Form 10-K

10-K 1 d10k.htm FORM 10-K Form 10-K

FORM 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(Mark One)

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

For the fiscal year ended December 31, 2006

¨	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 incorporation or organization)		(I.R.S. Employer Identification No.)


One Valero Way San Antonio, Texas		78249
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (210) 345-2000

Securities registered pursuant to Section 12(b) of the Act: Common stock, $0.01 par value per share, and

Preferred Share Purchase Rights, listed on the New York Stock Exchange.

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule12b-2 of the Exchange Act).

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

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

The aggregate market value of the voting and non-voting common stock held by non-affiliates was approximately $40.5 billion based on the last sales price quoted as of June 30, 2006 on the New York Stock Exchange, the last business day of the registrant’s most recently completed second fiscal quarter.

As of January 31, 2007, 604,114,047 shares of the registrant’s common stock were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

We intend to file with the Securities and Exchange Commission before March 31, 2007 a definitive Proxy Statement for our Annual Meeting of Stockholders scheduled for April 26, 2007, at which our directors will be elected. Portions of the 2007 Proxy Statement are incorporated by reference in Part III of this Form 10-K and are deemed to be a part of this report.

CROSS-REFERENCE SHEET

The following table indicates the headings in the 2007 Proxy Statement where certain information required in Part III of Form 10-K may be found.


Form 10-K Item No. and Caption		Heading in 2007 Proxy Statement
10. Directors, Executive Officers and Corporate Governance		Information Regarding the Board of Directors, Independent Directors, Audit Committee, Code of Ethics for Senior Financial Officers, Proposal No. 1 Election of Directors, Information Concerning Nominees and Other Directors, and Section 16(a) Beneficial Ownership Reporting Compliance

11. Executive Compensation		Compensation Committee, Compensation Discussion and Analysis, Compensation of Directors, 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 LLP Fees for Fiscal Years 2006 and 2005 and Audit Committee Pre-Approval Policy

Copies of all documents incorporated by reference, other than exhibits to such documents, will be provided without charge to each person who receives a copy of this Form 10-K upon written request to Jay D. Browning, Senior Vice President and Corporate Secretary, Valero Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-6000.

CONTENTS


		PAGE
PART I
Items 1., 1A. & 2.	Business, Risk Factors and Properties	1
	Recent Developments	2
	Segments	2
	Valero’s Operations	3
	Risk Factors	12
	Environmental Matters	14
	Properties	14
	Executive Officers of the Registrant	15
Item 1B.	Unresolved Staff Comments	16
Item 3.	Legal Proceedings	16
Item 4.	Submission of Matters to a Vote of Security Holders	17

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	18
Item 6.	Selected Financial Data	21
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 8.	Financial Statements and Supplementary Data	52
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	130
Item 9A.	Controls and Procedures	130
Item 9B.	Other Information	130

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	131
Item 11.	Executive Compensation	131
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	131
Item 13.	Certain Relationships and Related Transactions, and Director Independence	131
Item 14.	Principal Accountant Fees and Services	131

PART IV
Item 15.	Exhibits and Financial Statement Schedules	131

Signatures		137

iii

PART I

Unless otherwise indicated, the terms “Valero,” “we,” “our,” and “us” are used in this report to refer to Valero Energy Corporation, to one or more of our consolidated subsidiaries, or to all of them taken as a whole. In the following Items 1, 1A and 2, “Business, Risk Factors and Properties,” we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources, that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The words “forecasts,” “intends,” “believes,” “expects,” “plans,” “scheduled,” “goal,” “may,” “anticipates,” “estimates,” and similar expressions identify forward-looking statements. We do not undertake to update, revise, or correct any of the forward-looking information. Our forward-looking statements should be read in conjunction with our disclosures beginning on page 22 of this report under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.”

ITEMS 1., 1A. and 2. BUSINESS, RISK FACTORS AND PROPERTIES

Overview. We are a Fortune 500 company based in San Antonio, Texas. Our principal executive offices are at One Valero Way, San Antonio, Texas, 78249, and our telephone number is (210) 345-2000. Our common stock trades on the New York Stock Exchange under the symbol “VLO.” We were incorporated in Delaware in 1981 under the name Valero Refining and Marketing Company; our name was changed to Valero Energy Corporation on August 1, 1997. On January 31, 2007, we had 21,836 employees.

We own and operate 18 refineries located in the United States, Canada, and Aruba that produce premium, environmentally clean refined products such as RBOB¹, gasoline meeting the specifications of the California Air Resources Board (CARB), CARB diesel fuel, low-sulfur and ultra-low-sulfur diesel fuel, and oxygenates (liquid hydrocarbon compounds containing oxygen). We also produce conventional gasolines, distillates, jet fuel, asphalt, petrochemicals, lubricants, and other refined products.

We market branded and unbranded refined products on a wholesale basis in the United States and Canada through an extensive bulk and rack marketing network. We also sell refined products through a network of approximately 5,800 retail and wholesale branded outlets in the United States, Canada, and Aruba.

Available Information. Our internet website address is http://www.valero.com. Information contained on our website is not part of this annual report on Form 10-K. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K filed with (or furnished to) the Securities and Exchange Commission (SEC) are available on our internet website (in the “Investor Relations” section), free of charge, as soon as reasonably practicable after we file or furnish such material. We also post our corporate governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers, and the charters of the committees of our board of directors in the same website location. Our governance documents are available in print to any stockholder that makes a written request to Jay D. Browning, Senior Vice President and Corporate Secretary, Valero Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-6000.

¹	RBOB is a base unfinished reformulated gasoline mixture known as “reformulated gasoline blendstock for oxygenate blending” or “RBOB.”

RECENT DEVELOPMENTS

In 2006, we sold all of our ownership interest in Valero GP Holdings, LLC (NYSE: VEH), the general partner of Valero L.P. Valero L.P. is a publicly traded master limited partnership (NYSE: VLI) which owns and operates crude oil and refined product pipeline, terminalling, and storage tank assets. The sale of our interest in Valero GP Holdings, LLC is more fully described in Note 9 of Notes to Consolidated Financial Statements, and we hereby incorporate by reference into this Item our disclosures made in Note 9.

SEGMENTS

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

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

VALERO’S OPERATIONS

REFINING

On December 31, 2006, our refining operations included 18 refineries in the United States, Canada, and Aruba with a combined total throughput capacity of approximately 3.3 million barrels per day (BPD). The following table presents the locations of these refineries and their feedstock throughput capacities. These capacities exclude any throughput enhancements completed after December 31, 2006.


As of December 31, 2006
Refinery	Location	Throughput Capacity ^(a) (barrels per day)
Gulf Coast:
Corpus Christi ^(b)	Texas	340,000
Port Arthur	Texas	295,000
Aruba	Aruba	275,000
St. Charles	Louisiana	250,000
Texas City	Texas	245,000
Houston	Texas	130,000
Three Rivers	Texas	100,000
Krotz Springs	Louisiana	85,000

		1,720,000

West Coast:
Benicia	California	170,000
Wilmington	California	135,000

		305,000

Mid-Continent:
Memphis	Tennessee	195,000
McKee	Texas	170,000
Lima	Ohio	160,000
Ardmore	Oklahoma	90,000

		615,000

Northeast:
Quebec City	Quebec, Canada	215,000
Delaware City	Delaware	210,000
Paulsboro	New Jersey	195,000

		620,000

Total		3,260,000

(a)	“Throughput capacity” represents processed crude oil, intermediates, and other feedstocks. Total crude oil capacity is approximately 2.8 million BPD.

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

We process a wide slate of feedstocks, including sour crude oils, intermediates, and residual fuel oil (resid) which can typically be purchased at differentials below West Texas Intermediate, a benchmark crude oil. In 2006, sour crude oils, acidic sweet crude oils, and resid represented 55% of our throughput volumes, sweet crude oils represented 30%, and the remaining 15% was composed of blendstocks and other feedstocks. Our ability to process significant amounts of sour crude oils enhances our competitive position in the industry relative to refiners that process primarily sweet crude oils because sour crude oils typically can be purchased at differentials below sweet crude oils.

In 2006, gasolines and blendstocks represented 48% of our refined product slate; distillates – such as home heating oil, diesel fuel, and jet fuel – represented 32%; petrochemicals represented 3%; and asphalt, lubricants, gas oils, No. 6 fuel oil, petroleum coke, and other products comprised the remaining 17%.

GULF COAST

The following table presents the percentages of principal charges and yields (on a combined basis) for the nine refineries in this region for the year ended December 31, 2006. Total throughput volumes for the Gulf Coast refining region averaged 1,532,000 BPD for the twelve months ended December 31, 2006.

Combined Gulf Coast Region Charges and Yields

Fiscal 2006 Actual


	Percentage
Charges:
sour crude oil	53	%
high-acid sweet crude oil	1	%
sweet crude oil	16	%
residual fuel oil	14	%
other feedstocks	5	%
blendstocks	11	%
Yields:
gasolines and blendstocks	45	%
distillates	31	%
petrochemicals	4	%
other products (includes vacuum gas oil, No. 6 fuel oil, petroleum coke, asphalt, and other)	20	%

Corpus Christi East and West Refineries. Our Corpus Christi East and West Refineries are located along the Corpus Christi Ship Channel on the Texas Gulf Coast. The West Refinery specializes in processing primarily lower-cost sour crude oil and resid into premium products such as RBOB. The East Refinery processes heavy, high-sulfur crude oil into conventional gasoline, diesel, jet fuel, asphalt, aromatics, and other light products. We have operated the East Refinery since 2001 and have substantially integrated the operations of the West and East Refineries, allowing for the transfer of various feedstocks and blending components between the two refineries and the sharing of resources. The refineries typically receive and deliver feedstocks and products by tanker and barge via deepwater docking facilities along the Corpus Christi Ship Channel. Three truck racks with a total of 16 bays service local markets for gasoline, diesel, jet fuels, LPG’s, and asphalt. The refineries distribute refined products using the Colonial, Explorer, Valley, and other major pipelines.

Port Arthur Refinery. Our Port Arthur Refinery is located on the Texas Gulf Coast approximately 90 miles east of Houston. The refinery processes primarily heavy sour crude oils and other feedstocks into conventional and premium gasoline and RBOB, as well as diesel, jet fuel, petrochemicals, petroleum coke, and sulfur. The refinery receives crude oil over marine docks and has access to the Sunoco and Oiltanking terminals at Nederland, Texas. Finished products are distributed into the Colonial, Explorer, and TEPPCO pipelines or across the refinery docks into ships or barges. The refinery also has convenient truck-rack access.

Aruba Refinery. Our Aruba Refinery is located on the island of Aruba in the Caribbean Sea. It processes primarily heavy sour crude oil and produces primarily intermediate feedstocks and finished distillate products. Significant amounts of the refinery’s intermediate feedstock production are transported and further processed in our other refineries in the Gulf Coast, West Coast, and Northeast regions. The refinery receives crude oil by ship at its two deepwater marine docks which can berth ultra-large crude carriers. The refinery’s products are delivered by ship primarily into markets in the U.S. Gulf Coast, Florida, the New York Harbor, the Caribbean, and Europe.

St. Charles Refinery. Our St. Charles Refinery is located approximately 15 miles from New Orleans along the Mississippi River. The refinery processes sour crude oils and other feedstocks into gasoline, distillates, and other light products. The refinery receives crude oil over five marine docks and has access to the Louisiana Offshore Oil Port where it can receive crude oil through a 24-inch pipeline. Finished products can be shipped over these docks or by pipeline into either the Plantation or Colonial pipeline network for distribution to the eastern United States.

Texas City Refinery. Our Texas City Refinery is located southeast of Houston on the Texas City Ship Channel. The refinery processes primarily heavy sour crude oils into a wide slate of products. The refinery receives and delivers its feedstocks and products by tanker and barge via deepwater docking facilities along the Texas City Ship Channel and uses the Colonial, Explorer, and TEPPCO pipelines for distribution of its products.

Houston Refinery. Our Houston Refinery is located on the Houston Ship Channel. It processes primarily sour crude oils and low-sulfur resid into conventional gasoline and distillates. The refinery also produces roofing-grade asphalt. The refinery receives its feedstocks via tanker at deepwater docking facilities along the Houston Ship Channel and delivers its products through major refined-product pipelines, including the Colonial, Explorer, and TEPPCO pipelines.

Three Rivers Refinery. Our Three Rivers Refinery is located in South Texas between Corpus Christi and San Antonio. It processes primarily heavy sweet and sour crude oils into conventional gasoline and distillates. The refinery has access to crude oil from foreign sources delivered to the Texas Gulf Coast at Corpus Christi as well as crude oil from domestic sources through third-party pipelines. A 70-mile pipeline that can deliver 120,000 BPD of crude oil connects the Three Rivers Refinery to Corpus Christi. The refinery distributes its refined products primarily through pipelines owned by Valero L.P.

Krotz Springs Refinery. Our Krotz Springs Refinery is located between Baton Rouge and Lafayette, Louisiana on the Atchafalaya River. It processes light sweet crude oils (received by pipeline and barge) into conventional gasoline and distillates. The refinery’s location provides access to upriver markets on the Mississippi River, and its docking facilities along the Atchafalaya River are sufficiently deep to allow barge access. The facility also uses the Colonial pipeline to transport products to markets in the southeastern and northeastern United States.

WEST COAST

The following table presents the percentages of principal charges and yields (on a combined basis) for the two refineries in this region for the year ended December 31, 2006. Total throughput volumes for the West Coast refining region averaged approximately 305,000 BPD for the twelve months ended December 31, 2006.

Combined West Coast Region Charges and Yields

Fiscal 2006 Actual


	Percentage
Charges:
sour crude oil	68	%
high-acid sweet crude oil	2	%
sweet crude oil	1	%
other feedstocks	12	%
blendstocks	17	%
Yields:
gasolines and blendstocks	63	%
distillates	21	%
other products (includes vacuum gas oil, No. 6 fuel oil, petroleum coke, asphalt, and other)	16	%

Benicia Refinery. Our Benicia Refinery is located northeast of San Francisco on the Carquinez Straits of San Francisco Bay. It processes sour crude oils into premium products, primarily CARBOB gasoline. (CARBOB is a reformulated gasoline mixture that meets the specifications of the California Air Resources Board when blended with ethanol.) The refinery receives crude oil supplies via a deepwater dock that can berth large crude oil carriers and a 20-inch crude oil pipeline connected to a southern California crude oil delivery system. Most of the refinery’s products are distributed via the Kinder Morgan pipeline in California.

Wilmington Refinery. Our Wilmington Refinery is located near Los Angeles, California. The refinery processes a blend of lower-cost heavy and high-sulfur crude oils. The refinery can produce all of its gasoline as CARBOB gasoline and produces both ultra-low-sulfur diesel and CARB diesel. The refinery is connected by pipeline to marine terminals and associated dock facilities that can move and store crude oil and other feedstocks. Refined products are distributed via the Kinder Morgan pipeline system and various third-party terminals in southern California, Nevada, and Arizona.

MID-CONTINENT

The following table presents the percentages of principal charges and yields (on a combined basis) for the four refineries in this region for the year ended December 31, 2006. Total throughput volumes for the Mid-Continent refining region averaged 559,000 BPD for the twelve months ended December 31, 2006.

Combined Mid-Continent Region Charges and Yields

Fiscal 2006 Actual


	Percentage
Charges:
sour crude oil	6	%
sweet crude oil	86	%
other feedstocks	1	%
blendstocks	7	%
Yields:
gasolines and blendstocks	53	%
distillates	34	%
petrochemicals	4	%
other products (includes vacuum gas oil, No. 6 fuel oil, petroleum coke, asphalt, and other)	9	%

Memphis Refinery. Our Memphis Refinery is located in Tennessee along the Mississippi River’s Lake McKellar. It processes primarily light sweet crude oils. Almost all of its production is light products, including regular and premium gasoline, diesel, jet fuels, and petrochemicals. Crude oil is supplied to the refinery via the Capline Pipeline and can also be received, along with other feedstocks, via barge. The refinery’s products are distributed via truck racks at our three product terminals, barges, and a pipeline directly to the Memphis airport.

