean Air Act Amendments of 1990 (Clean Air Act). According to statements by the EPA, any new construction or material expansions will require that, among other things, a greenhouse gas permit be issued at either or both the state or federal level in accordance with the Clean Air Act and regulations, and we will be required to undertake a technology review to determine appropriate controls to be implemented with the project in order to reduce greenhouse gas emissions. The determination will be on a case by case basis, and the EPA has provided only genera l guidance on which controls will be required. Any such controls, however, could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

In addition, certain states have pursued independent regulation of greenhouse gases at the state level. For example, the California Global Warming Solutions Act, also known as AB 32, directs the California Air Resources Board (CARB) to develop and issue regulations to reduce greenhouse gas emissions in California to 1990 levels by 2020. CARB has issued a variety of regulations aimed at reaching this goal, including a Low Carbon F uel Standard (LCFS) as well as a state-wide cap-and-trade program. The LCFS is effective in 2011, with small reductions in the carbon intensity of transportation fuels sold in California. The mandated reductions in carbon intensity are scheduled to increase through 2020, after which another step-change in reductions is anticipated. The LCFS is designed to encourage substitution of traditional petroleum fuels, and, over time, it is anticipated that the LCFS will lead to a greater use of electric cars and alternative fuels, such as E85, as companies seek to generate more credits to offset petroleum fuels. The state-wide cap-and-trade program will begin in 2012. Initially, the program will apply only to stationary sources of greenhouse gases (e.g., refinery and power plant greenhouse gas emissions). Greenhouse gas emissions from fuels that we sell in California will be covered by t he program beginning in 2015. We anticipate that free allocations of credits will be available in the early years of the program, but we expect that compliance costs will be significant, particularly beginning in 2015, when fuels are included in the program. Complying with AB 32, including the LCFS and the cap-and-trade program, could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce. To the degree we are unable to recover these increased costs, these matters could have a material adverse effect on our financial position, results of operations, and liquidity.

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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 change s to our tax liabilities as a result of these audits may subject us to interest and penalties.

Effective June 1, 2010, the Government of Aruba (GOA) enacted a new tax regime applicable to refinery and terminal operations in Aruba. Under the new tax regime, we are subject to a profit tax rate of 7 percent and a dividend withholding tax rate of 0 percent. In addition, all imports and exports are exempt from turnover tax and throughput fees. Beginning June 1, 2012, we will also make a minimum annual tax payment of $10 million (payable in equal quarterly installments), with the ability to carry forward any excess tax prepayments to future tax years. 

The new tax regime was the result of a settlement agreement entered into on February 24, 2010 between the GOA and us that set the parties’ proposed terms for settlement of a lengthy and complicated tax dispute between the parties.  On May 30, 2010, the Aruban Parliament adopted several laws that implemented the provisions of the settlement agreement, which became effective June 1, 2010.  Pursuant to the terms of the settlement agreement, we relinquished the provisions of a previous tax holiday regime. On June 4, 2010, we made a payment to the GOA of $118 million (primarily from restricted cash held in escrow) in consideration of a full release of all tax claims prior to June 1, 2010. This settlement resulted in an after-tax gain of $30 million recognized primarily as a reduction to interest expense of $8 million and an income tax benefit of $20 million for the quarter ended June 30, 2010.

Health Care Reform

In March 2010, a comprehensive health care reform package composed of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (Health Care Reform) was enacted into law. Provisions of the Health Care Reform are expected to affect the future costs of our health care plans. An estimate of the impacts of the Health Care Reform is not yet practicable due to the number and complexity of the provisions; however, we are currently evaluating the potential impact of the Health Care Reform on our financial position and results of operations.

Litigation Matters

Retail Fuel Temperature Litigation

In 2006, a class action complaint was filed against us and several other defendants engaged in the retail and wholesale petroleum marketing business. The complaint alleges that because fuel volume increases with fuel temperature, the defendants violated state consumer protection laws by failing to adjust the volume or price 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. Following the 2006 complaint, numerous other federal complaints were filed, and there are now a total of 46 lawsuits of which 21 involve us. (We are named in classes involving several states where we have no retail presence.)  The lawsuits are consolidated into a multi-district litigation case in the U.S. District Court for the District of Kansas (Kansas City) (Multi-District Litigation Docket No. 1840, In re: Motor Fuel Temperature Sales Practices Litigation). In May 2010, the court issued an order in response to the plaintiffs’ motion for class certification of the Kansas cases. The court certified an “injunction class” covering nonmonetary relief but deferred ruling on

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

a “damages class.”  The court has scheduled trial in the Kansas cases for May 2012. We anticipate that the non-Kansas cases will be remanded in late 2011 or early 2012 with no additional rulings on the merits or class certification. We are a party to the Kansas cases, but we have no company-owned retail locations in Kansas. 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 that we may suffer a loss wi th 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.

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.

13.     STOCKHOLDERS’ EQUITY

Share Activity

For the years ended December 31, 2010, 2009, and 2008, activity in the number of shares of common stock and treasury stock was as follows (in millions):

	Common Stock	Treasury Stock
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	)
Sale of common stock	46	—
Shares issued, net of shares repurchased,   in connection with employee stock plans and other	—	2
Balance as of December 31, 2009	673	(109	)
Shares issued, net of shares repurchased,   in connection with employee stock plans and other	—	4
Balance as of December 31, 2010	673	(105	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Common Stock Offering

On June 3, 2009, we sold in a public offering 46 million shares of our common stock, which included 6 million shares related to an overallotment option exerci sed by the underwriters, at a price of $18.00 per share and received proceeds, net of underwriting discounts and commissions and other issuance costs, of $799 million.

Preferred Stock

We have 20 million shares of preferred stock authorized with a par value of $0.01 per share. No shares of preferred stock were outstanding during the years ended December 31, 2010, 2009, and 2008.

Treasury Stock

We purchase shares of our common stock in open market transactions to meet our obligations under employee stock-based compensation 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 February 28, 2008, our board of directors approved a $3 billion common stock purchase program, which is in addition to the remaining amount under a $6 billion program previously authorized. This additional $3 billion program has no expiration date. As of December 31, 2010, we had made no purchases of our common stock under this $3 billion program. As of December 31, 2010, we have approvals under these stock purchase programs to purchase approximately $3.5 billion of our common stock.

During the years ended December 31, 2010, 2009, and 2008, we purchased 0.7 million, 0.2 million, and 23.0 million shares of our common stock, respectively, at a cost of $13 million, $4 million, and $955 million, respectively. These pu rchases were made in connection with the administration of our stock-based compensation plans and the $6 billion common stock purchase program. During the years ended December 31, 2010, 2009, and 2008, we issued 4.4 million, 2.7 million, and 2.5 million shares from treasury, respectively, for our employee stock-based compensation plans.

Common Stock Dividends

On January 25, 2011, our board of directors declared a quarterly cash dividend of $0.05 per common share payable March 16, 2011 to holders of record at the close of business on February 16, 2011.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Accumulated Other Comprehensive Income

Accumulated balances for each component of accumulated other comprehensive income (loss) were as follows (in millions):

(217

	Foreign Currency Translation Adjustment			Pension/OPEB Liability Adjustment			Net Gain (Loss) On Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)
Balance as of December 31, 2007	$	580		$	(24	)	$	17		$	573
Other comprehensive income (loss)	(490		)	(411		)	152			(749		)
Balance as of December 31, 2008	90			(435		)	169			(176		)
Other comprehensive income (loss)	375			218			(52		)	541
Balance as of December 31, 2009	465			)		117			365
Other comprehensive income (loss)	158			(18		)	(117		)	23
Balance as of December 31, 2010	$	623		$	(235	)	$	—		$	388

14.     EMPLOYEE BENEFIT PLANS

Defined Benefit Plans

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 e mployees in the U.S. and generally provide eligible employees with retirement income based on years of service and compensation during specific periods. In addition, we have several nonqualified defined benefit pension plans (collectively, the Nonqualified Plans) that provide pension benefits to employees in Aruba and provide additional pension benefits to executive officers and certain other employees. The Qualified Plans and the Nonqualified 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 retiree health care benefits through a self-insured plan and, for certain locations, a health maintenance organization. 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. In March 2010, the Health Care Reform was enacted into law. As a result, income tax expense for the year ended December 31, 2010 includes a charge of $16 million related to the non-deductibility of certain retiree prescription health care costs, to the extent of federal subsidies received. Although the tax ch ange provisions of the Health Care Reform are not effective until 2013, the effect of changes in tax laws or rates on deferred tax assets and liabilities are recognized in the period that includes the enactment date, even though the changes may not be effective until future periods.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The changes in benefit obligation, the changes in fair value of plan assets, and the funded status of our Pension Plans and other postretireme nt benefit plans as of and for the years ended December 31, 2010 and 2009 were as follows (in millions):

	Pension Plans						Other Postretirement Benefit Plans
	2010			2009			2010			2009
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,454		$	1,492		$	466		$	520
Service cost	88			104			10			12
Interest cost	83			79			26			25
Participant contributions	—			—			12			9
Plan amendments	—			—			(31		)	(51		)
Special termination benefits	4			6			—			1
Medicare subsidy for prescription drugs	—			—			1			1
Benefits paid	(109		)	(74		)	(31		)	(28		)
Actuarial (gain) loss	106			(153		)	(28		)	(27		)
Foreign currency exchange rate changes	—			—			1			4
Benefit obligation at end of year	$	1,626		$	1,454		$	426		$	466
Change in plan assets:
Fair value of plan assets at beginning of year	$	1,251		$	1,005		$	—		$	—
Actual return on plan assets	149			228			—			—
Valero contributions	71			92			18			18
Participant contributions	—			—			12			9
Medicare subsidy for prescription drugs	—			—			1			1
Benefits paid	(109		)	(74		)	(31		)	(28		)
Fair value of plan assets at end of year	$	1,362		$	1,251		$	—		$	—
Reconciliation of funded status:
Fair value of plan assets at end of year	$	1,362		$	1,251		$	—		$	—
Less benefit obligation at end of year	1,626			1,454			426			466
Funded status at end of year	$	(264	)	$	(203	)	$	(426	)	$	(466	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The accumulated benefit obligations for certain of our Pension Plans exceed the fair values of the assets of those plans. For those plans, the table below presents the total projected benefit obligation, accumulated benefit obligation, and fair value of the plan assets (in millions).