McKee Refinery. Our McKee Refinery is located in the Texas Panhandle. It processes primarily sweet crude oils and produces conventional gasoline, RBOB, low-sulfur diesel, jet fuels, and asphalt. The refinery has access to crude oil from Texas, Oklahoma, Kansas, and Colorado through third-party pipelines. The refinery also has access at Wichita Falls, Texas to third-party pipelines that transport crude oil from the Texas Gulf Coast and West Texas to the Mid-Continent region. The refinery distributes its products primarily via Valero L.P.’s pipelines to markets in Texas, New Mexico, Arizona, Colorado, and Oklahoma.

Lima Refinery. Our Lima Refinery is located in Ohio between Toledo and Dayton. It currently processes primarily light sweet crude oils. The refinery produces conventional gasoline, RBOB, diesel, jet fuels, and petrochemicals. Crude oils are delivered to the refinery through the Mid-Valley and Marathon pipelines. The refinery’s products are distributed through the Buckeye and Inland pipeline systems and by rail and truck to markets in Ohio, Indiana, Illinois, Michigan, and western Pennsylvania.

Ardmore Refinery. Our Ardmore Refinery is located in Ardmore, Oklahoma, approximately 90 miles from Oklahoma City. It processes medium sour and light sweet crude oils into conventional gasoline, low-sulfur diesel, and asphalt. Crude oil is delivered to the refinery through Valero L.P.’s crude oil gathering and trunkline systems, other third-party pipelines, and trucking operations. Refined products are transported via pipelines, railcars, and trucks.

NORTHEAST

The following table presents the percentages of principal charges and yields (on a combined basis) for the three refineries in this region for the year ended December 31, 2006. Total throughput volumes for the Northeast refining region averaged 563,000 BPD for the twelve months ended December 31, 2006.

Combined Northeast Region Charges and Yields

Fiscal 2006 Actual


	Percentage
Charges:
sour crude oil	47	%
high-acid sweet crude oil	9	%
sweet crude oil	29	%
residual fuel oil	4	%
other feedstocks	3	%
blendstocks	8	%
Yields:
gasolines and blendstocks	44	%
distillates	38	%
petrochemicals	1	%
other products (includes vacuum gas oil, No. 6 fuel oil, petroleum coke, asphalt, and other)	17	%

Quebec City Refinery. Our Quebec City Refinery is located in Lévis, Canada (near Quebec City). It processes sweet crude oils and lower-quality, sweet acidic crude oils into conventional gasoline, low-sulfur diesel, jet fuels, heating oil, and propane. The refinery receives crude oil by ship at its deepwater dock on the St. Lawrence River. We charter large ice-strengthened, double-hulled crude oil tankers that can navigate the St. Lawrence River year-round. The refinery transports its products to its primary terminals in Quebec and Ontario primarily by train, and also uses ships and trucks extensively throughout eastern Canada.

Delaware City Refinery. Our Delaware City Refinery is located along the Delaware River near Wilmington, Delaware. The refinery processes primarily sour crude oils into a wide slate of products including conventional gasoline, RBOB, petroleum coke, sulfur, low-sulfur diesel, and home heating oil. Feedstocks and refined products are transported via pipeline, barge, and truck-rack facilities. The refinery’s production is sold primarily in the U.S. Northeast.

Paulsboro Refinery. Our Paulsboro Refinery is located in Paulsboro, New Jersey, approximately 15 miles south of Philadelphia on the Delaware River. The refinery processes primarily sour crude oils into a wide slate of products including gasoline, distillates, lube oil basestocks, asphalt, petroleum coke, sulfur, and fuel oil. Feedstocks and refined products are typically transported by tanker and barge via refinery-owned dock facilities along the Delaware River, Buckeye Partners’ product distribution system, an onsite truck rack owned by Valero L.P., railcars, and the Colonial pipeline, which allows products to be sold into the New York Harbor market.

FEEDSTOCK SUPPLY

Approximately 65% of our current crude oil feedstock requirements are purchased through term contracts while the remaining requirements are generally purchased on the spot market. Our term supply agreements include arrangements to purchase feedstocks at market-related prices directly or indirectly from various foreign national oil companies (including feedstocks originating in Saudi Arabia, Mexico, Iraq, Kuwait, Venezuela, Colombia, and Africa) as well as international and domestic oil companies. About 75% of these crude oil feedstocks are imported from foreign sources and about 25% are domestic. In the event we become unable to purchase crude oil from any one of these sources, we believe that adequate alternative supplies of crude oil would be available.

The U.S. network of crude oil pipelines and terminals allows us to acquire crude oil from producing leases, domestic crude oil trading centers, and ships delivering cargoes of foreign and domestic crude oil. Our Quebec City and Aruba Refineries rely on foreign crude oil that is delivered to the refineries’ dock facilities by ship. We use the futures market to manage a portion of the price risk inherent in purchasing crude oil in advance of our delivery date and holding inventories of crude oils and refined products.

REFINING SEGMENT SALES

Our refining segment includes sales of refined products in both the wholesale rack and bulk markets. These sales include refined products that are manufactured in our refining operations as well as refined products purchased or received on exchange from third parties. Most of our refineries have access to deepwater transportation facilities and interconnect with common-carrier pipeline systems, allowing us to sell products in most major geographic regions of the United States and eastern Canada. No customer accounted for more than 10% of our total operating revenues in 2006.

Wholesale Marketing

We market branded and unbranded transportation fuels on a wholesale basis in about 40 states through an extensive rack marketing network. The principal purchasers of our transportation fuels from terminal truck racks are wholesalers, distributors, retailers, and truck-delivered end users throughout the United States.

The majority of our rack volumes are sold through unbranded channels. The remainder is sold to distributors and dealers that are members of the Valero-brand family that operate approximately 3,850 branded sites. These sites are independently owned and are supplied by us under multi-year contracts. For wholesale branded sites, we promote our Valero^{^®} and Beacon^{^®} brands in California. Elsewhere in the United States, we promote our Valero^{^®} and Shamrock^{^®} brands, and we are in the process of converting our Diamond Shamrock^{^®} branded sites to the Valero^{^®} brand.

We also sell a variety of other products produced at our refineries including asphalt, lube base oils, petroleum coke, and sulfur. These products are transported via pipelines, barges, trucks, and railcars. We produce approximately 60,000 BPD of asphalt which is sold to customers in the paving and roofing industries. We are the second largest producer of asphalt in the United States. We produce asphalt at seven refineries and market asphalt in 20 states through 15 terminal facilities. We also produce packaged roofing products at four manufacturing facilities, and modified paving asphalts at nine polymer modifying plants. We are the largest producer of petroleum coke in the United States, supplying primarily power generation customers and cement manufacturers. We are also one of the largest producers of sulfur in the United States with sales primarily to customers in the agricultural sector.

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

Bulk Sales and Trading

We sell a significant portion of our gasoline and distillate production through bulk sales channels. Our bulk sales are made to various oil companies and traders as well as certain bulk end-users such as railroads, airlines, and utilities. Our bulk sales are transported primarily by pipeline, barges, and tankers to major tank farms and trading hubs.

We also enter into refined product exchange and purchase agreements. These agreements help to minimize transportation costs, optimize refinery utilization, balance refined product availability, broaden geographic distribution, and make sales to markets not connected to our refined product pipeline systems. Exchange agreements provide for the delivery of refined products by us to unaffiliated companies at our and third parties’ terminals in exchange for delivery of a similar amount of refined products to us by these unaffiliated companies at specified locations. Purchase agreements involve our purchase of refined products from third parties with delivery occurring at specified locations.

RETAIL

Our retail segment operations include the following:

•

sales of transportation fuels at retail stores and unattended self-service cardlocks,

•

sales of convenience store merchandise in retail stores, and

•

sales of home heating oil to residential customers.

We are one of the largest independent retailers of refined products in the central and southwest United States and eastern Canada. Our retail operations are supported by our proprietary credit card program which had approximately 700,000 accounts as of December 31, 2006. Our retail operations are segregated geographically into two groups: Retail-U.S. and Retail-Canada.

RETAIL-U.S.

Sales in Retail-U.S. represent sales of transportation fuels and convenience store merchandise through our company-operated retail sites. For the year ended December 31, 2006, total sales of refined products through Retail-U.S.’s retail sites averaged approximately 116,600 BPD. In addition to transportation fuels, our company-operated convenience stores sell snacks, candy, beer, fast foods, cigarettes, and fountain drinks. On December 31, 2006, we had 967 company-operated sites in Retail-U.S. (of which approximately 75% were owned and 25% were leased). Our company-operated stores are operated primarily under the brand names Corner Store^{^®} and Stop N Go^{^®}. Transportation fuels sold in our Retail-U.S. stores are sold primarily under the Valero^{^®} brand, with some sites selling under the Diamond Shamrock^{^®} brand pending their conversion to the Valero^{^®} brand.

RETAIL-CANADA

Sales in Retail-Canada include the following:

•

sales of refined products and convenience store merchandise through our company-operated retail sites and cardlocks,

•

sales of refined products through sites owned by independent dealers and jobbers, and

•

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, 2006, total retail sales of refined products through Retail-Canada averaged approximately 75,600 BPD. Transportation fuels are sold under the Ultramar^{^®} brand through a network of 956 outlets throughout eastern Canada. On December 31, 2006, we owned or leased 446 retail stores in Retail-Canada and distributed gasoline to 510 dealers and independent jobbers. In addition, Retail-Canada operates 89 cardlocks, which are card- or key-activated, self-service, unattended stations that allow commercial, trucking, and governmental fleets to buy transportation fuel 24 hours a day. Retail-Canada operations also include a large home heating oil business that provides home heating oil to approximately 151,000 households in eastern Canada. Our home heating oil business tends to be seasonal to the extent of increased demand for home heating oil during the winter.

RISK FACTORS

Our financial results are affected by volatile refining margins.

Our financial results are primarily affected by the relationship, or margin, between refined product prices and the prices for crude oil and other feedstocks. Our cost to acquire feedstocks and the price at which we can ultimately sell refined products depend upon numerous factors beyond our control, including regional and global supply of and demand for crude oil, gasoline, diesel, and other feedstocks and refined products. These in turn are dependent upon, among other things, the availability and quantity of imports, the production levels of domestic and foreign suppliers, levels of refined product inventories, U.S. relationships with foreign governments, political affairs, and the extent of governmental regulation.

Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Earnings on a diluted basis for 2004, 2005, and 2006 were $3.27 per share, $6.10 per share, and $8.64 per share, respectively. Refining margins were a significant contributing factor to the increase in our earnings between 2004 and 2006. The increase in our earnings for these periods is more fully described in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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

The principal environmental risks associated with our operations are emissions into the air and releases into the soil, surface water, or groundwater. Our operations are subject to extensive federal, state, and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasoline and diesel fuels. If we violate or fail to comply with these laws and regulations, we could be fined or otherwise sanctioned. Because environmental laws and regulations are becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, such as those relating to greenhouse gas emissions and climate change (e.g., California’s AB-32 “Global Warming Solutions Act”), the level of expenditures required for environmental matters could increase in the future. Future legislative action and regulatory initiatives could result in changes to operating permits, additional remedial actions, or increased capital expenditures and operating costs that cannot be assessed with certainty at this time. In addition, any major upgrades in any of our refineries could require material additional expenditures to comply with environmental laws and regulations.

Disruption of our ability to obtain crude oil could adversely affect our operations.

A significant portion of our feedstock requirements is satisfied through supplies originating in Saudi Arabia, Mexico, Iraq, Kuwait, Venezuela, Colombia, and Africa. We are, therefore, subject to the political, geographic, and economic risks attendant to doing business with suppliers located in, and supplies originating from, those areas. If one or more of our supply contracts were terminated, or if political events disrupt our traditional crude oil supply, we believe that adequate alternative supplies of crude oil would be available, but it is possible that we would be unable to find alternative sources of supply. If we are unable to obtain adequate crude oil volumes or are able to obtain such volumes only at unfavorable prices, our results of operations could be materially adversely affected, including reduced sales volumes of refined products or reduced margins as a result of higher crude oil costs.

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

The refining and marketing industry is highly competitive with respect to both feedstock supply and refined product markets. We compete with numerous other companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. We do not produce any of our crude oil feedstocks. Many of our competitors, however, obtain a significant portion of their feedstocks from company-owned production and some have more extensive retail outlets than we have. Competitors that have their own production or extensive retail outlets (and greater brand-name recognition) are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.

Some of our competitors also have materially greater financial and other resources than we have. Such competitors have a greater ability to bear the economic risks inherent in all phases of our industry. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial, and individual consumers.

A significant interruption in one or more of our refineries could adversely affect our business.

Our refineries are our principal operating assets. As a result, our operations could be subject to significant interruption if one or more of our refineries were to experience a major accident, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs.

Our operations expose us to many operating risks, not all of which are insured.

Our refining and marketing operations are subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards, and uncontrollable flows of oil and gas. They are also subject to the additional hazards of loss from severe weather conditions. As protection against operating hazards, we maintain insurance coverage against some, but not all, such potential losses. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.

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

ENVIRONMENTAL MATTERS

We hereby incorporate by reference into this Item the environmental disclosures contained in the following sections of this report:

•

Item 1 under the caption “Risk Factors – Compliance with and changes in environmental laws could adversely affect our performance,”

•

Item 3 “Legal Proceedings” under the caption “Environmental Enforcement Matters,” and

•

Item 8 “Financial Statements” in Note 24 of Notes to Consolidated Financial Statements.

Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2006, our capital expenditures attributable to compliance with environmental regulations were approximately $1.6 billion, and are currently estimated to be approximately $800 million for 2007 and approximately $450 million for 2008. (The estimates for 2007 and 2008 do not include amounts related to capital investments at our facilities that management has deemed to be strategic investments rather than expenditures relating to environmental regulatory compliance.) Of the foregoing amounts, our capital expenditures attributable to compliance with the Environmental Protection Agency’s Tier II gasoline and diesel standards were approximately $990 million in 2006, and are currently estimated to be approximately $380 million for 2007 and approximately $70 million for 2008.

PROPERTIES

Our principal properties are described above under the caption “Valero’s Operations,” and that information is incorporated herein by reference. We also own feedstock and refined product storage facilities in various locations. We believe that our properties and facilities are generally adequate for our operations and that our facilities are maintained in a good state of repair. As of December 31, 2006, we were the lessee under a number of cancelable and non-cancelable leases for certain properties. Our leases are discussed more fully in Note 23 of Notes to Consolidated Financial Statements.

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


EXECUTIVE OFFICERS OF THE REGISTRANT
Name	Age*	Positions Held with Valero	Officer Since
William R. Klesse	60	Chief Executive Officer and Chairman of the Board	2001
Gregory C. King	46	President	1997
Michael S. Ciskowski	49	Executive Vice President and Chief Financial Officer	1998
S. Eugene Edwards	50	Executive Vice President - Corporate Development and Strategic Planning	1998
Joseph W. Gorder	49	Executive Vice President - Marketing and Supply	2003
Richard J. Marcogliese	54	Executive Vice President - Operations	2001

*	on January 31, 2007

Mr. Klesse was elected as Valero’s Chairman of the Board on January 18, 2007, and as Chief Executive Officer on December 31, 2005. He was Valero’s Vice-Chairman of the Board from October 31, 2005 to January 18, 2007. He previously served as Executive Vice President and Chief Operating Officer since January 2003. He served as an Executive Vice President of Valero since the closing of our acquisition of Ultramar Diamond Shamrock Corporation (UDS) on December 31, 2001.