	December 31,
	2010		2009
Projected benefit obligation	$	231	$	249
Accumulated benefit obligation	192		221
Fair value of plan assets	44		81

Benefit payments, which reflect expected future services that we expect to pay, and the anticipated Medicare subsidies that we expect to receive are as follows for the years ending December 31 (in millions):

&n bsp;	Pension Benefits		Other Postretirement Benefits		Medicare Subsidy
2011	$	89	$	25	$	(2	)
2012	87		27		(2		)
2013	89		28		n/a
2014	98		29		n/a
2015	105		30		n/a
Years 2016-2020	707		162		n/a

We have no minimum required contributions to our Pension Plans during 2011 under the Employee Retirement Income Security Act; however, we plan to contribute approximately $100 million to our Pension Plans during 2011.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The components of net periodic benefit cost were as follows for the years ended December 31, 2010, 2009, and 2008 (in millions):

	Pension Plans									Other Postretirement Benefit Plans
	2010			2009			2008			2010			2009			2008
Components of net periodic benefit cost:
Service cost	$	88		$	104		$	92		$	10		$	12		$	13
Interest cost	83			79			76			26			25			28
Expected return on plan assets	(112		)	(108		)	(105		)	—			—			—
Amortization of:
Prior service cost (credit)	3			3			3			(20		)	(19		)	(9		)
Net loss	2			10

  2  4  6  3 

Net periodic benefit cost before

    special charges

64  88  68  20  24  35 Charge for special termination benefits8  7  —  —  1  — Net periodic benefit cost$72  $95  $68  $20  $25  $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. The charge for special termination benefits in 2010 and 2009 relates to early retirement programs for corporate employees and employees at our Delaware City and Paulsboro Refineries.

Pre-tax amounts recognized in other comprehensive income for the years ended December 31, 2010 and 2009 were as follows (in millions):

	Pension Plans						Other Postretirement Benefit Plans
	2010			2009			2010			2009
Net (gain) loss arising during the year:
Net actuarial loss (gain)	$	68		$	(273	)	$	(28	)	$	(27	)
Prior service credit	—			—			(31		)	(51		)
Net gain (loss) reclassified into income:
Net actuarial loss	(2		)	(10		)	(4		)	(6		)
Prior service (cost) credit	(3		)	(3		)	20			19
Curtailment and settlement	(4		)	(1		)	&md ash;			—
Total ch anges in other     comprehensive (income) loss	$	59		$	(287	)	$	(43	)	$	(65	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The pre-tax amounts in accumulated other comprehensive income as of D ecember 31, 2010 and 2009 that have not yet been recognized as components of net periodic benefit cost were as follows (in millions):

	Pension Plans				Other Postretirement Benefit Plans
	2010		2009		2010				2009
Prior service cost (credit)	$	14	$	16	$	(126	)	& nbsp;	$	(115	)
Net actuarial loss	403		342		61				94
Total	$	417	$	358	$	(65	)		$	(21	)

The following pre-tax amounts included in accumulated other comprehensive income as of December 31, 2010 are expected to be recognized as components of net periodic benefit cost during the year ending December 31, 2011 (in millions):

	Pension Plans		Other Postretirement Benefit Plans
Amortization of prior service cost (credit)	$	2	$	(23	)
Amortization of net actuarial loss	12		2
Total	$	14	$	(21	)

The weighted-average assumptions used to determine the benefit obligations as of December 31, 2010 and 2009 were as follows:

Pension Plans					Other Postretirement   Benefit Plans
	2010		2009			2010		2009
Discount rate	5.40	%	5.80	%		5.22	%	5.68	%
Rate of compensation increase	3.56	%	3.47	%		—	%	—	%

The discount rate assumptions used to determine the pension plan and other postretirement benefit plan obligations as of December&n bsp;31, 2010 and 2009 were based on the Hewitt Above Median yield curve (HAM). The HAM was designed by Aon Hewitt to provide a means for plan sponsors to value the liabilities of their pension plans or other postretirement benefit plans. The HAM is a hypothetical double yield curve represented by a series of annualized individual discount rates with maturities from one-half year to more than 30 years. Each bond issue underlying the HAM 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.

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The weighted-average assumptions used to determine the net periodic benefit cost for the years ended December 31, 2010, 2009, and 2008 were as follows:

	Pension Plans						Other Postretirement Benefit Plans
	2010		2009		2008		2010		2009		2008
Discount rate	5.80	%	5.40	%	6.00	%	5.68	%	5.39	%	6.00	%
Expected long-term rate of return     on plan assets	7.71	%	7.72	%	8.23	%	—	%	—	%	—	%
Rate of compensation increase	4.18	%	4.18	%	4.40	%	—	%	—	%	—	%

The assumed health care cost trend rates as of December 31, 2010 and 2009 were as follows:

	2010		2009
Health care cost trend rate assumed for next year	7.46	%	7.50	%
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	2018		201 8

Assumed health care cost trend rates have a significant effect on the amounts reported for retiree 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	$	1	$	(1	)
Effect on accumulated postretirement benefit obligation	18		(16		)

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The tables below present the fair values of the assets of our Qualified Plans (in millions) as of December 31, 2010 and 2009 by level of the fair value hierarchy. Assets categorized in Level 1 of the hierarchy are measured at fair value using a market approach based on quotations from national securities exchanges. Assets categorized in Level 2 of the hierarchy are measured at net asset value as a practical expedient for fair value. As noted above, our other postretirement benefit plans are funded on a pay-as-you-go basis and have no assets. Our Nonqualified Plans have assets, but the fair values of the assets of these plans are presented in Note 20.

	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Total as of December 31, 2010
Equity securities:
Valero Energy Corporation     common stock	$	5	$	—	$	—		$	5
Other U.S. companies (a)	369		—		—			369
International companies	107		—		—			107
Preferred stock	1		—		—			1
Mutual funds:
International growth	117		—		—			117
Index funds (b)	64		—		—		64
Corporate debt instruments	274		—		—			274
Government securities:
U.S. Treasury securities	30		—		—			30
Mortgage-backed securities	3		—		—			3
Other government   securities	93		—		—			93
Common collective trusts	—		231		—			231
Insurance contracts	—		18		—			18
Interest and dividends   receivable	5		—		—			5
Cash and cash equivalents	45		—		—			45
Total	$	1,113	$	249	$	—		$	1,362

______________________

See notes on page 100.

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Equity securities:

	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total as of December 31, 2009
Valero Energy Corporation    common stock	$	15	$	—	$	—	$	15
Other U.S. companies (a)	518		—		—		518
International companies	98		—		—		98
Preferred stock	3		—		—		3
Mutual funds:
International growth	107		—		—		107
Index funds (b)	60		—		—		60
Corporate debt instruments	257		—		—		257
Government securities:
U.S. Treasury securities	38

—  —  38 

Mortgage-backed securities

2  —  —  

2

 

Other government

   securities

93  —  —  93 Insurance contracts—  18  —  18 

Interest and dividends

   receivable

4  —  —  4 Cash and cash equivalents38  —  — 38 Total$1,233  $18  $—  $1,251 

(a)     Equity securities are held in a wide range of industrial sectors, including consumer goods, information technology, healthcare, industrials, and financial services.

(b)     This class include primarily investments in approximately 60 percent equities and 40 percent bonds.

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. As of December 31, 2010, the target allocations for plan assets are 70 percent equity securities and 30 percent fixed income investments. Equity securities include international stocks and a blend of domestic growth and value stocks of various sizes of capitalization. Fixed income securities include bonds and notes issued by the U.S. government and its agencies, corporate bonds, and mortgage-backed securities. The aggregate asset allocation is reviewed on an annual basis.

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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.

Defined Contribution Plans

Valero Energy Corporation Thrift Plan

The Valero Energy Corporation Thrift Plan covers substantially all U.S. employees except for those employees covered by the plans discussed below. Employees are immediately eligible to participate in the plan and receive employer matching contributions.

Through December 31, 2009, participants could make basic contributions up to 8 percent of their total annual salary, which included overtime and cash bonuses. In addition, participants who made a basic contribution of 8 percent could also make a supplemental contribution of up to 22 percent of their total eligible annual salary. We matched 75 percent of each participant’s total basic contributions up to 8 percent based on the participant’s total annual salary, excluding cash bonuses. Commencing January 1, 2010, we match 100 percent of basic contributions up to 6 percent of each participant’s total annual salary, excluding cash bonuses.

Valero Savings Plan

The Valero Savings Plan covers our U.S. retail store employees, certain other employees supporting the retail organization, and employees at our ethanol plants. Under this plan, participants can contribute from 1 percent to 30 percent of their eligible compensation. We contribute $0.60 for every $1.00 of the participant’s contribution up to6 percent of eligible compensation. At our discretion, we may also make profit-sharing contributions, which can range from 3.5 to 5 percent of eligible compensation, to the Plan to be allocated to the participants.