Mr. King was elected President in January 2003. He previously served as Executive Vice President and General Counsel since September 2001, and prior to that served as Executive Vice President and Chief Operating Officer since January 2001. Mr. King was Senior Vice President and Chief Operating Officer from 1999 to January 2001.

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

Mr. Edwards was elected Executive Vice President - Corporate Development and Strategic Planning in December 2005. Prior to that he had served as a Senior Vice President of Valero since December 2001 with responsibilities for product supply, trading, and wholesale marketing. He was first elected Vice President in 1998. He has held several positions in the company with responsibility for planning and economics, business development, risk management, and marketing.

Mr. Gorder was elected Executive Vice President – Marketing and Supply in December 2005. He had previously served as Senior Vice President – Corporate Development since August 2003. Prior to that he held several positions with Valero and UDS with responsibilities for corporate development and marketing. From October 2000 to May 2002, Mr. Gorder was Executive Vice President and Chief Financial Officer of Calling Solutions, Inc., a telecommunications and customer service provider.

Mr. Marcogliese was elected Executive Vice President - Operations in December 2005. He had previously served as Senior Vice President overseeing refining operations since July 2001. He joined Valero from Exxon Mobil Corporation in May 2000 as the Vice President and General Manager of our Benicia Refinery. He then transferred to our corporate office in June 2001 as head of Strategic Planning.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 3.

LEGAL PROCEEDINGS

Litigation

For the legal proceedings listed below, we hereby incorporate by reference into this Item our disclosures made in Part II, Item 8 of this report included in Note 25 of Notes to Consolidated Financial Statements under the caption “Litigation Matters.”

•

MTBE Litigation

•

Retail Fuel Temperature Litigation

•

Other Litigation

Environmental Enforcement Matters

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

United States Environmental Protection Agency (EPA) Region III, Notice of Non-Compliance/Request to Show Cause, CAA-III-05-008 (December 15, 2005) (Delaware City Refinery). The EPA issued a notice of non-compliance (NON) alleging failure to comply with EPA’s benzene waste NESHAP rule at the Delaware City Refinery for 2004 and 2005. The NON contains a proposed penalty of $130,000 (for which a prior owner of the refinery has agreed to indemnify us).

United States Environmental Protection Agency Region V, Notice of Violation and Finding of Violation EPA-5-05-OH-16 (June 28, 2005) (Lima Refinery). The EPA issued a notice and finding of violation (NOV) relating to an inspection that occurred at the Lima Refinery in October and November 2001. The NOV cites alleged violations under leak detection and repair regulations and tank floating roof regulations. The NOV does not specify any remedy sought by the EPA.

United States Environmental Protection Agency, Region VI, Notice of Violation (June 15, 2005) (Port Arthur Refinery). The EPA issued a notice and finding of violation concerning past flaring issues at the Port Arthur Refinery that occurred prior to our Premcor Acquisition. The EPA subsequently proposed a penalty of $8 million.

Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery). In 2005, the BAAQMD issued 27 violation notices (VNs) for various incidents at our Benicia Refinery and asphalt plant, including alleged excess emissions, recordkeeping discrepancies, and other matters. No penalties have been assessed for the VNs. We are negotiating a settlement with the BAAQMD for these matters. In 2006, the BAAQMD issued an additional 23 VNs for these facilities containing allegations similar to the 2005 VNs. We also plan to pursue settlement of the 2006 VNs.

Delaware Department of Natural Resources and Environmental Control (DDNREC) (Delaware City Refinery). Our Delaware City Refinery is subject to six outstanding notices of violation relating to alleged excess air emissions at the refinery. We have additionally self-reported other known noncompliance issues with air regulations at the refinery in connection with our attempt to settle all potential air-regulation violations with the DDNREC. The DDNREC’s initial penalty demand for these matters was $1.86 million, but we continue to negotiate the terms of a proposed settlement.

New Jersey Department of Environmental Protection (NJDEP) (Paulsboro Refinery). We are subject to 16 outstanding air-related Administrative Order and Notice of Civil Administrative Penalty Assessments (Notices) issued by the NJDEP relating to our Paulsboro Refinery. The Notices propose an aggregate penalty of $507,800. We have appealed certain of these Notices.

Ohio Environmental Protection Agency (Ohio EPA) (Lima Refinery). The Ohio EPA issued a proposed order to our Lima Refinery related to hydrogen sulfide levels in sewer gases routed to the refinery’s wastewater thermal oxidizer. The proposed order states a penalty of $350,000 for alleged New Source Performance Standards Subpart J violations. We are negotiating to settle this matter.

People of the State of Illinois, ex rel. v. The Premcor Refining Group Inc., et al., Third Judicial Circuit Court, Madison County (Case No. 03-CH-00459, filed May 29, 2003) (Hartford refinery and terminal). The Illinois Environmental Protection Agency (Illinois EPA) has issued several NOVs alleging violations of air and waste regulations at Premcor’s Hartford, Illinois terminal and now-closed refinery. We are negotiating the terms of a consent order for corrective action.

Texas Commission on Environmental Quality (TCEQ) (Port Arthur Refinery). In September 2005, we received two enforcement actions from the TCEQ relating to alleged Texas Clean Air Act violations at the Port Arthur Refinery dating back to 2002. The TCEQ has proposed penalties totaling $880,240 for these events. We have generally denied the allegations.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is traded on the New York Stock Exchange under the symbol “VLO.”

As of January 31, 2007, there were 8,478 holders of record of our common stock.

The following table shows the high and low sales prices of and dividends declared on our common stock for each quarter of 2006 and 2005.


	Sales Prices of the Common Stock				Dividends Per Common Share
Quarter Ended	High		Low		Dividends Per Common Share
2006:
December 31	$	57.09	$	47.52	$	0.08
September 30		68.83		46.84		0.08
June 30		70.75		55.19		0.08
March 31		63.70		47.99		0.06
2005:
December 31	$	58.15	$	45.86	$	0.05
September 30		58.63		39.38		0.05
June 30		41.13		28.90		0.05
March 31		38.58		21.01		0.04

On January 18, 2007, our board of directors declared a regular quarterly cash dividend of $0.12 per common share payable March 14, 2007 to holders of record at the close of business on February 14, 2007.

Dividends are considered quarterly by the board of directors and may be paid only when approved by the board.

During 2005 and 2006, 19,819,963 shares of our common stock, together with cash in lieu of fractional shares, were issued upon conversion of 10,000,000 shares of our 2% mandatory convertible preferred stock as discussed in Note 14 of Notes to Consolidated Financial Statements. The issuances of such shares were exempt from registration under Section 3(a)(9) of the Securities Act of 1933, as amended.

The following table discloses purchases of shares of Valero’s common stock made by us or on our behalf during the fourth quarter of 2006.


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Not Purchased as Part of Publicly Announced Plans or Programs (1)	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (2)
October 2006	2,105,947	$	52.96	2,105,947	0	$	2 billion
November 2006	924,781	$	52.48	924,781	0	$	2 billion
December 2006	765,411	$	54.75	765,411	0	$	2 billion
Total	3,796,139	$	53.20	3,796,139	0	$	2 billion

(1)

The shares reported in this column represent purchases settled in the fourth quarter of 2006 relating to (a) our purchases of shares in open-market transactions to meet our obligations under employee benefit plans, and (b) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our incentive compensation plans.

(2)	On October 23, 2006, we publicly announced a $2 billion stock purchase program that was authorized by our board of directors on October 19, 2006. The program has no expiration date.

The following Performance Graph is not “soliciting material,” is not deemed filed with the SEC, and is not to be incorporated by reference into any of Valero’s filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended, respectively.

The following line graph compares the cumulative total return* on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (selected by us) for the five-year period commencing December 31, 2001 and ending December 31, 2006. The peer group consists of the following ten companies that are engaged in the domestic energy industry: Chevron Corporation, ConocoPhillips, Exxon Mobil Corporation, Frontier Oil Corporation, Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Occidental Petroleum Corporation, Sunoco, Inc., and Tesoro Corporation.

LOGO


	12/2001		12/2002		12/2003		12/2004		12/2005		12/2006
Valero Common Stock	$	100	$	97.92	$	124.14	$	245.36	$	560.55	$	558.72
S&P 500		100		77.90		100.24		111.15		116.61		135.03
Peer Group		100		87.57		111.50		144.18		171.71		230.28

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

Assumes that an investment in Valero common stock and each index was $100 on December 31, 2001. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from December 31, 2001 through December 31, 2006.

ITEM 6.

SELECTED FINANCIAL DATA

The selected financial data for the five-year period ended December 31, 2006 was derived from our audited consolidated financial statements. The following table should be read together with the historical consolidated financial statements and accompanying notes included in Item 8, “Financial Statements and Supplementary Data,” and with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The following summaries are in millions of dollars except for per share amounts:


	Year Ended December 31,
	2006		2005 (a)		2004 (b)		2003 (c) (d)		2002
Operating revenues (e)	$	91,833	$	82,162	$	54,619	$	37,969	$	29,048

Operating income		8,010		5,459		2,979		1,222		471

Net income		5,463		3,590		1,804		622		92

Earnings per common share - assuming dilution		8.64		6.10		3.27		1.27		0.21

Dividends per common share		0.30		0.19		0.145		0.105		0.10

Property, plant and equipment, net		21,098		17,856		10,317		8,195		7,412

Goodwill		4,211		4,926		2,401		2,402		2,580

Total assets		37,753		32,798		19,392		15,664		14,465

Long-term debt and capital lease obligations (less current portions)		4,657		5,156		3,901		4,245		4,494

Company-obligated preferred securities of subsidiary trusts		—		—		—		—		373

Stockholders’ equity		18,605		15,050		7,798		5,735		4,308

(a)	Includes the operations related to the Premcor Acquisition beginning September 1, 2005.

(b)	Includes the operations related to the acquisition of the Aruba Refinery and related businesses (Aruba Acquisition) beginning March 5, 2004.

(c)	Includes the operations of the St. Charles Refinery beginning July 1, 2003.

(d)

On March 18, 2003, our ownership interest in Valero L.P. decreased from 73.6% to 49.5%. As a result of this decrease in ownership of Valero L.P. combined with certain other partnership governance changes, we ceased consolidating Valero L.P. on that date and began using the equity method to account for our investment in the partnership.

(e)	Operating revenues reported for 2005, 2004, 2003, and 2002 include approximately $7.8 billion, $4.9 billion, $3.9 billion, and $3.7 billion, respectively, related to crude oil buy/sell arrangements.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following review of our results of operations and financial condition should be read in conjunction with Items 1, 1A and 2, “Business, Risk Factors and Properties,” and Item 8, “Financial Statements and Supplementary Data,” included in this report. In the discussions that follow, all per-share amounts assume dilution.

CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report, including without limitation our disclosures below under the heading “Results of Operations - Outlook,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “believe,” “expect,” “plan,” “intend,” “estimate,” “project,” “projection,” “predict,” “budget,” “forecast,” “goal,” “guidance,” “target,” “will,” “could,” “should,” “may,” and similar expressions.

These forward-looking statements include, among other things, statements regarding:

•

future refining margins, including gasoline and distillate margins;

•

future retail margins, including gasoline, diesel, home heating oil, and convenience store merchandise margins;

•

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

•

anticipated levels of crude oil and refined product inventories;

•

our anticipated level of capital investments, including deferred refinery turnaround and catalyst costs and capital expenditures for environmental and other purposes, and the effect of those capital investments on our results of operations;

•

anticipated trends in the supply of and demand for crude oil and other feedstocks and refined products in the United States, Canada, and elsewhere;

•

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

•

the effect of general economic and other conditions on refining and retail industry fundamentals.

We based our forward-looking statements on our current expectations, estimates, and projections about ourselves and our industry. We caution that these statements are not guarantees of future performance and involve risks, uncertainties, and assumptions that we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual results may differ materially from the future performance that we have expressed or forecast in the forward-looking statements. Differences between actual results and any future performance suggested in these forward-looking statements could result from a variety of factors, including the following:

•

acts of terrorism aimed at either our facilities or other facilities that could impair our ability to produce or transport refined products or receive feedstocks;

•

political and economic conditions in nations that consume refined products, including the United States, and in crude oil producing regions, including the Middle East and South America;

•

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

•

the domestic and foreign supplies of crude oil and other feedstocks;

•

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

•

the level of consumer demand, including seasonal fluctuations;

•

refinery overcapacity or undercapacity;

•

the actions taken by competitors, including both pricing and the expansion and retirement of refining capacity in response to market conditions;

•

environmental, tax, and other regulations at the municipal, state, and federal levels and in foreign countries;

•

the level of foreign imports of refined products;

•

accidents or other unscheduled shutdowns affecting our refineries, machinery, pipelines, or equipment, or those of our suppliers or customers;

•

changes in the cost or availability of transportation for feedstocks and refined products;

•

the price, availability, and acceptance of alternative fuels and alternative-fuel vehicles;

•

delay of, cancellation of, or failure to implement planned capital projects and realize the various assumptions and benefits projected for such projects or cost overruns in constructing such planned capital projects;

•

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

•

rulings, judgments, or settlements in litigation or other legal or regulatory matters, including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;

•

legislative or regulatory action, including the introduction or enactment of federal, state, municipal, or foreign legislation or rulemakings, which may adversely affect our business or operations;

•

changes in the credit ratings assigned to our debt securities and trade credit;

•

changes in currency exchange rates, including the value of the Canadian dollar relative to the U.S. dollar; and

•

overall economic conditions.

Any one of these factors, or a combination of these factors, could materially affect our future results of operations and whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.

All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

OVERVIEW

The strong industry fundamentals we experienced throughout 2005 continued during 2006, resulting in the highest net income in our history of $5.5 billion, 52% higher than the net income reported in 2005. Our profitability is substantially determined by the spread between the price of refined products and the price of crude oil, referred to as the “refined product margin.” Refined product margins for the year 2006, both for gasoline and distillates, were comparable to the strong margins realized in 2005. Heavy industry-wide turnaround activity, the implementation of more restrictive sulfur regulations on gasoline and diesel, increased use of ethanol and decreased use of MTBE in the reformulated gasoline pool, and limited capacity expansions due to the high cost of compliance with environmental regulations resulted in tighter supplies of refined products and strong margins during most of 2006. Since approximately 60% of our total crude oil throughput represents sour crude oil and acidic sweet crude oil feedstocks that are purchased at prices less than sweet crude oil, our profitability is also significantly affected by the spread between sweet crude oil and sour crude oil prices, referred to as the “sour crude oil differential.” Sour crude oil differentials for 2006 were also about as wide as the very favorable differentials experienced in 2005. In addition to these continuing strong industry fundamentals, we benefited significantly from the addition of the four former Premcor refineries, which generated $2.5 billion of operating income, or 31% of our total operating income of $8.0 billion, with average throughput volumes of 792,000 barrels per day during 2006.

In addition to the operating income effects discussed above, we monetized our entire ownership interest in Valero L.P. by selling all of our units in Valero GP Holdings, LLC during 2006, generating proceeds of $880 million and recognizing a pre-tax gain of $328 million. This sale, along with our favorable operating results, resulted in a strong balance sheet as of December 31, 2006. We reduced debt by $245 million during 2006 and increased our cash balance to $1.6 billion at year-end, while at the same time purchasing $2.0 billion, or approximately 5%, of our outstanding shares.

RESULTS OF OPERATIONS

2006 Compared to 2005

Financial Highlights

(millions of dollars, except per share amounts)


	Year Ended December 31,
	2006			2005 (a) (b)			Change
Operating revenues (c)	$	91,833		$	82,162		$	9,671

Costs and expenses:
Cost of sales (a) (c)		77,482			71,673			5,809
Refining operating expenses		3,785			2,874			911
Retail selling expenses		803			758			45
General and administrative expenses		598			558			40
Depreciation and amortization expense:
Refining		1,024			720			304
Retail		87			83			4
Corporate		44			37			7

Total costs and expenses		83,823			76,703			7,120

Operating income		8,010			5,459			2,551
Equity in earnings of Valero L.P.		45			41			4
Other income, net		351			53			298
Interest and debt expense:
Incurred		(378	)		(334	)		(44	)
Capitalized		168			68			100
Minority interest in net income of Valero GP Holdings, LLC		(7	)		—			(7	)

Income before income tax expense		8,189			5,287			2,902
Income tax expense		2,726			1,697			1,029

Net income		5,463			3,590			1,873
Preferred stock dividends		2			13			(11	)

Net income applicable to common stock	$	5,461		$	3,577		$	1,884

Earnings per common share – assuming dilution	$	8.64		$	6.10		$	2.54

See	the footnote references on pages 28 and 29.

Operating Highlights

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


	Year Ended December 31,
	2006			2005 (a) (b)			Change
Refining:
Operating income (a)	$	8,470		$	5,900		$	2,570
Throughput margin per barrel (d)	$	12.29		$	11.14		$	1.15
Operating costs per barrel:
Refining operating expenses	$	3.50		$	3.16		$	0.34
Depreciation and amortization		0.95			0.80			0.15

Total operating costs per barrel	$	4.45		$	3.96		$	0.49

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		697			548			149
Medium/light sour crude		618			610			8
Acidic sweet crude		65			103			(38	)
Sweet crude		888			670			218
Residuals		234			181			53
Other feedstocks		149			132			17

Total feedstocks		2,651			2,244			407
Blendstocks and other		309			244			65

Total throughput volumes		2,960			2,488			472

Yields (thousand barrels per day):
Gasolines and blendstocks		1,432			1,174			258
Distillates		938			763			175
Petrochemicals		88			72			16
Other products (e)		503			481			22

Total yields		2,961			2,490			471


Retail – U.S.:
Operating income	$	113		$	81		$	32
Company-operated fuel sites (average)		982			1,024			(42	)
Fuel volumes (gallons per day per site)		4,985			4,830			155
Fuel margin per gallon	$	0.162		$	0.154		$	0.008
Merchandise sales	$	960		$	934		$	26
Merchandise margin (percentage of sales)		29.6	%		29.7	%		(0.1	)%
Margin on miscellaneous sales	$	169		$	126		$	43
Retail selling expenses	$	569		$	540		$	29
Depreciation and amortization expense	$	60		$	60		$	—

Retail – Canada:
Operating income	$	69		$	73		$	(4	)
Fuel volumes (thousand gallons per day)		3,176			3,204			(28	)
Fuel margin per gallon	$	0.217		$	0.211		$	0.006
Merchandise sales	$	167		$	150		$	17
Merchandise margin (percentage of sales)		27.4	%		25.6	%		1.8	%
Margin on miscellaneous sales	$	32		$	30		$	2
Retail selling expenses	$	234		$	218		$	16
Depreciation and amortization expense	$	27		$	23		$	4

See the footnote references on pages 28 and 29.

Refining Operating Highlights by Region (f)

(millions of dollars, except per barrel amounts)


	Year Ended December 31,
	2006		2005 (a) (b)			Change
Gulf Coast:
Operating income	$	5,109	$	3,962		$	1,147
Throughput volumes (thousand barrels per day) (g)		1,532		1,364			168
Throughput margin per barrel (d)	$	13.23	$	11.73		$	1.50
Operating costs per barrel:
Refining operating expenses	$	3.26	$	3.03		$	0.23
Depreciation and amortization		0.84		0.74			0.10

Total operating costs per barrel	$	4.10	$	3.77		$	0.33


Mid-Continent (h):
Operating income	$	1,329	$	856		$	473
Throughput volumes (thousand barrels per day) (g)		559		364			195
Throughput margin per barrel (d)	$	10.70	$	10.44		$	0.26
Operating costs per barrel:
Refining operating expenses	$	3.27	$	3.36		$	(0.09	)
Depreciation and amortization		0.92		0.65			0.27

Total operating costs per barrel	$	4.19	$	4.01		$	0.18


Northeast:
Operating income	$	944	$	725		$	219
Throughput volumes (thousand barrels per day) (g)		563		448			115
Throughput margin per barrel (d)	$	9.80	$	8.33		$	1.47
Operating costs per barrel:
Refining operating expenses	$	4.10	$	3.11		$	0.99
Depreciation and amortization		1.11		0.78			0.33

Total operating costs per barrel	$	5.21	$	3.89		$	1.32


West Coast:
Operating income	$	1,088	$	978		$	110
Throughput volumes (thousand barrels per day)		306		312			(6	)
Throughput margin per barrel (d)	$	15.07	$	13.42		$	1.65
Operating costs per barrel:
Refining operating expenses	$	4.04	$	3.59		$	0.45
Depreciation and amortization		1.27		1.23			0.04

Total operating costs per barrel	$	5.31	$	4.82		$	0.49

Operating income for regions above	$	8,470	$	6,521		$	1,949
LIFO charge (a)		—		(621	)		621

Total refining operating income	$	8,470	$	5,900		$	2,570

See	the footnote references on pages 28 and 29.

Average Market Reference Prices and Differentials (i)

(dollars per barrel)


	Year Ended December 31,
	2006		2005		Change
Feedstocks:
West Texas Intermediate (WTI) crude oil	$	66.00	$	56.44	$	9.56
WTI less sour crude oil at U.S. Gulf Coast (j)		7.01		6.88		0.13
WTI less Alaska North Slope (ANS) crude oil		2.47		3.06		(0.59	)
WTI less Maya crude oil		14.80		15.58		(0.78	)

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		11.34		10.60		0.74
No. 2 fuel oil less WTI		9.80		11.57		(1.77	)
Propylene less WTI		8.78		10.11		(1.33	)
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		12.16		10.39		1.77
Low-sulfur diesel less WTI		18.59		15.54		3.05
U.S. Northeast:
Conventional 87 gasoline less WTI		10.62		8.95		1.67
No. 2 fuel oil less WTI		9.60		11.60		(2.00	)
Lube oils less WTI		55.56		33.68		21.88
U.S. West Coast:
CARBOB 87 gasoline less ANS		21.52		19.42		2.10
CARB diesel less ANS		23.96		21.91		2.05

The	following notes relate to references on pages 25 through 28.

(a)

Includes the operations related to the Premcor Acquisition commencing on September 1, 2005. Cost of sales and refining operating income presented for the year ended December 31, 2005 include the effect of a $621 million LIFO charge related to the difference between the fair market value recorded for the inventories acquired in the Premcor Acquisition under purchase accounting and the amounts required to be recorded in applying Valero’s LIFO accounting policy. This charge was excluded from the consolidated and regional throughput margins per barrel and the regional operating income amounts presented herein in order to make the information presented comparable between periods.

(b)

As described in Note 1 of Notes to Consolidated Financial Statements, amounts previously reported in 2005 for refining operating expenses, retail selling expenses, general and administrative expenses, and depreciation and amortization expense, as well as related segment and regional amounts, have been reclassified for comparability with amounts reported in 2006.

(c)

Operating revenues and cost of sales both include approximately $7.8 billion for the year ended December 31, 2005 related to certain crude oil buy/sell arrangements, which involve linked purchases and sales related to crude oil contracts entered into to address location, quality, or grade requirements. Commencing January 1, 2006, we adopted EITF Issue No. 04-13 which requires that such buy/sell arrangements be accounted for as one transaction, thereby resulting in no recognition of revenues and cost of sales for these transactions.

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

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

(f)

The regions reflected herein contain the following refineries subsequent to the Premcor Acquisition: the Gulf Coast refining region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, Krotz Springs, St. Charles, Aruba, and Port Arthur Refineries; the Mid-Continent refining region includes the McKee, Ardmore, Memphis, and Lima Refineries; the Northeast refining region includes the Quebec City, Paulsboro, and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.

(g)

Throughput volumes for the Gulf Coast, Mid-Continent, and Northeast regions for the year ended December 31, 2006 include 287,000, 304,000, and 201,000 barrels per day, respectively, related to the operations of the refineries acquired from Premcor on September 1, 2005. Throughput volumes for the Gulf Coast, Mid-Continent, and Northeast regions for the year ended December 31, 2005 include 78,000, 106,000, and 63,000 barrels per day, respectively, related to the operations of the refineries acquired from Premcor commencing on September 1, 2005. Throughput volumes for those acquired refineries for the 122 days of their operations subsequent to the acquisition date of September 1, 2005 were 234,000, 317,000, and 187,000 barrels per day, respectively, for the Gulf Coast, Mid-Continent, and Northeast regions.

(h)

The information presented for the Mid-Continent region for the year ended December 31, 2005 includes the operations of the Denver Refinery, which was sold on May 31, 2005 to Suncor Energy (U.S.A.) Inc. Throughput volumes for the Mid-Continent region for the year ended December 31, 2005 include 15,000 barrels per day related to the Denver Refinery.

(i)

The average market reference prices and differentials, with the exception of the propylene and lube oil differentials, are based on posted prices from Platts Oilgram. The propylene differential is based on posted propylene prices in Chemical Market Associates, Inc. and the lube oil differential is based on Exxon Mobil Corporation postings provided by Independent Commodity Information Services-London Oil Reports. The average market reference prices and differentials are presented to provide users of the consolidated financial statements with economic indicators that significantly affect our operations and profitability.

(j)	The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.

General

Operating revenues increased 12% for the year ended December 31, 2006 compared to the year ended December 31, 2005 primarily as a result of higher refined product prices combined with additional throughput volumes from the former Premcor refinery operations. Operating income and net income for the year ended December 31, 2006 increased significantly compared to the year ended December 31, 2005. Operating income increased $2.6 billion, or 47%, from 2005 to 2006 due to a $2.6 billion increase in the refining segment and a $28 million increase in the retail segment, partially offset by a $47 million increase in general and administrative expenses (including corporate depreciation and amortization expense).

Refining

Operating income for our refining segment increased from $5.9 billion for the year ended December 31, 2005 to $8.5 billion for the year ended December 31, 2006 resulting from a 19% increase in throughput volumes and an increase in refining throughput margin of $1.15 per barrel, or 10%, partially offset by increased refining operating expenses (including depreciation and amortization expense) of $1.2 billion. In addition, the increase in the 2006 results was partially attributable to the unfavorable impact in 2005 of a $621 million pre-tax LIFO charge related to the difference between the fair market value recorded for the inventories acquired in the Premcor Acquisition under purchase accounting and the amounts required to be recorded in applying Valero’s LIFO accounting policy.

The change in refining throughput margin for 2006 compared to 2005 was impacted by the following factors:

•

Throughput volumes increased 472,000 barrels per day during 2006 compared to 2005 due to 545,000 barrels per day of incremental throughput from the four former Premcor refineries, offset to some extent by the sale of the Denver Refinery in 2005 and significant planned and unplanned downtime at several of our refineries in 2006.

•

Overall, gasoline and distillate margins increased in 2006 compared to 2005 due to significantly improved margins in the first half of 2006 attributable to increased foreign and U.S. demand, limited capacity additions, major industry turnaround activity, and continuing outages from last season’s hurricanes. However, the 2006 increase in gasoline and distillate margins was somewhat diminished in the second half of 2006 due to excess refined product supply and the higher margins experienced in September and October of 2005 due to the impact of Hurricanes Katrina and Rita.

•

Differentials on sour crude oil feedstocks during 2006 were essentially unchanged from the strong differentials in 2005, and remained wide due to continued ample supplies of sour crude oils and heavy sour residual fuel oils on the world market. Differentials on sour crude oil feedstocks also continued to benefit from increased demand for sweet crude oil resulting from lower sulfur specifications for gasoline and diesel and a global increase in refined product demand, particularly in Asia, which has resulted in higher utilization rates by refineries that require sweet crude oil as feedstock.

•

Throughput margin improved in 2006 due to the negative impact in 2005 of pre-tax losses of approximately $525 million on hedges related to forward sales of distillates and associated forward purchases of crude oil.

•

Margins on other refined products such as petroleum coke and sulfur were lower in 2006 due to an increase in the price of crude oil from 2005 to 2006.

Refining operating expenses, excluding depreciation and amortization expense, were 32% higher for the year ended December 31, 2006 compared to the year ended December 31, 2005, due primarily to the Premcor Acquisition on September 1, 2005. Excluding the effect of the Premcor Acquisition, operating expenses increased 5% due mainly to increases in maintenance expense, employee compensation and related benefits, outside services, and catalyst and chemicals, partially offset by reduced energy costs. Refining depreciation and amortization expense increased 42% from 2005 to 2006 primarily due to the Premcor Acquisition, the implementation of new capital projects, and increased turnaround and catalyst amortization.

Retail

Retail operating income was $182 million for the year ended December 31, 2006 compared to $154 million for the year ended December 31, 2005. This 18% increase in operating income was primarily attributable to improved retail fuel margins and increased in-store sales in the U.S. system, partially offset by higher selling expenses due mainly to an increase in credit card processing fees.

Corporate Expenses and Other

General and administrative expenses, including corporate depreciation and amortization expense, increased $47 million for the year ended December 31, 2006 compared to the year ended December 31, 2005. The increase was primarily due to increases in employee compensation and benefits, stock-based compensation expense, environmental expenses, and charitable contributions as well as the favorable resolution of a California excise tax dispute in 2005. These increases were partially offset by a decrease in variable compensation expense and 2005 nonrecurring expenses attributable to Premcor headquarters personnel.

“Other income, net” for the year ended December 31, 2006 includes a pre-tax gain of $328 million related to the sale of our ownership interest in Valero GP Holdings, LLC in 2006, as discussed in Note 9 of Notes to Consolidated Financial Statements.

Interest and debt expense incurred increased from 2005 to 2006 due to the effect of a full year of interest incurred in 2006 on the debt assumed in the Premcor Acquisition, partially offset by a reduction in other debt outstanding. Capitalized interest increased due to an increase in capital projects, including projects at the four former Premcor refineries.

Income tax expense increased $1.0 billion from 2005 to 2006 mainly as a result of a 55% increase in income before income tax expense. Our effective tax rate for the year ended December 31, 2006 increased from the year ended December 31, 2005 as a lower percentage of our pre-tax income was contributed by the Aruba Refinery, the profits of which are non-taxable in Aruba through December 31, 2010. This increase in the effective tax rate was partially offset by the effects of new tax legislation in both Texas and Canada in 2006.

2005 Compared to 2004

Financial Highlights

(millions of dollars, except per share amounts)


	Year Ended December 31,
	2005 (a) (b)			2004 (b) (c)			Change
Operating revenues (d)	$	82,162		$	54,619		$	27,543

Costs and expenses:
Cost of sales (a) (d)		71,673			47,797			23,876
Refining operating expenses		2,874			2,100			774
Retail selling expenses		758			696			62
General and administrative expenses		558			442			116
Depreciation and amortization expense:
Refining		720			517			203
Retail		83			58			25
Corporate		37			30			7

Total costs and expenses		76,703			51,640			25,063

Operating income		5,459			2,979			2,480
Equity in earnings of Valero L.P.		41			39			2
Other income (expense), net		53			(48	)		101
Interest and debt expense:
Incurred		(334	)		(297	)		(37	)
Capitalized		68			37			31

Income before income tax expense		5,287			2,710			2,577
Income tax expense		1,697			906			791

Net income		3,590			1,804			1,786
Preferred stock dividends		13			13			—

Net income applicable to common stock	$	3,577		$	1,791		$	1,786

Earnings per common share – assuming dilution	$	6.10		$	3.27		$	2.83

See the footnote references on pages 34 and 35.