Premcor Retirement Savings Plan

The Premcor Retirement Savings Plan covers certain union employees. Under this plan, particip ants can contribute from 1 percent to 50 percent of their eligible compensation. We contribute 200 percent of the first 3 percent of a participant’s eligible compensation. In addition, we contribute 100 percent of the next 3 percent of a participant’s eligible compensation for certain union participants who contribute to the plan.

Ultramar Ltd. Savings Plan

The Ultramar Ltd. Savings Plan covers all Canadian employees. Permanent employees are eligible after three months of service, temporary employees are eligible after one year of service, and seasonal employees are eligible after 220 days of service during 36 consecutive months. We contribute 9 percent of the employee’s base salary plus 50 percent of the employee’s voluntary contribution, which is limited to 6 pe rcent of the base salary. Our contribution does not exceed 12 percent of the base salary.

Valero Refining Company – Aruba N.V. Thrift Plan

The Valero Refining Company – Aruba N.V. Thrift Plan covers all Aruban employees. Employees are eligible to participate after completing one year of service and can contribute a maximum of 8 percent of salary. We match 100 percent of employee contributions up to a maximum of 8 percent based on years of service.

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Our contributions to these qualified defined contribution plans were as follows (in millions):

	Year Ended December 31,
	2010		2009		2008
Valero Energy Corporation Thrift Plan	$	36	$	37	$	38
Valero Savings Plan	6		5		5
Premcor Retirement Savings Plan	5		6		6
Ultramar Ltd. Savings Plan	9		8		9

Valero Refining Company – Aruba N.V.

  Thrift Plan

1  1  1 

We also have two nonqualified defined contribution plans, the assets and liabilities of which are measured and recorded at fair value on a recurring basis as disclosed in Note 20. No contributions were made to these nonqualified defined contribution plans for the years ended December 31, 2010, 2009, and 2008.

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15.     STOCK-BASED COMPENSATION

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, 2010, a total of 9,711,596 shares of our common stock remained available to be awarded under the OSIP.

•     The Restricted Stock Plan for Non-Employee Directors authorizes an annual grant of our common stock valued at $160,000 to each non-employee director. Vesting will occur based on the number of grants received as follows: (i) initial grants will vest in three equal annual installments, (ii) second grants will vest one third on the first anniversary of the grant date and the remainingtwo thirds on the second anniversary of the grant date, and (iii) all grants thereafter will vest 100 percent on the first anniversary of the grant date. As of December 31, 2010, a total of 77,839 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, 2010, a total of 46,5 93 shares of our common stock remained available to be awarded under this plan.

•     In addition, we 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 stock-based compensati on arrangements is discussed below.

The following table reflects activity related to our stock-based compensation arrangements (in millions):

	Year Ended December 31,
	2010		2009			2008
Stock-based compensation expense	$	54	$	68		$	59
Tax benefit recognized on stock-based    compensation expense	19		24			21
Tax benefit realized for tax deductions    resulting from exercises and vestings	23		9			22
Effect of tax deductions in excess of   recognized stock-based compensation   expense reported as a financing cash flow	11		5		&n bsp;	9

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Stock Options

U nder the terms of our various stock-based compensation 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-Schole s 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 years ended December 31, 2010, 2009, and 2008 was three years rather than five years as in prior years, historical exercise patterns did 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 i s presented in the table below.

	Y ear Ended December 31,
	2010		2009			2008
Expected life in years	6.0		6.0			4.5
Expected volatility	48.21	%	47.8	%		43.2	%
Expected dividend yield	1.05	%	3.1	%	;	3.5	%
Risk-free interest rate	1.83	%

 2.8% 2.8%

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

	Number of Stock Options		Weighted-Average Exercise Price Per Share		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
					(in years)	(in millions)
Outstanding at January 1, 2010	26,625,876		$	23.75
Granted	333,375		18.99
Exercised	(2,242,056	)	9.18
Forfeited	(337,637	)	38.21
Outstanding at December 31, 2010	24,379,558		24.83		3.8	$	145

         Exercisable at December 31, 201019,619,887  24.21  3.1  128 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The weighted-average grant-date fair value of stock options granted during the years ended December 31, 2010, 2009, and 2008 was $8 .17, $6.91, and $5.03 per stock option, respectively. The total intrinsic value of stock options exercised during the years ended December 31, 2010, 2009, and 2008 was $25 million, $12 million, and $47 million, respectively. Cash received from stock option exercises for the years ended December 31, 2010, 2009, and 2008 was $20 million, $11 million, and $16 million, respectively.

As of December 31, 2010, there was $23 million of unrecognized compensation cos t related to outstanding unvested stock option awards, which is expected to be recognized over a weighted-average period of approximately two 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 three to 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.

	Number of Shares		Weighted-Average Grant-Date Fair Value Per Share
Nonvested shares at January 1, 2010	2,598,297		$	26.12
Granted	2,138,414		18.78
Vested	(1,327,040	)	27.13
Forfeited	(49,458	)	26.20
Nonvested shares at December 31, 2010	3,360,213		21.05

As of December 31, 2010, there was $47 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 two years. The total fair value of restricted stock that vested during the years ended December 31, 2010, 2009, and 2008 was $25 million, $12 million, and $12 million, respectively.

Performance Awards

Performance awards are issued to certain of our key employees and represent rights to receive shares of our common stock upon the achievement by us of an objective performance measure. The objective performance measure is our total shareholder return, which is ranked among the total shareholder returns of a defined peer group of companies. Our ranking determines the rate at which the performance awards convert into our common shares. Conversion rates can range from zero to a maximum of 200 percent.

Performance awards vest in equal one-third increments (tranches) on an annual basis. Our compensation committee establishes the peer group of companies for each tranche of awards at the beginning of the one-year vesting period for that tranche. Therefore, performance awards are not considered to be granted for accounting purposes until our compensation committee establishes the peer group of companies for each tranche of awards. The fair value of each tranche of awards is determine d at the time the awards are considered to be granted and is based on the expected conversion rate for those awards and the fair value per share. Fair

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

value per share is equal to the market price of our common stock on the grant date reduced by expected dividends over that tranche’s vesting period.

If a tranche of awards fails to meet the minimum performance measure at the end of its vesting period as established by our compensation committee, that tranche of awards remains outstanding for an additional year and may convert into our common shares that following year. If such tranche of awards does not convert to our common shares the following year, those awards are forfeited.

A summary of the status of our performance awards considered granted is presented below.

	Nonvested Awards		Vested Awards
Awards as of January 1, 2010	48,455		67,882
Granted	253,611		—
Vested	(48,455	)	48,455
Converted	—		(58 ,186	)
Forfeited	—		(33,932	)
Awards as of December 31, 2010	253,611		24,219

There were two grants of performance awards during the year ended December 31, 2010. The fair value of the first grant of 31,361 awards was based on an expected conversion rate of 50 percent and a fair value per share of $18.15. The fair value of the second grant of 222,250 awards, which are subject to vesting during the year ending December 31, 2011 was based on an expected conversion rate of 83 percent and a fair value per share of $18.79.

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16.     INCOME TAXES

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

	Year Ended December 31,
	2010			2009			2008
U.S. operations	$	1,436		$	(371	)	$	(307	)
Canada operations	223			222			605
Aruba operations	(161		)	(167		)	(14		)
Income (loss) from continuing operations     before income tax expense (benefit)	$	1,498		$	(316	)	$	284

The following is a reconciliation of income tax expense (benefit) related to continuing operations to income taxes computed by applying the U.S. statutory federal income tax rate (35 percent for all years presented) to income (loss) from continuing operations before income tax expense (benefit) (in millions):

	Year Ended December 31,
	2010			2009			2008
Federal income t ax expense (benefit)    at the U.S. statutory rate	$	524		$	(111	)	$	99
U.S. state income tax expense (benefit),     net of U.S. federal income tax effect	(21		)	(2		)	18
U.S . manufacturing deduction	5			7			(55		)
Canada operations	(12		)	(6		)	(27		)
Aruba operations	39			81			7
Goodwill impairment	—			—			1,346
Permanent differences	8			(7		)	25
Change in tax law	16			—			—
Other, net	16			(5		)	25
Income tax expense (benefit)	$	575		$	(43	)	$	1,438

The Aruba Refinery’s profits through June 1, 2010 were non-taxable in Aruba due to a tax holiday granted by the GOA. The tax holiday had an immaterial effect on our consolidated results of operat ions for the years ended December 31, 2010, 2009, and 2008.

Income taxes related to discontinued operations for the years ended December 31, 2010, 2009, and 2008 were $370 million benefit, $1.1 billion benefit, and $29 million expense, respectively.

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

	Year Ended December 31,
	2010				2009			2008
Current:
U.S. federal	$	(75	)		$	(309	)	$	766
U.S. state	(13		)		(16		)	3
Canada	39			&nbs p;	120			45
Aruba	(17		)		22			2
Total current	(66		)		(183		)	816
Deferred:
U.S. federal	634				181			456
U.S. state	(19		)		12			26
Canada	26				(53		)	140
Total deferred	641				140			622
Income tax expense (benefit)	$	575

  $(43) $1,438 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

	December 31,
	2010			2009
Deferred income tax assets:
Tax credit carryforwards	$	99		$	88
Net operating losses (NOL)	265			241
Compensation and employee benefit liabilities	286			304
Environmental liabilities	85			85
Inventories	170			152
Other	184			234
Total deferred income tax assets	1,089			1,104
Less: Valuation allowance	(270		)	(200		)
Net deferred income tax assets	819			904
Deferred income tax liabilities:
Turnarounds	(256		)	(212		)
Property, plant and equipment	(4,835		)	(4,280		)
Inventories	(260		)	(399		)
Other	(65		)	(92		)
Total deferred income tax liabilities	(5,416		)	(4,983		)
Net deferred income tax liabilities	$	(4,597	)	$	(4,079	)

We had the following income tax credit and loss carryforwards as of December 31, 2010, (in millions):

	Amount		Expiration
U.S. state income tax credits	$	69	2012 through 2029
U.S. state inc ome tax credits	36		Unlimited
Foreign tax credit	30		2012
U.S. state NOL (gross amount)	5,492		2011 through 20 30

We have recorded a valuation allowance as of December 31, 2010 and 2009, due to uncertainties related to our ability to utilize some of our deferred income tax assets, primarily consisting of certain state NOLs, 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, 2010 is primarily dependent upon our ability to generate future taxable income in certain states and foreign source income in the U.S.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Subsequently recognized ta x benefits related to the valuation allowance for deferred income tax assets as of December 31, 2010 will be allocated as follows (in millions):

Income tax benefit	$	261
Additional paid-in capital	9
Total	$	270

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, 2010, the cumulative undistributed ea rnings of these subsidiaries were approximately $4.4 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.

The following is a reconciliation of the change in unrecognized tax benefits, excluding the effect of related penalties and interest and the federal tax effect of state unrecognized tax benefits (in millions):

	Year Ended December 31,
	2010			2009			2008
Balance as of beginning of year	$	484		$	238		$	164
Additions based on tax positions related to the current year	4			158			17
Additions for tax positions related to prior years	49			106			67
Reductions for tax positions related to prior years	(203		)	(6		)	(5		)
Reductions for tax positions related to the lapse of   applicable statute of limitations	(4		)	(1		)	(5		)
Settlements	—			(11		)	—
Balance as of end of year	$	330		$	484		$	238

As of December 31, 2010, 2009 and 2008, there were $153 million, $155 million, and $136 million respectively, of unrecognized tax benefits that if recognized would affect our annual effective tax rate. We do not expect our unrecognized tax benefits to change significantly over the next 12 months.

During the years ended December 31, 2010, 2009, and 2008, we recognized approximately $19 million, $22 million, and $22 million in interest and penalties, which is reflected within income tax expen se (benefit). We had accrued approximately $109 million and $90 million for the payment of interest and penalties as of December 31, 2010 and 2009, respectively.

Our tax years through 2001, UDS’s tax years through 2001, and Premcor’s tax years for 2002 and 2003 a re closed to adjustment by the Internal Revenue Service. Our tax years for 2002 through 2007 are currently under examination and Premcor’s separate tax years for 2004 and 2005 are currently under examination. The Internal Revenue Service proposed adjustments to our taxable income for certain open years, including adjustments related to depreciation methods. We are protesting the proposed adjustments and do not expect

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

that the ultimate disposition of these findings will result in a material change to our financial position or results of operations. We b elieve that adequate provisions for income taxes have been reflected in the consolidated financial statements.

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17.     EARNINGS (LOSS) PER COMMON SHARE

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

	Year Ended December 31,
	2010				2009					2008
	Restricted Stock		Common Stock		Restricted Stock		Common Stock			Restricted Stock		Common Stock
Earnings (loss) per common share from continuing operations:
Income (loss) from continuing operations			$	923			$	(273	)			$	(1,154	)
Less dividends paid:
Common stock			113				323					298
Nonvested restricted stock			1				1					1
Undistributed earnings (loss)			$	809			$	(597	)			$	(1,453	)
Weighted-average common shares outstanding	3		563		2		541			1		524
Earnings (loss) per common share from continuing operations:
Distributed earnings	$	0.21	$	0.20	$	0.61	$	0.60		$	0.56	$	0.57
Undistributed earnings (loss)	1.43		1.43		—

(1.10) —  (2.77)Total earnings (loss) per common share from continuing operations$1.64  $1.63  $0.61  $(0.50) $0.56  $(2.20)Earnings (loss) per common share from continuing operations – assuming dilution:           Income (loss) from continuing operations  $923    $(273)  $(1,154)Weighted-average common shares outstanding  563    541    524 Common equivalent shares:           Stock options  3    —    — Performance awards and unvested restricted stock  2    —    

—

 Weighted-average common shares outstanding – assuming dilution  568    541    524 Earnings (loss) per common share from continuing operations – assuming dilution  $1.62    $(0.50)  $(2.20)

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The following table reflects potentially dilutive securities (in millions) 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 antidilutive. These potentially dilutive securities included common equivalent shares (primarily stock options), which were excluded due to the loss from continuing operations for 2009 and 2008, and stock options for which the exercise prices were greater than the average market price of our common shares during each respective reporting period.

	Year Ended December 31,
	2010	2009	2008
Common equivalent shares	—	4	7
Stock options	14	12	7

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18.  ;    SEGMENT INFORMATION

Prior to the second quarter of 2009, we had two reportable segments, which were refining and retail. As a result of the VeraSun Acquisition during the second quarter of 2009 (as discussed in Note 2), ethanol is presented as a third reportable segment. 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. Our ethanol segment includes sales of internally-produced ethanol and distillers grains. Operations that are not included in any of the three 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.

The following table reflects activity related to continuing operations (in millions):

	Refining		Retail		Ethanol		Corporate		Total
Year ended December 31, 2010:
Operating revenues from external   customers	$	69,854	$	9,339	$	3,040	$	—	$	82,233
Intersegment revenues	6,416		—		245

  —  6,661 Depreciation and amortization expense1,210  108  36  51  1,405 Operating income (loss)1,903 346  209  (582) 1,876 Total expenditures for long-lived assets2,084  102  —  48  2,234           Year ended December 31, 2009:         

Operating revenues from external

  customers

55,516  7,885  1,198  —  64,599 Intersegment revenues5,137  —  137  —  5,274 Depreciation and amortization expense1,194  101  18  48  1,361 Operating income (loss)247  293  165  (622) 83 Total expenditures for long-lived assets2,338  66  5  39  2,448          Year ended December 31, 2008:         

Operating revenues from external

  customers

96,148  10,528

 —  —  106,676 Intersegment revenues7,703  —  —  —  7,703 Depreciation and amortization expense1,155  105  —  44  1,304 Operating income (loss)765  369  — (603) 531 Total expenditures for long-lived assets2,476  104  —  141  2,721 

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Our principal products include conventional and CARB gasolines, RBOB (reformulated gasoline blendstock for oxygenate blending), 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 cus tomers for our principal products were as follows (in millions):

	Year Ended December 31,
	2010			2009			2008
Refining:
Gasolines and blendstocks	$	35,731		$	28,320		$	42,647
Distillates	26,402			20,526			40,723
Petrochemicals	3,161			2,177			3,837
Lubes and asphalts	1,315			1,126			1,879
Other product revenues	3,245			3,367			7,062
Total refining operating revenues	69,854			55,516			96,148
Retail:
Fuel sales (gasoline and diesel)	7,498			6,148			8,750
Merchandise sales and other	1,581			1,505			1,446
Home heating oil	260		232			332
Total retail operating revenues	9,339			7,885			10,528
Ethanol:
Ethanol	2,647			1,032			—
Distillers grains	393			166			—
Total ethanol operating revenues	3,040			1,198			—
Consolidated operating revenues	$	82,233		$	64,599		$	106,676

Operating revenues by geographic area are shown in the table below (in millions). The geographic area is based on location of customer and no customer accounted for more than 10 percent of our consolidated operating revenues.

	Year Ended December 31,
	2010		2009		2008
U.S.	$	67,392	$	55,247	$	88,703
Canada	6,945		6,048		9,961
Other countries	7,896		3,304		8,012
Consolidated operating revenues	$	82,233

$64,599  $106,676 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Long-lived assets include property, plant and equipment, intangible assets, and certain long-lived assets included in “deferred charges and other assets, net.” Geographic information by country for long-lived assets, including long-lived assets related to discontinued operations, consisted of the following (in millions):

	December 31,
	2010		2009
U.S.	$	20,488	$	20,810
Canada	2,308		2,239
Aruba	981		1,002
Consolidated long-lived assets	$	23,777	$	24,051

Total assets by reportable segment, including assets related to discontinued operations, which are entirely related to our refining segment, were as follows (in million s):

	December 31,
	2010		2009
Refining	$	30,363	$	30,844
Retail	1,925		1,875
Ethanol	953		654
Corporate	4,380		2,199
Total consolidated assets	$	37,621	$	35,572

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19.     SUPPLEMENTAL CASH FLOW INFORMATION

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,
	2010			2009			2008
Decrease (increase) in current assets:
Receivables, net	$	(679	)	$	(806	)	$	4,865
Inventories	(407		)	(77		)	(705		)
Income taxes receivable	545			(668		)	(197		)
Prepaid expenses and other	107			56			(107		)
Increase (decrease) in current liabilities:
Accounts payable	670			1,475

(4,985)Accrued expenses(99) 73  (51)Taxes other than income taxes(66) 107  (4)Income taxes payable(3) 95  (446)Changes in current assets and current liabilities

$

68  $255  $(1,630)

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;

•     the amounts shown above exclude the current assets and current liabilities acquired i n connection with the acquisitions of ASA and Renew assets and the VeraSun Acquisition;

•     amounts accrued for capital expenditures, deferred turnaround and catalyst costs, and contingent earn-out payments are reflected in investing activities in the consolidated statements of cash flows when such amounts are paid;

•     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;

•     changes in assets held for sale and liabilities related to assets held for sale pertaining to the operations of the Paulsboro, Delaware City, and Krotz Springs Refineries prior to their sale 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.