Operating Highlights

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


	Year Ended December 31,
	2005 (a) (b)			2004 (b) (c)			Change
Refining:
Operating income (a)	$	5,900		$	3,267		$	2,633
Throughput margin per barrel (e)	$	11.14		$	7.44		$	3.70
Operating costs per barrel:
Refining operating expenses	$	3.16		$	2.65		$	0.51
Depreciation and amortization		0.80			0.66			0.14

Total operating costs per barrel	$	3.96		$	3.31		$	0.65

Throughput volumes (thousand barrels per day) (f):
Feedstocks:
Heavy sour crude		548			485			63
Medium/light sour crude		610			575			35
Acidic sweet crude		103			92			11
Sweet crude		670			531			139
Residuals		181			136			45
Other feedstocks		132			128			4

Total feedstocks		2,244			1,947			297
Blendstocks and other		244			215			29

Total throughput volumes		2,488			2,162			326

Yields (thousand barrels per day):
Gasolines and blendstocks		1,174			1,034			140
Distillates		763			650			113
Petrochemicals		72			71			1
Other products (g)		481			417			64

Total yields		2,490			2,172			318


Retail – U.S.:
Operating income	$	81		$	93		$	(12	)
Company-operated fuel sites (average)		1,024			1,106			(82	)
Fuel volumes (gallons per day per site)		4,830			4,644			186
Fuel margin per gallon	$	0.154		$	0.142		$	0.012
Merchandise sales	$	934		$	925		$	9
Merchandise margin (percentage of sales)		29.7	%		28.4	%		1.3	%
Margin on miscellaneous sales	$	126		$	100		$	26
Retail selling expenses	$	540		$	499		$	41
Depreciation and amortization expense	$	60		$	37		$	23

Retail – Canada:
Operating income	$	73		$	91		$	(18	)
Fuel volumes (thousand gallons per day)		3,204			3,250			(46	)
Fuel margin per gallon	$	0.211		$	0.211		$	—
Merchandise sales	$	150		$	140		$	10
Merchandise margin (percentage of sales)		25.6	%		23.8	%		1.8	%
Margin on miscellaneous sales	$	30		$	24		$	6
Retail selling expenses	$	218		$	197		$	21
Depreciation and amortization expense	$	23		$	21		$	2

See the footnote references on pages 34 and 35.

Refining Operating Highlights by Region (h)

(millions of dollars, except per barrel amounts)


	Year Ended December 31,
	2005 (a) (b)			2004 (b) (c)		Change
Gulf Coast:
Operating income	$	3,962		$	1,998	$	1,964
Throughput volumes (thousand barrels per day) (f) (i)		1,364			1,213		151
Throughput margin per barrel (e)	$	11.73		$	7.69	$	4.04
Operating costs per barrel:
Refining operating expenses	$	3.03		$	2.60	$	0.43
Depreciation and amortization		0.74			0.59		0.15

Total operating costs per barrel	$	3.77		$	3.19	$	0.58


Mid-Continent (j):
Operating income	$	856		$	233	$	623
Throughput volumes (thousand barrels per day) (i)		364			291		73
Throughput margin per barrel (e)	$	10.44		$	5.50	$	4.94
Operating costs per barrel:
Refining operating expenses	$	3.36		$	2.71	$	0.65
Depreciation and amortization		0.65			0.60		0.05

Total operating costs per barrel	$	4.01		$	3.31	$	0.70


Northeast:
Operating income	$	725		$	509	$	216
Throughput volumes (thousand barrels per day) (i)		448			380		68
Throughput margin per barrel (e)	$	8.33		$	6.22	$	2.11
Operating costs per barrel:
Refining operating expenses	$	3.11		$	1.96	$	1.15
Depreciation and amortization		0.78			0.61		0.17

Total operating costs per barrel	$	3.89		$	2.57	$	1.32


West Coast:
Operating income	$	978		$	527	$	451
Throughput volumes (thousand barrels per day)		312			278		34
Throughput margin per barrel (e)	$	13.42		$	10.02	$	3.40
Operating costs per barrel:
Refining operating expenses	$	3.59		$	3.78	$	(0.19	)
Depreciation and amortization		1.23			1.05		0.18

Total operating costs per barrel	$	4.82		$	4.83	$	(0.01	)

Operating income for regions above	$	6,521		$	3,267	$	3,254
LIFO charge (a)		(621	)		—		(621	)

Total refining operating income	$	5,900		$	3,267	$	2,633

See	the footnote references on pages 34 and 35.

Average Market Reference Prices and Differentials (k)

(dollars per barrel)


	Year Ended December 31,
	2005		2004		Change
Feedstocks:
WTI crude oil	$	56.44	$	41.42	$	15.02
WTI less sour crude oil at U.S. Gulf Coast (l)		6.88		5.31		1.57
WTI less ANS crude oil		3.06		2.53		0.53
WTI less Maya crude oil		15.58		11.43		4.15

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		10.60		7.73		2.87
No. 2 fuel oil less WTI		11.57		3.98		7.59
Propylene less WTI		10.11		9.80		0.31
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		10.39		8.59		1.80
Low-sulfur diesel less WTI		15.54		6.95		8.59
U.S. Northeast:
Conventional 87 gasoline less WTI		8.95		8.15		0.80
No. 2 fuel oil less WTI		11.60		5.44		6.16
Lube oils less WTI		33.68		23.83		9.85
U.S. West Coast:
CARBOB 87 gasoline less ANS		19.42		19.39		0.03
CARB diesel less ANS		21.91		16.45		5.46

The following notes relate to references on pages 31 through 34.

(a)

(b)

As described in Note 1 of Notes to Consolidated Financial Statements, amounts previously reported in 2005 and 2004 for refining operating expenses, retail selling expenses, general and administrative expenses, and depreciation and amortization expense, as well as related segment and regional amounts, have been reclassified for comparability with amounts reported in 2006.

(c)	Includes the operations related to the Aruba Acquisition commencing on March 5, 2004.

(d)

Operating revenues and cost of sales both include approximately $7.8 billion for the year ended December 31, 2005 and approximately $4.9 billion for the year ended December 31, 2004 related to certain crude oil buy/sell arrangements, which involve linked purchases and sales related to crude oil contracts entered into to address location, quality, or grade requirements. Commencing January 1, 2006, we adopted EITF Issue No. 04-13 which requires that such buy/sell arrangements be accounted for as one transaction, thereby resulting in no recognition of revenues and cost of sales for these transactions.

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

(f)

Total throughput volumes and throughput volumes for the Gulf Coast region for the year ended December 31, 2004 are based on 366 days, which results in 183,000 barrels per day being included for the Aruba Refinery for the year ended December 31, 2004. Throughput volumes for the Aruba Refinery for the 302 days of its operations during 2004 averaged 221,000 barrels per day.

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

(h)

Refineries; the Northeast refining region includes the Quebec City, Paulsboro, and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.

(i)	Throughput volumes for the Gulf Coast, Mid-Continent, and Northeast regions for the year ended December 31, 2005 include 78,000, 106,000, and 63,000 barrels per day, respectively, related to the operations of the refineries acquired from Premcor

commencing on September 1, 2005. Throughput volumes for those acquired refineries for the 122 days of their operations subsequent to the acquisition date of September 1, 2005 were 234,000, 317,000, and 187,000 barrels per day, respectively, for the Gulf Coast, Mid-Continent, and Northeast regions.

(j)

The information presented for the Mid-Continent region includes the operations of the Denver Refinery through May 31, 2005, the date of our sale of this facility to Suncor Energy (U.S.A.) Inc. Throughput volumes for the Mid-Continent region include 15,000 and 37,000 barrels per day related to the Denver Refinery for the years ended December 31, 2005 and 2004, respectively.

(k)

(l)	The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.

General

Operating revenues increased 50% for the year ended December 31, 2005 compared to the year ended December 31, 2004 primarily as a result of significantly higher refined product prices combined with additional throughput volumes from refinery operations. Operating income and net income for the year ended December 31, 2005 increased significantly compared to the year ended December 31, 2004. Operating income increased $2.5 billion, or 83%, from 2004 to 2005 due primarily to a $2.6 billion increase in the refining segment, partially offset by a $30 million decrease in the retail segment and a $123 million increase in general and administrative expenses (including corporate depreciation and amortization expense).

Refining

Operating income for our refining segment increased from $3.3 billion for the year ended December 31, 2004 to $5.9 billion for the year ended December 31, 2005, resulting mainly from an increase in refining throughput margin of $3.70 per barrel, or 50%, and a 15% increase in throughput volumes, partially offset by an increase in refining operating expenses (including depreciation and amortization expense) of $977 million and the 2005 LIFO charge discussed in the “2006 Compared to 2005 Results of Operations.”

Refining throughput margin for 2005 increased primarily due to the following factors:

•

Distillate margins increased significantly in all of our refining regions during 2005 compared to 2004, with margins in the Gulf Coast region almost triple the margins in 2004 and margins in the Mid-Continent and Northeast regions more than double 2004 margins. The improvement in distillate margins was due to increased foreign and U.S. demand, resulting from improved U.S. and global economies and higher demand for on-road diesel and jet fuel. In addition, both gasoline and distillate margins increased significantly in September and October of 2005 due to the impact of Hurricanes Katrina and Rita, which reduced the supply of refined products as refineries along the Gulf Coast reduced or shut down their operations because of the hurricanes.

•

Differentials on our sour crude oil feedstocks improved during 2005 compared to 2004 due to ample supplies of sour crude oils and heavy sour residual fuel oils on the world market. In addition, differentials on sour crude oil feedstocks benefited from increased demand for sweet crude oil resulting from several factors, including (i) the global movement to cleaner fuels, which has required most refineries to lower the sulfur content of the gasoline they produce, and (ii) a global increase in refined product demand, particularly in Asia, which has resulted in higher utilization rates by refineries that require sweet crude oil as feedstock.

•

Throughput volumes increased 326,000 barrels per day in 2005 compared to 2004 due mainly to throughput of 247,000 barrels per day at the four refineries acquired from Premcor on September 1, 2005, incremental throughput of 40,000 barrels per day at the Aruba Refinery, which was acquired in March 2004, and lower volumes in 2004 due to turnarounds at the St. Charles, Benicia, and Wilmington Refineries.

The above increases in throughput margin for 2005 were partially offset by the effects of:

•

lower margins on other refined products such as petroleum coke, sulfur, No. 6 fuel oil, asphalt, and propylene due to a significant increase in the price of crude oil from 2004 to 2005, and

•

increased pre-tax losses of approximately $295 million on hedges related to forward sales of distillates and associated forward purchases of crude oil.

Refining operating expenses, excluding depreciation and amortization expense, were 37% higher for the year ended December 31, 2005 compared to the year ended December 31, 2004 due mainly to $420 million of expenses related to the refineries acquired in the Premcor Acquisition, a full year of operations of the Aruba Refinery, and increases in energy costs, employee compensation expense, and maintenance expense. Refining depreciation and amortization expense increased 39% from 2004 to 2005 due mainly to depreciation expense resulting from the Premcor Acquisition on September 1, 2005, implementation of new capital projects, increased turnaround and catalyst amortization, a $15 million gain in 2004 on the sale of certain property discussed in Note 6 of Notes to Consolidated Financial Statements, and the write-off of costs in 2005 resulting from the decision to convert wholesale sites marketing under the Diamond Shamrock brand to the Valero brand.

Retail

Retail operating income was $154 million for the year ended December 31, 2005 compared to $184 million for the year ended December 31, 2004, a decrease of 16% between the periods. The decrease was primarily attributable to increased selling expenses in the U.S. and Canada as higher retail fuel prices resulted in higher credit card processing fees. In addition, Canada’s selling expenses increased $15 million due to an increase in the Canadian dollar exchange rate.

Corporate Expenses and Other

General and administrative expenses, including corporate depreciation and amortization expense, increased $123 million for the year ended December 31, 2005 compared to the year ended December 31, 2004, primarily due to increases in employee compensation and benefits, the recognition of increased variable compensation expense, resulting in large part from a significant increase in our common stock price during 2005, and expenses attributable to Premcor headquarters personnel. These increases were partially offset by the successful resolution in the first quarter of 2005 of a California excise tax dispute.

“Other income (expense), net” improved $101 million for the year ended December 31, 2005 compared to the year ended December 31, 2004 primarily due to the combined effect of a $55 million gain realized on the sale of our equity interests in Javelina Company and Javelina Pipeline Company in November 2005 and a 2004 impairment charge of $57 million to write off the carrying amount of our equity investment in Clear Lake Methanol Partners, L.P. This combined effect, as well as an increase in bank interest income due to higher cash balances, was partially offset by our 50% interest in certain debt refinancing costs incurred in 2005 by the Cameron Highway Oil Pipeline joint venture and increased costs related to our accounts receivable sales program.

Interest and debt expense incurred increased from 2004 to 2005 due to interest incurred in 2005 on the debt resulting from the Premcor Acquisition. Capitalized interest increased due to an increase in capital projects, including projects at the four former Premcor refineries.

Income tax expense increased $791 million from 2004 to 2005 mainly as a result of a 95% increase in income before income tax expense. Our effective tax rate for the year ended December 31, 2005, however, decreased from the year ended December 31, 2004 primarily as a result of a change in permanent book-to-tax differences, which included a deduction from income in 2005 for qualified domestic manufacturing activities, as allowed under the American Jobs Creation Act of 2004.

OUTLOOK

In January 2007, we saw industry fundamentals for refined products remain consistent with what we experienced at the end of 2006. The Gulf Coast gasoline margin for January 2007 was $4.62 per barrel, while the West Coast gasoline margin averaged $20.34 per barrel. Regarding distillates, the Gulf Coast on-road diesel margin was $13.00 per barrel and the West Coast on-road diesel margin was $28.94 per barrel.

Our outlook for gasoline margins is positive. Gasoline supplies are expected to tighten as spring maintenance activity gets underway. In addition, the industry will soon be making the transition from winter-grade gasoline specifications to summer-grade specifications, which generally leads to declines in inventories and higher margins as we head toward the summer driving season. While these factors are expected to reduce supplies, gasoline demand is expected to remain positive this year as a result of lower pump prices and a continuing strong economy. This positive demand trend combined with the expected pressure on supplies should create a tightening of the supply/demand balance.

The outlook for low-sulfur distillate margins is also favorable as on-road diesel demand continues to be strong. Currently, approximately 80% of our U.S. on-road distillate production is ultra-low-sulfur diesel (ULSD) and we are on schedule to meet the EPA’s phase-in requirements for ULSD by the end of the transition period in June 2007. In addition, specifications requiring a reduction in the amount of sulfur in off-road diesel (excluding marine and railroad uses) go into effect in June of this year, which may further tighten supplies. As a result, we expect the favorable spread between on-road and off-road diesel prices to continue.

Sour crude oil differentials are expected to remain favorable for the foreseeable future. Persistently weak residual fuel oil prices support wider differentials for sour crude oil since complex refiners can substitute residual fuel oil for a portion of their sour crude oil purchases if residual fuel oil becomes more economic to process than crude oil. In addition, the flexibility of many of our refineries to process alternative sour crude oils allows us to continue to find attractively priced feedstocks.

Operationally during 2007, we expect to benefit from our recently completed Port Arthur crude unit expansion which allows us to process up to 325,000 barrels per day of sour crude oil at that refinery.

On February 16, 2007, our McKee Refinery experienced a fire in its propane deasphalting unit. As of the filing of this annual report, the entire McKee Refinery remains shut down while efforts are underway to determine the cause of the accident, assess damages, and establish a plan for making repairs. Full scale efforts to assess damages, make repairs, and restart the refinery are underway though we do not yet have a firm estimated date for commencement of operations. Although we are in the preliminary stages of assessing the extent of damages, we do not believe that this incident will have a material adverse effect on our results of operations for the first quarter of 2007.

Overall, we believe that we are well-positioned to capitalize on the expected continuing positive industry fundamentals during 2007.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Year Ended December 31, 2006

Net cash provided by operating activities for the year ended December 31, 2006 was $6.3 billion compared to $5.9 billion for the year ended December 31, 2005. The increase in cash generated from operating activities was due primarily to the significant increase in operating income discussed above under “Results of Operations,” partially offset by a $1.2 billion decrease from an unfavorable change in working capital between the years and a $1.0 billion increase in current income tax expense. Changes in cash provided by or used for working capital during the years ended December 31, 2006 and 2005 are shown in Note 16 of Notes to Consolidated Financial Statements. The primary difference in the working capital changes between the two years resulted from a favorable working capital change in 2005 attributable to the factors discussed below in “Cash Flows for the Year Ended December 31, 2005.” Both receivables and accounts payable increased in 2006 due mainly to price increases for gasoline and crude oil.

The net cash generated from operating activities during the year ended December 31, 2006, combined with $880 million of proceeds from the sale of our ownership interest in Valero GP Holdings, LLC, a $206 million benefit from tax deductions in excess of recognized stock-based compensation cost, and $122 million of proceeds from the issuance of common stock related to our employee benefit plans, were used mainly to:

•

fund $3.8 billion of capital expenditures and deferred turnaround and catalyst costs;

•

purchase 34.6 million shares of treasury stock at a cost of $2.0 billion;

•

make long-term note repayments of $249 million;

•

fund $101 million of contingent earn-out payments in connection with the acquisition of Basis Petroleum, Inc., the St. Charles Refinery, and the Delaware City Refinery;

•

terminate our interest rate swap contracts for $54 million;

•

pay common and preferred stock dividends of $184 million; and

•

increase available cash on hand by $1.2 billion.

Cash Flows for the Year Ended December 31, 2005

Net cash provided by operating activities for the year ended December 31, 2005 was $5.9 billion compared to $3.0 billion for the year ended December 31, 2004, an increase of $2.9 billion. The increase in cash generated from operating activities was due primarily to the significant increase in operating income discussed above under “Results of Operations” and an $879 million increase from favorable working capital changes between the years, as reflected in Note 16 of Notes to Consolidated Financial Statements. For the year ended December 31, 2005, working capital was positively impacted by a $400 million increase in the amount of receivables sold under our accounts receivable sales program and a decrease in restricted cash of approximately $200 million due to the repayment of certain debt assumed in the Premcor Acquisition using funds restricted for that purpose. Both receivables and accounts payable increased significantly due to commodity price increases from December 31, 2004 to December 31, 2005.

The net cash generated from operating activities during 2005, combined with $428 million of available cash on hand, $182 million of proceeds from the issuance of common stock related to our employee benefit plans, $78 million of proceeds from the sale of our investment in the Javelina joint venture, $45 million of proceeds from the sale of the Denver Refinery, and a $38 million net return of investment from the Cameron Highway Oil Pipeline joint venture resulting mainly from the refinancing of the joint venture’s debt in June 2005, were used mainly to:

•

fund $2.6 billion of capital expenditures and deferred turnaround and catalyst costs;

•

make long-term note repayments of $874 million;

•

fund $2.3 billion of the Premcor Acquisition, net of cash acquired;

•

purchase 13 million shares of treasury stock at a cost of $571 million;

•

fund contingent earn-out payments of $85 million in connection with prior acquisitions;

•

fund certain minor acquisitions for $62 million;

•

make a general partner contribution to Valero L.P. of $29 million; and

•

pay common and preferred stock dividends of $106 million.

Capital Investments

During the year ended December 31, 2006, we expended $3.2 billion for capital expenditures and $569 million for deferred turnaround and catalyst costs. Capital expenditures for the year ended December 31, 2006 included approximately $1.6 billion of costs related to environmental projects. In addition, we expended $101 million for amounts due under contingent earn-out agreements.

In connection with our acquisitions of Basis Petroleum, Inc. in 1997 and the St. Charles Refinery in 2003, the sellers are entitled to receive payments in any of the ten years and seven years, respectively, following these acquisitions if certain average refining margins during any of those years exceed a specified level (see the discussion in Note 23 of Notes to Consolidated Financial Statements). In connection with the Premcor Acquisition, we assumed Premcor’s obligation under a contingent earn-out agreement related to Premcor’s acquisition of the Delaware City Refinery from Motiva Enterprises LLC (Motiva). Under this agreement, Motiva was entitled to receive two separate annual earn-out contingency payments depending on (a) the amount of crude oil processed at the refinery and the level of refining margins through May 2007, and (b) the achievement of certain performance criteria at the gasification facility through May 2006. The earn-out contingency related to the gasification facility expired in 2006 with no payment required. Payments due under all of these earn-out arrangements are limited based on annual and aggregate limits. During 2006, we made earn-out payments of $26 million (the maximum remaining payment based on the aggregate limitation under the agreement) related to the acquisition of Basis Petroleum, Inc., $50 million related to the acquisition of the St. Charles Refinery, and $25 million related to the acquisition of the Delaware City Refinery. In January 2007, we made an earn-out payment of $50 million related to the St. Charles Refinery. Based on estimated margin levels through April 2007, earn-out payments of $25 million (the maximum remaining payment based on the aggregate limitation under the agreement) related to the acquisition of the Delaware City Refinery would be due in the second quarter of 2007.

For 2007, we expect to incur approximately $3.5 billion for capital investments, including approximately $3.1 billion for capital expenditures (approximately $800 million of which is for environmental projects) and approximately $400 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes anticipated expenditures related to the contingent earn-out agreements discussed above and strategic acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.

Contractual Obligations

Our contractual obligations as of December 31, 2006 are summarized below (in millions).


	Payments Due by Period
	2007		2008		2009		2010		2011		Thereafter		Total
Long-term debt	$	462	$	6	$	209	$	33	$	418	$	3,946	$	5,074
Capital lease obligations		9		10		10		10		9		84		132
Operating lease obligations		413		331		243		161		100		238		1,486
Purchase obligations		19,955		7,090		1,657		311		302		2,333		31,648
Other long-term liabilities		—		183		155		153		145		986		1,622

Total	$	20,839	$	7,620	$	2,274	$	668	$	974	$	7,587	$	39,962

Long-Term Debt

Payments for long-term debt are at stated values.

During March 2006, we made a scheduled debt repayment of $220 million related to our 7.375% notes. In addition, during 2006, we made debt payments of $29 million related to various notes as discussed in Note 12 of Notes to Consolidated Financial Statements.

As of December 31, 2006, “current portion of long-term debt and capital lease obligations” as reflected in the consolidated balance sheet included mainly $230 million of notes which become due in April 2007 and $50 million of notes which become due in November 2007, as well as $175 million of notes with a maturity date of February 2010 which were redeemed in February 2007, as discussed in Note 12 of Notes to Consolidated Financial Statements.

Our agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt to below investment grade ratings by Moody’s Investors Service and Standard & Poor’s Ratings Services, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. As of December 31, 2006, all of our ratings on our senior unsecured debt are at or above “investment grade” level as follows:


Rating Agency		Rating
Standard & Poor’s Ratings Services		BBB (stable outlook)
Moody’s Investors Service		Baa3 (stable outlook)
Fitch Ratings		BBB (stable outlook)

Operating Lease Obligations

Our operating lease obligations include leases for land, office facilities and equipment, retail facilities and equipment, dock facilities, transportation equipment, and various facilities and equipment used in the storage, transportation, production, and sale of refinery feedstocks and refined products. Operating lease obligations include all operating leases that have initial or remaining noncancelable terms in excess of one year, and are not reduced by minimum rentals to be received by us under subleases.

Purchase Obligations

A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum, or variable price provisions, and (iii) the approximate timing of the transaction. We have various purchase obligations including industrial gas and chemical supply arrangements (such as hydrogen supply arrangements), crude oil and other feedstock supply arrangements, and various throughput and terminalling agreements. We enter into these contracts to ensure an adequate supply of utilities, feedstock, and storage to operate our refineries. Substantially all of our purchase obligations are based on market prices or adjustments based on market indices. Certain of these purchase obligations include fixed or minimum volume requirements, while others are based on our usage requirements. The purchase obligation amounts included in the table above include both short-term and long-term obligations and are based on (a) fixed or minimum quantities to be purchased and (b) fixed or estimated prices to be paid based on current market conditions. As of December 31, 2006, our short-term and long-term purchase obligations decreased by approximately $2.0 billion from the amount reported as of December 31, 2005. The decrease is primarily attributable to a decrease in obligations under crude oil supply contracts, partially offset by new contracts in 2006. We have not made in the past, nor do we expect to make in the future, payments for feedstock or services that we have not received or will not receive, nor paid prices in excess of then prevailing market conditions.

Other Long-term Liabilities

Our “other long-term liabilities” are described in Note 13 of Notes to Consolidated Financial Statements. For most of these liabilities, the timing of the payment of such liabilities is not fixed and therefore cannot be determined as of December 31, 2006. However, certain expected payments related to our anticipated pension contribution in 2007 and our other postretirement benefit obligations are discussed in Note 21 of Notes to Consolidated Financial Statements. For purposes of reflecting amounts for other long-term liabilities in the table above, we have made our best estimate of expected payments for each type of liability based on information available as of December 31, 2006.

Other Commercial Commitments

As of December 31, 2006, our committed lines of credit were as follows:


	Borrowing Capacity	Expiration
Revolving credit facility	$ 2.5 billion	August 2011
Canadian revolving credit facility	Cdn. $ 115 million	December 2010

As of December 31, 2006, we had $343 million of letters of credit outstanding under uncommitted short-term bank credit facilities, Cdn. $85 million of letters of credit outstanding under our Canadian committed revolving credit facility, and $245 million of letters of credit outstanding under our committed revolving credit facility. These letters of credit expire during 2007, 2008, and 2009.

Stock Purchase Programs

Our board of directors has approved our purchase of treasury stock in open market transactions to satisfy employee benefit plan requirements as well as purchases under our publicly announced stock purchase programs. Under these authorizations, we purchased approximately 5% of our outstanding shares during 2006. We purchased 28.9 million shares for $1.6 billion related to our employee benefit plans and 5.7 million shares for $361 million under our former stock purchase program.

On October 19, 2006, our board of directors approved a new $2 billion common stock purchase program. This new authorization is in addition to our existing authorization for employee benefit plan requirements. Stock purchases under this program will be made from time to time at prevailing prices as permitted by securities laws and other legal requirements, and are subject to market conditions and other factors. The program does not have a scheduled expiration date. During 2006, we purchased no shares under our new $2 billion stock purchase program.

Sale of Investment in Valero GP Holdings, LLC

On July 19, 2006, Valero GP Holdings, LLC consummated an initial public offering (IPO) of 17,250,000 of its units representing limited liability company interests to the public at $22.00 per unit, before an underwriters’ discount of $1.265 per unit. On December 22, 2006, Valero GP Holdings, LLC completed a secondary public offering of 20,550,000 units representing limited liability company interests at a price of $21.62 per unit, before an underwriters’ discount of $0.8648 per unit. In addition, 4,700,000 unregistered units of Valero GP Holdings, LLC were sold to its chairman of the board of directors (who was at that time also chairman of Valero’s board of directors) at $21.62 per unit. All such units were sold by our subsidiaries that held various ownership interests in Valero GP Holdings, LLC. As a result, Valero GP Holdings, LLC did not receive any proceeds from these offerings, and our indirect ownership interest in Valero GP Holdings, LLC was reduced to zero.

Proceeds to our selling subsidiaries from the IPO totaled approximately $355 million, net of the underwriters’ discount and other offering expenses, which resulted in a pre-tax gain to us of $132 million on the sale of the units. Proceeds to our selling subsidiaries from the secondary offering and private sale of units totaled

approximately $525 million, net of the underwriters’ discount and other offering expenses, which resulted in an additional pre-tax gain to us of $196 million. The total pre-tax gain of $328 million is included in “other income (expense), net” in the consolidated statement of income for the year ended December 31, 2006. The funds received from these offerings are being used for general corporate purposes.

Pension Plan Funded Status

During 2006, we contributed $343 million to our qualified pension plans. Based on a 5.75% discount rate and fair values of plan assets as of December 31, 2006, the fair value of the assets in our qualified pension plans was equal to approximately 104% of the projected benefit obligation under those plans as of the end of 2006.

Although we have no expected minimum required contribution to our qualified pension plans during 2007 under the Employee Retirement Income Security Act, we expect to contribute approximately $100 million to our qualified plans during 2007.

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. For additional information regarding our environmental matters, see Note 24 of Notes to Consolidated Financial Statements.

Tax Matters

We are subject to extensive tax liabilities, including federal, state, and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise, withholding, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. For example, effective January 1, 2007, the Government of Aruba (GOA) enacted a turnover tax on revenues from the sale of goods produced and services rendered in Aruba. The turnover tax, which is 3% for on-island sales and services and 1% on export sales, is being assessed by the GOA on sales by our Aruba Refinery. However, due to a previous tax holiday that was granted to our Aruba Refinery by the GOA through December 31, 2010, we believe that sales by our Aruba Refinery should not be subject to this turnover tax. We have filed a request for arbitration with the Netherlands Arbitration Institute pursuant to which we will seek to enforce our rights under this tax holiday.

Other

During the third quarter of 2005, certain of our refineries experienced property damage and business interruption losses associated with Hurricanes Katrina and Rita. As a result of these losses, we submitted claims to our insurance carriers under our insurance policies. As of December 31, 2006, we have recorded a receivable related to our property damage claims, which was recorded as a reduction of repair and maintenance expense. No amounts related to the potential business interruption insurance recoveries were accrued in our consolidated financial statements as of and for the year ended December 31, 2005 as we had not reached a final settlement with the insurance carriers. During 2006, we reached a final business interruption settlement with our insurance carriers, the proceeds from which were recorded as a reduction to “cost of sales.” Amounts received or to be received for these matters are immaterial to our results of operations and financial position.

On February 1, 2007, we announced our plan to explore strategic alternatives for our Lima Refinery, which we acquired in the Premcor Acquisition.

Our refining and marketing operations have a concentration of customers in the refining industry and customers who are refined product wholesalers and retailers. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively, in that these customers may be similarly affected by changes in economic or other conditions. However, we believe that our portfolio of accounts receivable is sufficiently diversified to the extent necessary to minimize potential credit risk. Historically, we have not had any significant problems collecting our accounts receivable.

We believe that we have sufficient funds from operations and, to the extent necessary, from the public and private capital markets and bank markets, to fund our ongoing operating requirements. We expect that, to the extent necessary, we can raise additional funds from time to time through equity or debt financings. However, there can be no assurances regarding the availability of any future financings or whether such financings can be made available on terms that are acceptable to us.

OFF-BALANCE SHEET ARRANGEMENTS

Accounts Receivable Sales Facility

As of December 31, 2006, we had an accounts receivable sales facility with a group of third-party financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables, which matures in August 2008. We use this program as a source of working capital funding. Under this program, one of our wholly owned subsidiaries sells an undivided percentage ownership interest in the eligible receivables, without recourse, to the third-party financial institutions. We remain responsible for servicing the transferred receivables and pay certain fees related to our sale of receivables under the program. As of December 31, 2006, the amount of eligible receivables sold to the third-party financial institutions was $1 billion. Note 4 of Notes to Consolidated Financial Statements includes additional discussion of the activity related to this program.

Termination of this program would require us to obtain alternate working capital funding, which would result in an increase in accounts receivable and either increased debt or reduced cash on our consolidated balance sheet. However, as of December 31, 2006, the termination of this program would not have had a material effect on our liquidity and would not have affected our ability to comply with restrictive covenants in our credit facilities. We are not aware of any existing circumstances that are reasonably likely to result in the termination or material reduction in the availability of this program prior to its maturity.