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Noncash investing activities for the year ended December 31, 2010 consist of the $160 million note receivable from PBF Holding related to the sale of the Paulsboro Refinery discussed in Note 3. Noncash investing activities for the year ended December 31, 2008 consist of the contingent consideration received in the form of the $171 million earn-out agreement related to the sale of the Krotz Springs Refinery discussed in Note 3. There were no significant noncash investing activities for the year ended December 31, 2009.

There were no significant noncash financing activities for the years ended December 31, 2010, 2009 and 2008.

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

	Year Ended December 31,
	2010			2009			2008
Interest paid in excess of amount capitalized	$	(457	)	$	(390	)	$	(351	)
Income taxes received (paid), net	690			(165		)	1,455

Cash flows related to the discontinued operations of the Paulsboro and Delaware City Refineri es have been combined with the cash flows from continuing operations within each category in the consolidated statements of cash flows for all years presented and are summarized as follows (in millions):

	Year Ended December 31,
	2010			2009			2008
Cash provided by (used in) operating activities:
Paulsboro Refinery	$	88		$	10		$	246
Delaware City Refinery	(26		)	(126		)	81
Cash used in investing activities:
Paulsboro Refinery	(41		)	(121		)	(212		)
Delaware City Refinery	—			(153		)	(268		)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20.    FAIR VALUE MEASUREMENTS

General

A fair value hierarchy (Level 1, Level 2, or Level 3) is used to categorize fair value amounts based on the quality of inputs used to measure fair value. Accordingly, 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 and 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.

Recurring Fair Value Measurements

The tables below present information (in millions) about our financial assets and liabilities measured and recorded at fair value on a recurring basis and indicate the fair value hierarchy of the inputs utilized by us to determine the fair values as of December 31, 2010 and 2009.

	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments			Total as of December 31, 2010
Assets:
Commodity derivative contracts	$	3,240	$	489	$	—	$	(3,560	)	$	169
Nonqualified benefit plans	104		—		10		—			114
Liabilities:
Commodity derivative contracts	3,097		502		—		(3,560		)	39
Nonqualified benefit plans	36		—		—		—			36

	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments			Total as of December 31, 2009
Assets:
Commodity derivative contracts	$	2,148	$	2,517	$	—	$	(4,306	)	$	359
Nonqualified benefit plans	99		—		10		—			109
Liabilities:
Commodity derivative contracts	2,239		2,176		—

(4,306) 109 Nonqualified benefit plans34  —  —  —  34 

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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. 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, with appropriate consideration of counterparty credit risk, 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.

•     The nonqualified benefit plan assets and nonqualified benefit plan liabilities categorized in Level 1 of the fair value hierarchy are measured at fair value using a market approach based on quotations from national securities exchanges. The nonqualified benefit plan assets categorized in Level 3 of the fair value hierarchy represent insurance contracts, the fair values of which are provided by the insurer.

As of December 31, 2010, cash collateral deposi ts of $403 million with brokers under master netting arrangements is included in the fair value of the commodity derivatives reflected in Level 1. As of December 31, 2009, cash received from brokers of $64 million resulting from the equity in broker accounts covered by master netting arrangements exceeding the minimum margin requirements for such accounts, 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 positio ns. We have elected to offset the fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty, including any related cash collateral asset or obligation; however, fair value amounts by hierarchy level are presented on a gross basis in the tables above.

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

	Nonqualified Benefit Plans						Earn-Out Agreement
	2010		2009		2008		2010		2009			2008
Balance at beginning of year	$	10	$	—	$	—	$	—	$	13		$	—
Alon earn-out agreement   (see Note 3)	—		—		—		—		(33		)	171
Total gains (losses) included   in earnings	—		—		—		—		20			(158		)
Transfers in and/or out of  & nbsp;Level 3	—		10		—		—		—			—
Balance at end of year	$	10	$	10	$	—	$	—	$	—		$	13
The amount of total gains   (losses) included in earnings   attributable to the change in   unrealized gains or losses   relating to assets still held   at December 31	$	—	$	—	$	—	$	—	$	—		$	(158	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2009 and 2008, the amounts reflected in “total gains (losses) included in earnings” in the table above related to the earn-out agreement are reporte d in “other income, net.” We entered into the earn-out agreement with Alon in connection with the sale of our Krotz Springs Refinery in 2008 as discussed in Note 3. We also entered into commodity derivative instruments to hedge the risk of changes in the fair value of the earn-out agreement. The gains (losses) associated with these instruments are also reported in “other income, net.”

Non-recurring Fair Value Measurements

The table below presents information (in millions) about our nonfinancial assets and liabilities measured and recorded at fair value on a nonrecurring basis and indicates the fair value hierarchy of the inputs utilized by us to determine the fair values as ofDecember 31, 2009. As of and for the year ended December 31, 2010, there were no nonfinancial assets or liabilities that were measured and recorded at fair value on a nonrecurring basis.

Fair Value Measurements Using
Quoted Prices in Active Markets (Level 1)	Significant Other Observable Inputs (Level 2)

 

Significant Unobservable Inputs

(Level 3)

 Total as of
December 31,
2009 Total LossesAssets:         

Long-lived assets of

   discontinued

   Delaware City Refinery

$—  

$

—  $16  $16 $(1,901)

Cancelled capital projects

   in progress

—  —  —  —  (607)Liabilities:         

Asset retirement

   obligations

—  —  95  95  (95)

The $16 million fair value of the discontinued Delaware City Refinery represented our estimated net realizable value for the combined cycle power plant, which was the only part of the refinery that was deemed to have any salvage value as of December 31, 2009. The $1.9 billion loss, which is reflected in discontinued operations for the year ended December 31, 2009, relates to the impairment loss reco gnized related to all long-lived assets of the Delaware City Refinery, as discussed in Note 3. See Note 4 for a discussion of the loss resulting from the cancellation of various capital projects in progress.

Asset retirement obligations in the tables above are calculated based on the present value of estimated removal and other closure costs using our internal risk-free rate of return or appropriate equivalent. The $95 million loss relates to asset retirement costs associated with the shutdown of the Delaware City Refinery, which is included in the loss from discontinued operations for the year ended December 31, 2009.

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21.     PRICE RISK MANAGEMENT ACTIVITIES

We are exposed to market risks related to the volatility in the price of commodities, interest rates and foreign currency exchange rates, and we enter into derivative instruments to manage those risks. We also enter into derivative instruments to manage the price risk on other contractual derivatives into which we have entered. The only types of derivative instruments we enter into are those related to the various commodities we purchase or produce, interest rate swaps, and foreign cur rency exchange and purchase contracts, as described below. All derivative instruments are recorded 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 t he 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. The cash flow effects of all of our derivative contracts are reflected in operating activities in the consolidated statements of cash flows for all periods presented.

Commodity Price Risk

We are exposed to market risks related to the price of crude oil, refined products (primarily gasoline and d istillate), grain (primarily corn), and natural gas used in our refining operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, including swaps, futures, and options. We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations. We use swaps primarily to manage our price exposure. Our positions in commodity derivative 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.

For risk management purposes, we use fair value hedges, cash flow hedges, and economic hedges. In addition to the use of derivative instruments to manage commodity price risk, we also enter into certain commodity derivative instruments for trading purposes. Our objective for entering into each type of hedge or trading activity is described below.

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Fair Value Hedges

Fair value hedges are used to hedge certain refining inventories and firm commitments to purchase inventories. The level of activity for our fair value hedges is based on the level of our operating inventories, and generally represents the amount by which o ur inventories differ from our previous year-end LIFO inventory levels.

As of December 31, 2010, we had the following outstanding commodity derivative instruments that were entered into to hedge crude oil and refined product inventories. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).

	Notional Contract Volumes by Year of Maturity
Derivative Instrument	2011
Crude oil and refined products:
Futures - long	13,589
Futures - short	23,240

Cash Flow Hedges

Cash flow hedges are used to hedge certain forecasted feedstock and refined product purchases, refined product sales, and natural gas purchases. The objective of our cash flow hedges is to lock in the price of forecasted feedstock, product, or natural gas purchases or refined product sales at existing market prices that we deem favorable. As of December 31, 2010, we had no outstanding commodity derivative instruments that were designated as cash flow hedges.

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Economic Hedges

Economic hedges are hedges not designated as fair value or cash flow hedges that are used to (i) manage price volatility in certain refinery feedstock, refined product, and corn inventories, and (ii) manage price volatility in certain forecasted refinery feedstock, refined product, and corn purchases, refined product sales, and natural gas purchases. Our objective in entering into economi c hedges is consistent with the objectives discussed above for fair value hedges and cash flow hedges. However, the economic hedges are not designated as a fair value hedge or a cash flow hedge for accounting purposes, usually due to the difficulty of establishing the required documentation at the date that the derivative instrument is entered into that would allow us to achieve “hedge deferral accounting.”

As of December 31, 2010, we had the following outstanding commodity derivative instruments that were entered into as economic hedges. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those iden tified as corn contracts that are presented in thousands of bushels).

	Notional Contract Volumes by Year of Maturity
Derivative Instrument	2011	2012
Crude oil and refin ed products:
Swaps - long	149,100	—
Swaps - short	147,872	—
Futures - long	164,130	223
Futures - short	164,163	323
Options - long	2,410	—
Options - short	2,400	—
Corn:
Futures - long	10,670	40
Futures - short	56,895	2,870

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Trading Activities

Derivatives entered into for trading purposes represent commodity derivative instruments held or issued for trading purposes. Our objective in entering into commodity derivative instruments for trading purposes is to take advantage of existing market conditions related to commodities that we perceive as opportunities to benefit our results of operations and cash flows, but for which there are no related physical transactions.