NEW ACCOUNTING PRONOUNCEMENTS

As discussed in Note 1 of Notes to Consolidated Financial Statements, certain new financial accounting pronouncements have been issued which either have already been reflected in the accompanying consolidated financial statements, or will become effective for our financial statements at various dates in the future. The adoption of these pronouncements has not had, nor is expected to have, a material effect on our consolidated financial statements.

CRITICAL ACCOUNTING POLICIES INVOLVING CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The following summary provides further information about our critical accounting policies that involve critical accounting estimates, and should be read in conjunction with Note 1 of Notes to Consolidated Financial Statements, which summarizes our significant accounting policies. The following accounting policies involve estimates that are considered critical due to the level of sensitivity and judgment involved, as well as the impact on our consolidated financial position and results of operations. We believe that all of our estimates are reasonable.

Impairment of Assets

Long-lived assets (excluding goodwill, intangible assets with indefinite lives, equity method investments, and deferred tax assets) are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. An impairment loss should be recognized only if the carrying amount of the asset is not recoverable and exceeds its fair value. Goodwill and intangible assets that have indefinite useful lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. An impairment loss should be recognized if the carrying amount of the asset exceeds its fair value. We evaluate our equity method investments for impairment when there is evidence that we may not be able to recover the carrying amount of our investments or the investee is unable to sustain an earnings capacity that justifies the carrying amount. A loss in the value of an investment that is other than a temporary decline is recognized currently in earnings, and is based on the difference between the estimated current fair value of the investment and its carrying amount.

In order to test for recoverability, management must make estimates of projected cash flows related to the asset being evaluated which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment. Due to the significant subjectivity of the assumptions used to test for recoverability and to determine fair value, changes in market conditions could result in significant impairment charges in the future, thus affecting our earnings. Our impairment evaluations are based on assumptions that are consistent with our business plans. However, providing sensitivity analysis if other assumptions were used in performing the impairment evaluations is not practicable due to the significant number of assumptions involved in the estimates. We recognized an impairment charge of $57 million in 2004 related to our equity investment in Clear Lake Methanol Partners, L.P. as discussed in Note 10 of Notes to Consolidated Financial Statements.

Environmental Liabilities

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

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

determination of our obligation in proportion to other parties. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts, and potential improvements in remediation technologies. An estimate of the sensitivity to earnings for changes in those factors is not practicable due to the number of contingencies that must be assessed, the number of underlying assumptions, and the wide range of possible outcomes.

The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2006, 2005, and 2004 is included in Note 24 of Notes to Consolidated Financial Statements. We believe that we have adequately accrued for our environmental exposures.

Pension and Other Postretirement Benefit Obligations

We have significant pension and other postretirement benefit liabilities and costs that are developed from actuarial valuations. Inherent in these valuations are key assumptions including discount rates, expected return on plan assets, future compensation increases, and health care cost trend rates. Changes in these assumptions are primarily influenced by factors outside our control. For example, the discount rate assumption is based on a review of long-term bonds that receive one of the two highest ratings given by a recognized rating agency as of the end of each year, while the expected return on plan assets is based on a compounded return calculated for us by an outside consultant using historical market index data with an asset allocation of 65% equities and 35% bonds, which is representative of the asset mix in our qualified pension plans. These assumptions can have a significant effect on the amounts reported in our consolidated financial statements. For example, a 0.25% decrease in the assumptions related to the discount rate or expected return on plan assets or a 0.25% increase in the assumptions related to the health care cost trend rate or rate of compensation increase would have the following effects on the projected benefit obligation as of December 31, 2006 and net periodic benefit cost for the year ending December 31, 2007 (in millions):


	Pension Benefits		Other Postretirement Benefits
Increase in projected benefit obligation resulting from:
Discount rate decrease	$	59	$	17
Compensation rate increase		23		—
Health care cost trend rate increase		—		11
Increase in expense resulting from:
Discount rate decrease		9		2
Expected return on plan assets decrease		3		—
Compensation rate increase		5		—
Health care cost trend rate increase		—		2

Tax Liabilities

Our operations are subject to extensive tax liabilities, including federal, state, and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise, withholding, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed, and the implementation of future legislative and regulatory tax initiatives could result in increased tax liabilities that cannot be predicted at this time. In addition, we have received claims from various jurisdictions related to certain tax matters. Tax liabilities include potential assessments of penalty and interest amounts.

We record tax liabilities based on our assessment of existing tax laws and regulations. A contingent loss related to a transactional tax claim is recorded if the loss is both probable and estimable. The recording of our tax

liabilities requires significant judgments and estimates. Actual tax liabilities can vary from our estimates for a variety of reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due. In addition, in determining our income tax provision, we must assess the likelihood that our deferred tax assets, primarily consisting of net operating loss and tax credit carryforwards, will be recovered through future taxable income. Significant judgment is required in estimating the amount of valuation allowance, if any, that should be recorded against those deferred income tax assets. If our actual results of operations differ from such estimates or our estimates of future taxable income change, the valuation allowance may need to be revised. However, an estimate of the sensitivity to earnings that would result from changes in the assumptions and estimates used in determining our tax liabilities is not practicable due to the number of assumptions and tax laws involved, the various potential interpretations of the tax laws, and the wide range of possible outcomes.

Legal Liabilities

A variety of claims have been made against us in various lawsuits. Although we have been successful in defending litigation in the past, we cannot be assured of similar success in future litigation due to the inherent uncertainty of litigation and the individual fact circumstances in each case. We record a liability related to a loss contingency attributable to such legal matters if we determine the loss to be both probable and estimable. The recording of such liabilities requires judgments and estimates, the results of which can vary significantly from actual litigation results due to differing interpretations of relevant law and differing opinions regarding the degree of potential liability and the assessment of reasonable damages. However, an estimate of the sensitivity to earnings if other assumptions were used in recording our legal liabilities is not practicable due to the number of contingencies that must be assessed and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

COMMODITY PRICE RISK

We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refining operations. In order to reduce the risks of these price fluctuations, we use derivative commodity instruments to hedge a portion of our refinery feedstock and refined product inventories and a portion of our unrecognized firm commitments to purchase these inventories (fair value hedges). The carrying amount of our refinery feedstock and refined product inventories was $4.2 billion and $3.8 billion as of December 31, 2006 and 2005, respectively, and the fair value of such inventories was $7.1 billion as of both December 31, 2006 and 2005. From time to time, we use derivative commodity instruments to hedge the price risk of forecasted transactions such as forecasted feedstock and product purchases, refined product sales, and natural gas purchases (cash flow hedges). We also use derivative commodity instruments that do not receive hedge accounting treatment to manage our exposure to price volatility on a portion of our refinery feedstock and refined product inventories and on certain forecasted feedstock and product purchases, refined product sales, and natural gas purchases. These derivative instruments are considered economic hedges for which changes in their fair value are recorded currently in cost of sales. Finally, we enter into derivative commodity instruments based on our fundamental and technical analysis of market conditions that we mark to market for accounting purposes. See “Derivative Instruments” in Note 1 of Notes to Consolidated Financial Statements for a discussion of our accounting for the various types of derivative transactions.

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

The following tables provide information about our derivative commodity instruments as of December 31, 2006 and 2005 (dollars in millions, except for the weighted-average pay and receive prices as described below), including:

•

fair value hedges which are used to hedge our recognized refining inventories and unrecognized firm commitments (i.e., binding agreements to purchase inventories in the future);

•

cash flow hedges which are used to hedge our forecasted feedstock and product purchases, refined product sales, and natural gas purchases;

•

economic hedges (hedges not designated as fair value or cash flow hedges) which are used to:

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

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

•

derivative commodity instruments held or issued for trading purposes.

The gain or loss on a derivative instrument designated and qualifying as a fair value hedge and the offsetting loss or gain on the hedged item are recognized currently in income in the same period. The effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is initially reported as a component of “other comprehensive income” and is then recorded in income in the period or periods during which the hedged forecasted transaction affects income. The ineffective portion of the gain or loss on the cash flow derivative instrument, if any, is recognized in income as incurred. For our economic hedges and for derivative instruments entered into by us for trading purposes, the derivative instrument is recorded at fair value and changes in the fair value of the derivative instrument are recognized currently in income.

The following tables include only open positions at the end of the indicated reporting period, and therefore do not include amounts related to closed cash flow hedges for which the gain or loss remains in “accumulated other comprehensive income” pending consummation of the forecasted transactions.

Contract volumes are presented in thousands of barrels (for crude oil and refined products) or in billions of British thermal units (for natural gas). The weighted-average pay and receive prices represent amounts per barrel (for crude oil and refined products) or amounts per million British thermal units (for natural gas). Volumes shown for swaps represent notional volumes, which are used to calculate amounts due under the agreements. For futures, the contract value represents the contract price of either the long or short position multiplied by the derivative contract volume, while the market value amount represents the period-end market price of the commodity being hedged multiplied by the derivative contract volume. The pre-tax fair value for futures, swaps, and options represents the fair value of the derivative contract. The pre-tax fair value for swaps represents the excess of the receive price over the pay price multiplied by the notional contract volumes. For futures and options, the pre-tax fair value represents (i) the excess of the market value amount over the contract amount for long positions, or (ii) the excess of the contract amount over the market value amount for short positions. Additionally, for futures and options, the weighted-average pay price represents the contract price for long positions and the weighted-average receive price represents the contract price for short positions. The weighted-average pay price and weighted-average receive price for options represents their strike price.


	December 31, 2006
	Contract Volumes	Wtd Avg Pay Price		Wtd Avg Receive Price		Contract Value		Market Value			Pre-tax Fair Value


*Fair Value Hedges:*
Futures – long:
2007 (crude oil and refined products)	15,261	$	63.66		N/A	$	972	$	949		$	(23	)
Futures – short:
2007 (crude oil and refined products)	22,091		N/A	$	64.56		1,426		1,379			47

*Cash Flow Hedges:*
Swaps – long:
2007 (crude oil and refined products)	39,125		70.14		65.16		N/A		(195	)		(195	)
Swaps – short:
2007 (crude oil and refined products)	39,125		69.66		76.30		N/A		260			260
Futures – long:
2007 (crude oil and refined products)	21,087		64.75		N/A		1,365		1,336			(29	)
Futures – short:
2007 (crude oil and refined products)	18,356		N/A		64.82		1,190		1,161			29

*Economic Hedges:*
Swaps – long:
2007 (crude oil and refined products)	13,244		12.02		11.02		N/A		(13	)		(13	)
2007 (natural gas)	893		0.76		0.78		N/A		—			—
Swaps – short:
2007 (crude oil and refined products)	7,605		26.47		27.66		N/A		9			9
2007 (natural gas)	833		0.85		0.89		N/A		—			—
Futures – long:
2007 (crude oil and refined products)	50,442		64.28		N/A		3,242		3,171			(71	)
2007 (natural gas)	400		7.33		N/A		3		3			—
Futures – short:
2007 (crude oil and refined products)	51,623		N/A		64.15		3,312		3,252			60
2007 (natural gas)	400		N/A		8.21		3		3			—
Options – long:
2007 (crude oil and refined products)	31		84.29		N/A		—		—			—
Options – short:
2007 (crude oil and refined products)	1,478		N/A		61.94		—		(6	)		6

*Trading Activities:*
Futures – long:
2007 (crude oil and refined products)	801		77.29		N/A		62		59			(3	)
Futures – short:
2007 (crude oil and refined products)	801		N/A		84.87		68		58			10


Total pre-tax fair value of open positions											$	87


	December 31, 2005
		Wtd Avg		Wtd Avg								Pre-tax
	Contract	Pay		Receive		Contract			Market			Fair
	Volumes	Price		Price		Value			Value			Value
*Fair Value Hedges:*
Futures – long:
2006 (crude oil and refined products)	50,912	$	59.03		N/A	$	3,005		$	3,113		$	108
Futures – short:
2006 (crude oil and refined products)	64,422		N/A	$	59.87		3,857			3,958			(101	)

*Cash Flow Hedges:*
Futures – long:
2006 (crude oil and refined products)	18,179		62.24		N/A		1,131			1,152			21
Futures – short:
2006 (crude oil and refined products)	13,690		N/A		60.51		828			849			(21	)

*Economic Hedges:*
Swaps – long:
2006 (crude oil and refined products)	7,947		8.12		8.81		N/A			5			5
2006 (natural gas)	2,700		11.37		9.19		N/A			(6	)		(6	)
Swaps – short:
2006 (crude oil and refined products)	4,481		17.27		16.85		N/A			(2	)		(2	)
2006 (natural gas)	1,350		9.19		11.46		N/A			3			3
Futures – long:
2006 (crude oil and refined products)	29,945		65.64		N/A		1,966			2,036			70
Futures – short:
2006 (crude oil and refined products)	27,052		N/A		65.34		1,768			1,815			(47	)
Options – long:
2006 (natural gas)	1,290		9.27		N/A		(2	)		(1	)		1
Options – short:
2006 (crude oil and refined products)	190		N/A		72.95		(1	)		(1	)		—
2006 (natural gas)	690		N/A		7.98		—			—			—

*Trading Activities:*
Swaps – long:
2006 (crude oil and refined products)	300		11.64		11.94		N/A			—			—
2006 (natural gas)	350		9.33		11.28		N/A			1			1
Swaps – short:
2006 (crude oil and refined products)	1,350		12.66		13.17		N/A			1			1
2006 (natural gas)	350		11.28		9.18		N/A			(1	)		(1	)
Futures – long:
2006 (crude oil and refined products)	12,266		60.01		N/A		736			763			27
2006 (natural gas)	840		8.03		N/A		6			9			3
Futures – short:
2006 (crude oil and refined products)	10,816		N/A		60.49		654			678			(24	)
2006 (natural gas)	840		N/A		8.34		7			9			(2	)
Options – long:
2006 (crude oil and refined products)	2,000		0.50		N/A		—			—			—
2006 (natural gas)	900		10.00		N/A		—			—			—
Options – short:
2006 (crude oil and refined products)	2,000		N/A		0.50		—			—			—
2006 (natural gas)	900		N/A		10.00		—			—			—


Total pre-tax fair value of open positions												$	36

INTEREST RATE RISK

Our primary market risk exposure for changes in interest rates relates to our long-term debt obligations. We manage our exposure to changing interest rates through the use of a combination of fixed and floating rate debt. In addition, we sometimes utilize interest rate swap agreements to manage a portion of our exposure to changing interest rates by converting certain fixed-rate debt to floating rate. These interest rate swap agreements are generally accounted for as fair value hedges. The gain or loss on the derivative instrument and the gain or loss on the debt that is being hedged is recorded in interest expense. The recorded amounts of the derivative instrument and long-term debt balances are adjusted accordingly.

The following table provides information about our long-term debt and interest rate derivative instruments (dollars in millions), all of which are sensitive to changes in interest rates. For long-term debt, principal cash flows and related weighted-average interest rates by expected maturity dates are presented. For interest rate swaps, the table presents notional amounts and weighted-average interest rates by expected (contractual) maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the contract. Weighted-average floating rates are based on implied forward rates in the yield curve at the reporting date.