As of December 31, 2010, we had the following outstanding commodity derivative instruments that were entered into for trading purposes. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes represent thousands of barrels, except those identified as natural gas contracts that are presented in billions of British thermal units and corn contracts that are presented in thousands of bushels).

	Notional Contract Volumes by Year of Maturity
De rivative Instrument	2011	2012
Crude oil and refined products:
Swaps - long	20,111	—
Swaps - short	20,111	—
Futures - long	30,400	969
Futures - short	30,139	1,094
Natural gas:
Futures - long	2,500

 — Futures - short 2,500  — Corn:    Futures - long 1,550  — Futures - short 1,150  — 

Interest Rate Risk

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, at times we have used interest rate swap agreements to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt. These interest rate swap agreements are generally accounted for as fair value hedges. However, we have not had any outstanding interest rate swap agreements since 2006.

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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 contrac ts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of December 31, 2010, we had commitments to purchase $487 million of U.S. dollars. These commitments matured on or before January 31, 2011.

Fair Values of Derivative Instruments

The following tables provide information about the fair values of our derivative instruments as of December 31, 2010 and 2009 (in millions) and the line items in the consolidated balance sheet in which the fair values are reflected. See Note 20 for additional information related to the fair values of our derivative instruments.

As indicated in Note 20, we net fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty under master netting arrangements. The tables below, however, are presented on a gross asset and gross liability basis, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts. In addition, in Note 20, we included cash collateral on deposit with or received from brokers in the fair value of the commodity derivatives; these cash amounts are not reflected in the tables below.

		Fair Value as of
		December 31, 2010
	Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	120	$	183
Swaps	Prepaid expenses and other	55		39
Swaps	Accrued expenses	31		32
Total		$	206	$	254
Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	2,717	$	2,914
Swaps	Prepaid expenses and other	287		277
Swaps	Accrued expenses	116		148
Options	Accrued expenses	—		6
Total		$	3,120	$	3,345
Total derivatives		$	3,326	$	3,599

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		Fair Value as of
		December 31, 2009
	Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	1	$	2
Futures	Accrued expenses	13		37
Swaps	Receivables, net	308		271
Swaps	Prepaid expenses and other	579		415
Swaps	Accrued expenses	28		19
Total		$	929	$	744
Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	34	$	29
Futures	Accrued expenses	2,094		2,101
Swaps	Receivables, net	506		370
Swaps	Prepaid expenses and other	1,049		1,037
Swaps	Accrued expenses	46		62
Options	Accrued expenses	—		1
Total		$	3,729	$	3,600
Total derivatives		$	4,658	$	4,344

Market and Counterparty Risk

Our price risk management activities involve th e 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 counterparty risk because 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.

As of December 31, 2010, we had net receivables related to derivative instruments of $4 million from counterparties in the refining industry and $21 million from counterparties in the financial services industry. As of December 31, 2009, we had net receivables related to derivative instruments of $19 million from counterparties in the refining industry and $157 million from counterparties in the financial services industry. These amounts represent the aggregate amount payable to us by companies in those industries, reduced by

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payables from us to those companies under master netting arrangements that allow for the setoff of amounts receivable fr om and payable to the same party. We do not require any collateral or other security to support derivative instruments into which we enter. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.

Effect of Derivative Instruments on Consolidated Statements of Income and Other Comprehensive Income

The following tables provide information about the gain or loss recognized in income and other comprehensive income on our derivative instruments for the years ended December 31, 2010 and 2009 (in millions), and the line items in the consolidated financial statements in which such gains and losses are reflected.

Derivatives in Fair Value Hedging Relationships		Gain or (Loss) Recognized in Income on Derivatives					Gain or (Loss) Recognized in Income on Hedged Item					Gain or (Loss) Recognized in Income for Ineffective Portion of Derivative
	Location	2010		2009			2010			2009		2010		2009
Commodity contracts	Cost of sales	$	45	$	(75	)	$	(40	)	$	69	$	5	$	(6	)

For fair value hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effective ness. No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges.

Derivatives in Cash Flow Hedging Relationships	Gain or (Loss) Recognized in OCI on Derivatives (Effective Portion)				Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Gain or (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	2010			2009	Location	2010	2009	Location	2010	2009
Commodity contracts	$	(2	)	$

125  Cost of sales $178  $337  

Cost of sales

$—  $3 Commodity contracts—  —  Income (loss) from discontinued operations, net of income taxes —  (132) Income (loss) from discontinued operations, net of income taxes—  

—

 Total $(2) $125  &nbs p; $178  $205   $—  $3 

For cash flow hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness. For the year ended December 31, 2010, there were no amounts reclassified from accumulated other comprehensive income into income as a result of the discontinuance of cash flow hedge accounting. For the year ended December 31, 2009, there were$132 million of pre-tax losses reclassified from accumulated other comprehensive income into income as a result of the discontinuance of cash flow hedge accounting. This amount, which is the amount classified as a loss from discontinued operations in the table, relates to the forecasted sales of distillates that did not occur due to the shutdown of the Delaware City Refinery.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2010, cash flow hedges primarily related to forward sales of distillates and associated forward purchases of crude oil, with no amount of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive income as of December 31, 2010.

Derivatives Designated as Economic Hedges and Other Derivative Instruments	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2010			2009
Commodity contracts	Cost of sales	$	(210	)

 $55 Foreign currency contracts Cost of sales (24) (22)    (234) 33 Alon earn-out agreement Other income, net —  20 Alon earn-out hedge (commodity contracts) Other income, net —  (62)    —  (42)Total   $(234) $(9)

Derivatives Designated as Trading Activities	Location of Gain Recognized in Income on Derivatives	Amount of Gain Recognized in Income on Derivatives
		2010		2009
Commodity contracts	Cost of sales	$	8	$	126

22.     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, 2010:

•$210 million of 6.75% senior notes due February 2011, and

•$200 million of 6.125% senior notes due May 2011.

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

The following condensed c onsolidating 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.

129

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet as of December 31, 2010

(in millions)

	Valero Energy Corporation			PRG			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Curren t assets:
Cash and temporary cash investments	$	2,023		$	—		$	1,311		$	—		$	3,334
Receivables, net	160			33			4,390			—			4,583
Inventories	—			420			4,527			—			4,947
Income taxes receivable	293			—			343			(293		)	343
Deferred income taxes	—			—			190			—			190
Prepaid expenses and other	—			7			114			—			121
Total current assets	2,476			460			10,875			(293		)	13,518
Property, plant and equipment, at cost	—			4,284			24,637			—			28,921
Accumulated depreciation	—		& nbsp;	(499		)	(5,753		)	—			(6,252		)
Property, plant and equipment , net	—			3,785			18,884			—			22,669
Intangible assets, net	—			—			224			—			224
Investment in Valero Energy affiliates	6,143			5,568			114			(11,825		)	—
Long-term notes receivable from affiliates	14,579			—			—			(14,579		)	—
Deferred income tax receivable	550			—			—			(550		)	—
Deferred charges and other assets, net	143			133			934			—			1,210
Total assets	$	23,891		$	9,946		$

31,031  $(27,247) $37,621 LIABILITIES AND STOCKHOLDERS’ EQUITYCurrent liabilities:         

Current portion of debt and capital lease

  obligations

$8  $410  $404  $—  $822 Accounts payable1  93  6,347  —  6,441 Accrued expenses156  46  388  —  590 Taxes other than income taxes—  15  656  —  671 Income taxes payable—  —  296  (293) 3 Deferred income taxes257  —  —  — 257 Total current liabilities422  564  8,091  (293) 8,784

Debt and capital lease obligations,

  less current portion

7,482  —  33  —  7,515 Long-term notes payable to affiliates—  8,190  6,389  (14,579) — Deferred income taxes—  911  4,169  (550) 4,530 Other long-term liabilities962  167  638  —  1,767 Stockholders’ equity:         Common stock7  

—

  1  (1) 7 Additional paid-in capital7,704  3,719  7,026  (10,745) 7,70 4 Treasury stock(6,462)

—  —  —  (6,462)Retained earnings13,388  (3,599) 4,709  (1,110) 13,388 

Accumulated other comprehensive

  income (loss)

388  (6) (25) 31  3 88 Total stockholders’ equity15,025  114  11,711  (11,825) 15,025 Total liabilities and stockholders’ equity$23,891  $9,946  $31,031  $(27,247) $37,621 

130

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet as of December 31, 2009

(in millions)

	Valero Energy Corporation		PRG			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	78	$	—		$	747		$	—		$	825
Receivables, net	—		28			3,751			—			3,779
Inventories	—		424			4,154			—			4,578
Income taxes receivable	858		—			887			(858		)	887
Deferred income taxes	—		—			180			—			180
Prepaid expenses and other	—		7			377			—			384
Assets held for sale	—		—			289			—			289
Total current assets	936		459			10,385			(858		)	10,922
Property, plant and equipment, at cost	—		4,087			22,798			—			26,885
Accumulated depreciation	—		(388		)	(4,882		)	—			(5,270		)
Property, plant and equipment, net	—		3,699			17,916			—			21,615
Intangible assets, net	—		—			227			—			227
Investment in Valero Energy affiliates	6,456		3,807			68			(10,331		)	—
Long-term notes receivable from affiliates	14,181

—  ��  (14,181) — Deferred income tax receivable809  —  —  (809) — Deferred charges and other assets, net133  67  1,147

  —  1,347 Long-term assets held for sale—  157  1,304  —  1,461 Total assets$22,515  $8,189  $31,047  $(26,179) $35,572 LIABILITIES AND STOCKHOLDERS’ EQUITYCurrent liabilities:         

Current portion of debt and capital lease

  obligations

$33  $—  $204  $—  $237 Accounts payable52  223  5,550  —  5,825 Accrued expenses117  222  302 & nbsp;—  641 Taxes other than income taxes—  19  706  —  725 Income taxes payable—  —  953  (858) 95 Deferred income taxes253  —  —  —  253 Liabilities related to assets held for sale—  8  25 —  33 Total current liabilities455  472  7,740  (858) 7,809 

Debt and capital lease obligations,

  less current portion

6,236  895  32  —  7,163 Long-term notes payable to affiliates—  5,924  8,257  (14,181) — Deferred income taxes—  703  4,112  (809) 4,006 Other long-term liabilities1,099  127  643  —  1,869 Stockholders’ equity:         Common stock7  —  1  (1) 7 Additional paid-in capital7,896  3,719  6,887  (10,606) 7,896 Treasury stock(6,721) —  —  —  (6,721)Retained earnings13,178  (3,644) 3,262  382  13,178 

Accumulated other comprehensive income

  (loss)

365  (7) 113  (106) 365 Total stockholders’ equity14,725  68  10,263  (10,331) 14,725 Total liabilities and stockholders’ equity$22,515  $8,189  $31,047  $(26,179) $35,572 

131

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income for the Year Ended December 31, 2010

(in millions)

	Valero Energy Corporation			PRG				Other Non-Guarantor Subsidiaries				Eliminations				Consolidated
Operating revenues	$	—		$	14,610			$	80,120			$	(12,497	)		$	82,233
Costs and expenses:
Cost of sales	—			16,155				70,800				(12,497		)		74,458
Operating expenses	—			297			3,664				—				3,961
General and administrative expenses	2			(14		)		543				—				531
Depreciation and amortization expense	—			149				1,256				—				1,405
Asset impairment loss	—			—				2				—				2
Total costs and expenses	2			16,587				76,265				(12,497		)		80,357
Operating income (loss)	(2		)	(1,977		)		3,855				—				1,876
Equity in earnings of subsidiaries	76			1,649				46				(1,771		)		—
Other income (expense), net	1,139			(34		)		791				(1,790		)		106
Interest and debt expense:
Incurred	(706		)	(513		)		(1,145		)		1,790				(574		)
Capitalized	—			6				84				—				90
Income (loss) from continuing operations   before income tax expense (benefit)	507			(869		)		3,631				(1,771		)		1,498
Income tax expense (benefit)	183			(872		)		1,264				—				575
Income from continuing operations	324			3				2,367				(1,771		)		923
Income (loss) from discontinued operations,   net of income taxes	—			43				(642		)		—				(599		)
Net income	$	324		$	46			$	1,725			$	(1,771	)		$	324

132

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANC IAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income for the Year Ended December 31, 2009

(in millions)

	Valero Energy Corporation			PRG				Other Non-Guarantor Subsidiaries				Eliminations				Consolidated
Operating revenues	$	—		$	10,864			$	63,860		&nb sp;	$	(10,125	)		$	64,599
Costs and expenses:
Cost of sales	—			11,979				56,832				(10,125		)		58,686
Operating expenses	—			287				3,388				—				3,675
General and administrative expenses	3			43			526		&n bsp;		—				572
Depreciation and amortization expense	—			129				1,232				—				1,361
Asset impairment loss	—			131				91				—				222
Total costs and expenses	3			12,569				62,069				(10,125		)		64,516
Operating income (loss)	(3		)	(1,705		)		1,791				—				83
Equity in earnings (losses) of subsidiaries	(2,220		)	947				(2,121		)		3,394				—
Other income (expense), net	1,154			(55		)		727				(1,809		)		17
Interest and debt expense:
Incurred	(633		)	(542		)		(1,155		)		1,809				(521		)
Capitalized	—			13				92				—				105
Loss from continuing operations before   income tax expense (benefit)	(1,702		)	(1,342		)		(666		)		3,394				(316		)
Income tax expense (benefit)	280			(851		)		528				—				(43		)
Loss from continuing operations	(1,982		)	(491		)		(1,194		)		3,394

 (273)

Loss from discont inued operations,

  net of income taxes

—  (1,630) (79) —  (1,709)Net loss$(1,982) $(2,121) $

(1,273

) $3,394  $(1,982)

133

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income for the Year Ended December 31, 2008

(in millions)

	Valero Energy Corporation			PRG			Other Non-Guarantor Subsidiaries			Eliminations				Consolidated
Operating revenues	$	—		$	20,105		$	103,537		$	(16,966	)	&nbs p;	$	106,676
Costs and e xpenses:
Cost of sales	—			19,683			93,370			(16,966		)		96,087
Operating expenses	—			443			3,964			—				4,407
General and administrative expenses	(9		)	40			528			—				559
Depreciation and amortization expense	—			140			1,164			—				1,304
Asset impairment loss	—			43			43			—				86
Gain on sale of Krotz Springs Refinery	—			—			(305		)	—				(305		)
Goodwill impairment loss	—			1,796			2,211			—				4,007
Total costs and expenses	(9		)	22,145			100,975			(16,966		)		106,145
Operating income (loss)	9			(2,040		)	2,562			—				531
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		)	(1,092		)	1,769				(452		)
Capitalized	—			17			75			—				92
Income (loss) from continuing operations   before income tax expense (benefit)	(921		)	(1,762		)	890			2,077				284
Income tax expense (benefit)	210			(358		)	1,586			—				1,438
Loss from continuing operations	(1,131		)	(1,404		)	(696		)	2,077				(1,154		)
Income (loss) from discontinued operations,   net of income taxes	—			(119		)	142			—				23
Net loss	$	(1,131	)	$	(1,523	)	$	(554	)	$	2,077			$	(1,131	)

134

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2010

(in millions)

	Valero Energy Corporation			PRG			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in)   operating activities	$	687		$	(1,563	)	$	3,921		$	—		$	3,045
Cash flows from investing activities:
Capital exp enditures	—			(221		)	(1,509		)	—			(1,730		)
Deferred turnaround and catalyst costs	—			(85		)	(450		)	—			(535		)
Acquisitions of ethanol plants	—			—			(260		)	—			(260		)
Proceeds from the sale of the   Paulsboro Refinery	—			—			547			—			547
Proceeds from the sale of the   Delaware City Refinery assets and   as sociated terminal and pipeline assets	—			210			10			—			220
Proceeds from the sale of investment in   CHOPS	—			—			330			—			330
Net intercompany loan repayments	36			—			—			(36		)	—
Investments in subsidiaries	(8		)	(112		)	—

 120  — Return of investment124  —  —  (124)

— Other investing activities, net—  —  23  —  23 

Net cash provided by (used in)

  investing activities

152  (208) (1,309) (40) (1,405)Cash flows from financing activities:         Non-bank debt:         Borrowings1,244  —  300  —  1,544 Repayments(33) (484) —  —  (517)Accounts receivable sales program:         Proceeds from the sale of receivables—  —  1,225  —  1,225 Repayments—  —  (1,325) —  (1,325)Purchase of common stock for treasury(13) —  —  —  (13)

Issuance of common stock in connection

  with stock-based compensation plans

20  —  —  —  20 Common stock dividends(114) —  —  —  (114)Capital contributions from parent—  —  120  (120) — Dividend to parent—  —  (124) 124  — Net intercompany borrowings—  2,255  (2,291) 36  — Other financing activities, net2  

—

  (6

)

 —  (4)

Net cash provided by (used in)

  financing activities

1,106  1,771  (2,101) 

40

  816 

Effect of foreign exchange rate

  changes on cash

—  —  53  —  53 

Net increase (decrease) in cash and

  temporary cash investments

1,945

  —  564  —  2,509 

Cash and temporary cash investments

  at beginning of year

78  —  747  —  825 

Cash and temporary cash investments

  at end of year

$2,023  $—  $1,311  $—  $3,334 

135

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2009

(in millions)

	Valero Energy Corporation			&n bsp;	PRG			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in)   operating activities	$	(526	)		$	(1,198	)	$	3,547		$	—		$	1,823
Cash flows f rom investing activities:
Capital expenditures	—				(526		)	(1,780		)	—			(2,306		)
Deferred turnaround and catalyst costs	—				(72		)	(343		)	—			(415		)
Acquisitions of ethanol plants	& mdash;				—			(556		)	—			(556		)
Advance payments related to acquisition   of ethanol facilities	—				—			(21		)	—			(21		)
Investments in subsidiaries	(2,335		)		(142		)	(2,121		)	4,598			—
Return of investment	109				—			—			(109		)	—
Net intercompany loan repayments	1,422				—			—			(1,422		)	—
Minor acquisition	—				—			(29		)	—			(29		)
Other investing activities, net	—				—			35			—			35
Net cash used in investing activities	(804		)		(740		)	(4,815		)	3,067			(3,292		)
Cash flows from financing activities:
Non-bank debt:
Borrowings	998				—			—			—			998
Repayments	(285		)		—			—			—			(285		)
Bank credit agreements:
Borrowings	39				—			—			—

  39 

Repayments

(39) —  —  —  (39)Accounts receivable sales program:         Proceeds from sale of receivables—  —  950  —  950 Repayments—  —  (850) —  (850)

Proceeds from the sale of common stock,

  net of issuance costs

799  —  —  —  799 Purchase of common stock for treasury(4) —  —  —  (4)Issuance of common stock in connection with stock-based compensation plans11  —  —  —  11 Common stock dividends(324) —  —  —  (324)Dividend to parent—  —  (109) 109  — Capital contributions from parent—  2,121  2,477  (4,598) — Net intercompany repayments— (183) (1,239) 1,422  — Other financing activities, net(2) —  (4) —  (6)

Net cash provided by financing

  activities

1,193  1,938  1,225  (3,067) 1,289 

Effect of foreign exc hange rate changes

  on cash

—  —  65  —  65

Net increase (decrease) in cash and

  temporary cash investments

(137) —  22  — (115)

Cash and temporary cash investments

  at beginning of year

215  —  725  —  940 

Cash and temporary cash investments

  at end of year

$78  $—  $747  $—  $825 

136

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINA NCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2008

(in millions)

	Valero Energy Corporation			PRG (1)				Other Non-Guarantor Subsidiaries (1)				Eliminations			Consolidated
Net cash provided by operating activities	$	46		$	14			$	3,035			$	—		$	3,095
Cash flows from investing activities:
Capital expenditures	—			(653		)		(2,240		)		—			(2,893		)
Deferred turnaround and catalyst costs	—			(93		)		(315		)		—			(408		)
Proceeds from the sale of the   Krotz Springs Refinery	—			—				463				—			463
Investments in subsidiaries	(1,235		)	—				(1,523		)		2,758			—
Return of investment	629			265			—				(894		)	—
Net intercompany loan repayments	596			—				—

 (596) — Minor acquisitions—  —  (144) —  (144)Other investing activities, net—  —  17  —  17 Net cash used in investing activities(10) (481) (3,742) 1,268  (2,965)Cash flows from financing activities:         Non-bank debt repayments(6) 

(368

) —  —  (374)Bank credit agreements:         Borrowings296  —  —  —  296 Repayments(296) —  —  —  (296)Purchase of common stock for treasury(955) —  —  —  (955)

Issuance of common stock in connection

  with stock-based compensation plans

16  —  —  —  16 Common stock dividends(299) —  — —  (299)Dividend to parent—&nb sp; —  (894) 894  — Capital contributions from parent—&nb sp; 1,523  1,235  (2,758) — 

Net intercompany borrowings

  (repayments)

—  (688) 92  596  — Other financing activities, net9  —  (4) —  5 

Net cash provided by (used in)

  financing activities

(1,235) 467  429  (1,268) (1,607)

Effect of foreign exchang e 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.

137

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

23.     QUARTERLY FINANCIAL DATA (Unaudited)

The following table summarizes quarterly financial data for the years ended December 31, 2010 and 2009 (in millions, except per share amounts). The amounts shown below differ from those previously reported in our quarterly reports on Form 10-Q for the quarters ended March 31, June 30, and September 30, 2010 due to the sale of the Paulsboro Refinery in December 2010 as discussed in Note 3. The results of operations of the Paulsboro Refinery have been presented as discontinued operations for all periods presented.

	2010 Quarter Ended
	March 31		June 30 (a)		September 30		December 31 (b)
Operating revenues	$	18,493	$	20,561	$	21,015	$	22,164
Operating income (loss)	4		904		590

 378 

Income (loss) from continuing

  operations

(80) 520  303  180 Net income (loss)(113) 583  292  (438)

Earnings (loss) per common share

  from continuing operations –

  assuming dilution

(0.14) 0.92  0.53  0.32 

Earnings (loss) per common share –

  assuming dilution

(0.20) 1.03  0.51  (0.77)      & nbsp;  2009 Quarter Ended March 31 June 30 September 30 December 31 (c)Operating revenues$12,590  $16,518  $17,607  $17,884 Operating income (loss)541  (130) (193) (135)

Income (loss) from continuing

  operations

331  (156) (317) (131)Net income (loss)309  (254) (629) (1,408)

Earnings (loss) per common share

  from continuing operations –

  assuming dilution

0.64  (0.30) (0.56) (0.23)

Earnings (loss) per common share –

  assuming dilution

0.59  (0.48) (1.12) (2.51)

______________

(a)     Net income for the quarter ended June 30, 2010 includes the $92 million pre-tax gain related to the sale of the Delaware City Refinery as discussed in Note 3.

(b)     Net loss for the quarter ended December 31, 2010 includes the $980 million pre-tax loss related to the sale of the Paulsboro Refinery as discussed in Note 3.

(c)     Net loss for the quarter ended December 31, 2009 includes the $1.9 billion pre-tax loss related to the shutdown of the Delaware City Refinery as discussed in Note 3.

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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, 2010.

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 55 of this report, and is incorporated herein by reference.

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

KPMG LLP’s report on Valero’s internal control over financial reporting appears in Item 8 beginning on page 57 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 financia l 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.

139

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 2011 annual meeting of stockholders. We will file the proxy statement with the SEC before March 31, 2011.

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 rep orting	55
Reports of independent registered public accounting firm	56
Consolidated balance sheets as of December 31, 2010 and 2009	59
Consolidated statements of income for the years ended December 31, 2010, 2009, and 2008	60
Consolidated statements of stockholders’ equity for the years ended December 31, 2010, 2009, and 2008	61
Consolidated statements of cash flows for the years ended December 31, 2010, 2009, and 2008	62
Consolidated statements of comprehensive income for the years ended December 31, 2010, 2009, and 2008	63
Notes to consolidated financial statements	64

2. Financial Statement Schedule s 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:

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).
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).

140

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 Ene rgy 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 date d 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 am ong 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 Dec ember 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 July 29, 2009 - incorporated by reference to Exhibit 10.01 to Valero’s Current Report on Form 8-K dated July 29, 2009, and filed August 4, 2009 (SEC File No. 1-13175).
+10.02	--	Valero Energy Corporation 2005 Omnibus Stock Incentive Plan, amended and restated as of October 1, 2005.
+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 - incorporated by reference to Exhibit 10.04 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2008 (SEC File No. 1-13175).
*+10.05	--	Form of 2010 Elective Deferral Agreement pursuant to the Valero Energy Corporation Deferred Compensation Plan.

141

*+10.06	--	Form of Investment Election Form pursuant to the Valero Energy Corporation Deferred Compensation Plan.
*+10.07	--	Form of 2010 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 - incorporated by reference to Exhibit 10.08 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2008 (SEC File No. 1-13175).
+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 - incorporated by reference to Exhibit 10.10 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2008 (SEC File No. 1-13175).
+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) - incorporated by reference to Exhibit 10.16 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2008 (SEC File No. 1-13175).
+10.17	--	Change of Control Agreement (Tier II) dated March 15, 2007 between Valero Energy Corporation and Kimberly S. Bowers - incorporated by reference to Exhibit 10.16 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2008 (SEC File No. 1-13175).
*+10.18	--	Form of Performance Award Agreement pursuant to the Valero Energy Corporation 2005 Omnibus Stock Incentive Plan.
+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 on Form 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).

142

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 - incorporated by reference to Exhibit 10.23 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2008 (SEC File No. 1-13175).
10.24	--	First Amendment to $2,500,000,000 5-Year Revolving Credit Agreement, dated as of July 24, 2006 - incorporated by reference to Exhibit 10.24 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2008 (SEC File No. 1-13175).
10 .25	--	Second Amendment to $2,500,000,000 5-Year Revolving Credit Agreement, dated as of November 9, 2007 - incorporated by reference to Exhibit 10.25 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2008 (SEC File No. 1-13175).
*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 25, 2011.
*24.01	--	Power of Attorney dated February 24, 2011 (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.
		&n bsp;
*32.01	--	Section 1350 Certifications (under Section 906 of the Sarbanes-Oxley Act of 2002).
*99.01	--	Audit Committee Pre-Approval Policy.
**101	--	The following materials from Valero Energy Corporation’s Form 10-K for the year ended December 31, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statements of Other Comprehensive Income, and (vi) Notes to Consolidated Financial Statements, tagged in detail.

______________

*    Filed herewith.

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

**    Submitted electronically herewith.

In accordance with Rule 402 of Regulation S-T, the XBRL information in Exhibit 101 to this Annual Report on Form 10-K shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

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 r elating to debt not exceeding 10 percent of the total assets of the registrant and its subsidiaries on a consolidated basis.

143

SIGNATURE

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 25, 2011

144

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.

/s/ Michael S. Ciskowski

Signature		Title		Date
/s/ William R. Klesse		Chief Executive Officer, President, and Chairman of the Board (Principal Executive Officer)		February 24, 2011
(William R. Klesse)
	Executive Vice President  and Chief Financial Officer (Principal Financial and Accounting Officer)		February 24, 2011
(Michael S. Ciskowski)
/s/ Ronald K. Calgaard		Director		February 24, 2011
(Ronald K. Calgaard)
/s/ Jerry D. Choate		Director		February 24, 2011
(Jerry D. Choate)
/s/ Ruben M. Escobedo		Director		February 24, 2011
(Ruben M. Escobedo)
/s/ Bob Marbut		Director		February 24, 2011
(Bob Marbut)
/s/ Donald L. Nickles		Director		Februar y 24, 2011
(Donald L. Nickles)
/s/ Robert A. Profusek		Director		February 24, 2011
(Robert A. Profusek)
/s/ Susan Kaufman Purcell		Director		February 24, 2011
(Susan Kaufman Purcell)
/s/ Stephen M. Waters		Director		February 24, 2011
(Stephen M. Waters)
/s/ Randall J. Weisenburger		Director		February 24, 2011
(Randall J. Weisenburger)
/s/ Rayford Wilkins, Jr.		Director		February 24, 2011
(Rayford Wilkins, Jr.)			&nbs p;

145