	December 31, 2006
	Expected Maturity Dates
	2007			2008			2009			2010			2011			There- after			Total			Fair Value
Long-term Debt:
Fixed rate	$	462		$	6		$	209		$	33		$	418		$	3,946		$	5,074		$	5,361
Average interest rate		7.3	%		6.0	%		3.6	%		6.8	%		6.4	%		7.1	%		6.9	%


	December 31, 2005
	Expected Maturity Dates
	2006			2007			2008			2009			2010			There- after			Total			Fair Value
Long-term Debt:
Fixed rate	$	220		$	287		$	6		$	209		$	208		$	4,392		$	5,322		$	5,735
Average interest rate		7.4	%		6.1	%		6.0	%		3.6	%		8.9	%		7.0	%		6.9	%

Interest Rate Swaps Fixed to Floating:
Notional amount	$	125		$	225		$	—		$	9		$	—		$	641		$	1,000		$	(28	)
Average pay rate		6.5	%		6.2	%		5.8	%		5.9	%		5.9	%		5.6	%		5.9	%
Average receive rate		6.0	%		5.8	%		5.7	%		5.7	%		5.7	%		5.6	%		5.7	%

On May 1, 2006, we terminated the $875 million of interest rate swap contracts outstanding at that date for a payment of $54 million. Substantially all of this payment was deferred and is being amortized to interest expense over the remaining lives of the debt instruments that were being hedged.

FOREIGN CURRENCY RISK

We enter into foreign currency exchange and purchase contracts to manage our exposure to exchange rate fluctuations on transactions related to our Canadian operations. Changes in the fair value of these contracts are recognized currently in income and are intended to offset the income effect of translating the foreign currency denominated transactions that they are intended to hedge.

As of December 31, 2006, we had commitments to purchase $290 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before January 19, 2007, resulting in a 2007 gain of $4 million.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate “internal control over financial reporting” (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) for Valero. Our management evaluated the effectiveness of Valero’s internal control over financial reporting as of December 31, 2006. In its evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Management believes that as of December 31, 2006, our internal control over financial reporting was effective based on those criteria.

Our independent registered public accounting firm has issued an attestation report on management’s assessment of our internal control over financial reporting, which begins on page 54 of this report.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

of Valero Energy Corporation and subsidiaries:

We have audited the accompanying consolidated balance sheets of Valero Energy Corporation and subsidiaries (the Company) as of December 31, 2006 and 2005, and the related consolidated statements of income, stockholders’ equity, cash flows and comprehensive income for each of the years in the three-year period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) (the PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Valero Energy Corporation and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, the Company adopted the provisions of Emerging Issues Task Force Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, and Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment, effective January 1, 2006.

We also have audited, in accordance with the standards of the PCAOB, the effectiveness of Valero Energy Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 23, 2007, expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

/s/ KPMG LLP

San Antonio, Texas

February 23, 2007

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

of Valero Energy Corporation and subsidiaries:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Valero Energy Corporation and subsidiaries (the Company) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) (the PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Valero Energy Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by COSO. Also, in our opinion, Valero Energy Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the PCAOB, the consolidated balance sheets of Valero Energy Corporation and subsidiaries as of December 31, 2006 and 2005, and the related consolidated

statements of income, stockholders’ equity, cash flows and comprehensive income for each of the years in the three-year period ended December 31, 2006, and our report dated February 23, 2007 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

San Antonio, Texas

February 23, 2007

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Par Value)


	December 31,
	2006			2005
ASSETS
Current assets:
Cash and temporary cash investments	$	1,590		$	436
Restricted cash		31			30
Receivables, net		4,389			3,564
Inventories		4,430			4,039
Income taxes receivable		32			70
Deferred income taxes		143			142
Prepaid expenses and other		145			65

Total current assets		10,760			8,346


Property, plant and equipment, at cost		24,377			20,388
Accumulated depreciation		(3,279	)		(2,532	)

Property, plant and equipment, net		21,098			17,856


Intangible assets, net		303			298
Goodwill		4,211			4,926
Investment in Valero L.P.		—			327
Deferred charges and other assets, net		1,381			1,045

Total assets	$	37,753		$	32,798


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	476		$	222
Accounts payable		6,864			5,563
Accrued expenses		510			581
Taxes other than income taxes		586			595
Income taxes payable		23			109
Deferred income taxes		363			305

Total current liabilities		8,822			7,375


Long-term debt, less current portion		4,576			5,109

Capital lease obligations, less current portion		81			47

Deferred income taxes		4,047			3,615

Other long-term liabilities		1,622			1,602

Commitments and contingencies (Note 23)

Stockholders’ equity:
Preferred stock, $0.01 par value; 20,000,000 shares authorized; 0 and 3,164,151 shares issued and outstanding		—			68
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 627,501,593 and 621,230,266 shares issued		6			6
Additional paid-in capital		7,779			8,164
Treasury stock, at cost; 23,738,162 and 3,807,976 common shares		(1,396	)		(196	)
Retained earnings		11,951			6,673
Accumulated other comprehensive income		265			335

Total stockholders’ equity		18,605			15,050

Total liabilities and stockholders’ equity	$	37,753		$	32,798

See Notes to Consolidated Financial Statements.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Millions of Dollars, Except per Share Amounts and Supplemental Information)


	Year Ended December 31,
	2006			2005			2004
Operating revenues (1) (2)	$	91,833		$	82,162		$	54,619


Costs and expenses:
Cost of sales (1)		77,482			71,673			47,797
Refining operating expenses		3,785			2,874			2,100
Retail selling expenses		803			758			696
General and administrative expenses		598			558			442
Depreciation and amortization expense		1,155			840			605

Total costs and expenses		83,823			76,703			51,640


Operating income		8,010			5,459			2,979
Equity in earnings of Valero L.P.		45			41			39
Other income (expense), net		351			53			(48	)
Interest and debt expense:
Incurred		(378	)		(334	)		(297	)
Capitalized		168			68			37
Minority interest in net income of Valero GP Holdings, LLC		(7	)		—			—


Income before income tax expense		8,189			5,287			2,710
Income tax expense		2,726			1,697			906


Net income		5,463			3,590			1,804
Preferred stock dividends		2			13			13


Net income applicable to common stock	$	5,461		$	3,577		$	1,791


Earnings per common share	$	8.94		$	6.51		$	3.51
Weighted-average common shares outstanding (in millions)		611			549			510

Earnings per common share – assuming dilution	$	8.64		$	6.10		$	3.27
Weighted-average common equivalent shares outstanding (in millions)		632			588			552

Dividends per common share	$	0.30		$	0.19		$	0.145

Supplemental information (billions of dollars):
(1) Includes amounts related to crude oil buy/sell arrangements:
Operating revenues		N/A		$	7.8		$	4.9
Cost of sales		N/A			7.8			4.9
(2) Includes excise taxes on sales by our U.S. retail system	$	0.8			0.8			0.8

See Notes to Consolidated Financial Statements.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Millions of Dollars)


	Preferred Stock			Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)
Balance as of December 31, 2003	$	200		$	4	$	3,919		$	(41	)	$	1,483		$	170
Net income		—			—		—			—			1,804			—
Dividends on common stock		—			—		—			—			(75	)		—
Dividends on and accretion of preferred stock		8			—		—			—			(13	)		—
Sale of common stock		—			1		405			—			—			—
Stock-based compensation expense		—			—		24			—			—			—
Shares repurchased, net of shares issued, in connection with employee stock plans and other		—			—		8			(158	)		—			—
Other comprehensive income		—			—		—			—			—			59


Balance as of December 31, 2004		208			5		4,356			(199	)		3,199			229
Net income		—			—		—			—			3,590			—
Dividends on common stock		—			—		—			—			(103	)		—
Dividends on and accretion of preferred stock		10			—		—			—			(13	)		—
Conversion of preferred stock		(150	)		—		150			—			—			—
Issuance of common stock in connection with the Premcor Acquisition		—			1		3,177			—			—			—
Fair value of replacement stock options issued in connection with the Premcor Acquisition		—			—		595			—			—			—
Stock-based compensation expense		—			—		51			—			—			—
Shares issued, net of shares repurchased, in connection with employee stock plans and other		—			—		(165	)		3			—			—
Other comprehensive income		—			—		—			—			—			106


Balance as of December 31, 2005		68			6		8,164			(196	)		6,673			335
Net income		—			—		—			—			5,463			—
Dividends on common stock		—			—		—			—			(183	)		—
Dividends on and accretion of preferred stock		1			—		—			—			(2	)		—
Conversion of preferred stock		(69	)		—		69			—			—			—
Credits from subsidiary stock sales, net of tax		—			—		101			—			—			—
Stock-based compensation expense		—			—		81			—			—			—
Shares repurchased, net of shares issued, in connection with employee stock plans and other		—			—		(636	)		(1,200	)		—			—
Other comprehensive income		—			—		—			—			—			29
Adjustment to initially apply FASB Statement No. 158, net of tax		—			—		—			—			—			(99	)

Balance as of December 31, 2006	$	—		$	6	$	7,779		$	(1,396	)	$	11,951		$	265

See Notes to Consolidated Financial Statements.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)


	Year Ended December 31,
	2006			2005			2004
Cash flows from operating activities:
Net income	$	5,463		$	3,590		$	1,804
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		1,155			840			605
Minority interest in net income of Valero GP Holdings, LLC		7			—			—
Gain on sale of Valero GP Holdings, LLC		(328	)		—			—
Gain on sale of investment in Javelina joint venture		—			(55	)		—
Impairment of investment in Clear Lake Methanol Partners, L.P.		—			—			57
Noncash interest expense and other income, net		24			31			11
Stock-based compensation expense		108			80			35
Deferred income tax expense		290			255			345
Changes in current assets and current liabilities		(144	)		1,082			203
Changes in deferred charges and credits and other, net		(263	)		27			(80	)

Net cash provided by operating activities		6,312			5,850			2,980

Cash flows from investing activities:
Capital expenditures		(3,187	)		(2,133	)		(1,292	)
Deferred turnaround and catalyst costs		(569	)		(441	)		(304	)
Premcor Acquisition, net of cash acquired		—			(2,343	)		—
Proceeds from sale of Valero GP Holdings, LLC		880			—			—
Aruba Acquisition, net of cash acquired		—			—			(541	)
Proceeds from sale of the Denver Refinery		—			45			—
Proceeds from sale of investment in Javelina joint venture		—			78			—
General partner contribution to Valero L.P.		—			(29	)		—
Contingent payments in connection with acquisitions		(101	)		(85	)		(53	)
(Investment) return of investment in Cameron Highway Oil Pipeline Project, net		(26	)		38			(36	)
Distributions in excess of equity in earnings of Valero L.P.		8			—			—
Proceeds from dispositions of property, plant and equipment		64			30			108
Buyout of assets under structured lease arrangements		—			—			(567	)
Minor acquisitions and other investing activities, net		(40	)		(60	)		—

Net cash used in investing activities		(2,971	)		(4,900	)		(2,685	)

Cash flows from financing activities:
Long-term notes:
Borrowings		—			—			400
Repayments		(249	)		(874	)		(69	)
Bank credit agreements:
Borrowings		830			1,617			3,528
Repayments		(830	)		(1,617	)		(3,788	)
Termination of interest rate swaps		(54	)		—			—
Purchase of treasury stock		(2,020	)		(571	)		(318	)
Proceeds from the sale of common stock, net of issuance costs		—			—			406
Issuance of common stock in connection with employee benefit plans		122			182			113
Benefit from tax deduction in excess of recognized stock-based compensation cost		206			—			—
Common and preferred stock dividends		(184	)		(106	)		(79	)
Cash distributions to minority interest in Valero GP Holdings, LLC		(4	)		—			—
Other		(5	)		(13	)		(8	)

Net cash provided by (used in) financing activities		(2,188	)		(1,382	)		185

Effect of foreign exchange rate changes on cash		1			4			15

Net increase (decrease) in cash and temporary cash investments		1,154			(428	)		495
Cash and temporary cash investments at beginning of year		436			864			369

Cash and temporary cash investments at end of year	$	1,590		$	436		$	864

See Notes to Consolidated Financial Statements.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions of Dollars)


	Year Ended December 31,
	2006			2005			2004
Net income	$	5,463		$	3,590		$	1,804

Other comprehensive income (loss):
Foreign currency translation adjustment		(11	)		54			111

Pension liability adjustment		(1	)		(1	)		—

Net gain (loss) on derivative instruments designated and qualifying as cash flow hedges:
Net gain (loss) arising during the year, net of income tax (expense) benefit of $(38), $117, and $90		70			(218	)		(168	)
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $15, $(146), and $(62)		(29	)		271			116

Net gain (loss) on cash flow hedges		41			53			(52	)

Other comprehensive income		29			106			59

Comprehensive income	$	5,492		$	3,696		$	1,863

See Notes to Consolidated Financial Statements.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

As used in this report, the terms “Valero,” “we,” “us,” or “our” may refer to Valero Energy Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole. We are an independent refining and marketing company and own and operate 18 refineries (seven in Texas, two each in California and Louisiana, and one each in Delaware, Ohio, Oklahoma, New Jersey, Tennessee, Aruba, and Quebec, Canada) with a combined total throughput capacity as of December 31, 2006 of approximately 3.3 million barrels per day. We market our refined products through an extensive bulk and rack marketing network and approximately 5,800 retail and wholesale branded outlets in the United States and eastern Canada under various brand names including primarily Valero^{^®}, Diamond Shamrock^{^®}, Shamrock^{^®}, Ultramar^{^®}, and Beacon^{^®}. Our operations are affected by:

•

company-specific factors, primarily refinery utilization rates and refinery maintenance turnarounds;

•

seasonal factors, such as the demand for refined products during the summer driving season and heating oil during the winter season; and

•

industry factors, such as movements in and the level of crude oil prices including the effect of quality differential between grades of crude oil, the demand for and prices of refined products, industry supply capacity, and competitor refinery maintenance turnarounds.

These consolidated financial statements include the accounts of Valero and subsidiaries in which Valero has a controlling interest. Intercompany balances and transactions have been eliminated in consolidation. Investments in non-controlled entities are accounted for using the equity method of accounting.

On July 19, 2006, Valero sold a 40.6% interest in Valero GP Holdings, LLC, which, through certain of its subsidiaries, owns the general partner interest, incentive distribution rights, and a 21.4% limited partner interest in Valero L.P. On December 22, 2006, Valero sold its remaining interest in Valero GP Holdings, LLC. These financial statements consolidate Valero GP Holdings, LLC through December 21, 2006, with net income attributable to the 40.6% interest held by public unitholders from July 19, 2006 through December 21, 2006 presented as a minority interest in the consolidated statement of income. See Note 9 under “Valero GP Holdings, LLC” for a discussion of the sale of Valero GP Holdings, LLC.

The term UDS Acquisition refers to the merger of Ultramar Diamond Shamrock Corporation (UDS) into Valero effective December 31, 2001.

Use of Estimates

The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires our management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, management reviews its estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Cash and Temporary Cash Investments

Our temporary cash investments are highly liquid, low-risk debt instruments which have a maturity of three months or less when acquired. Cash and temporary cash investments exclude cash that is not available to us due to restrictions related to its use. Such amounts are segregated in the consolidated balance sheets in “restricted cash” (see Note 3).

Inventories

Inventories are carried at the lower of cost or market. The cost of refinery feedstocks purchased for processing and refined products are determined under the last-in, first-out (LIFO) method using the dollar-value LIFO method, with any increments valued based on average purchase prices during the year. The cost of feedstocks and products purchased for resale and the cost of materials, supplies, and convenience store merchandise are determined principally under the weighted-average cost method.

Effective January 1, 2006, we adopted the provisions of Statement No. 151, “Inventory Costs,” which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material and requires that those items be recognized as current-period charges. Statement No. 151 also requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. We adopted Statement No. 151 on January 1, 2006 with no effect on our financial position or results of operations.

Property, Plant and Equipment

Additions to property, plant and equipment, including capitalized interest and certain costs allocable to construction and property purchases, are recorded at cost.

The costs of minor property units (or components of property units), net of salvage value, retired or abandoned are charged or credited to accumulated depreciation under the composite method of depreciation. Gains or losses on sales or other dispositions of major units of property are recorded in income and are reported in “depreciation and amortization expense” in the consolidated statements of income.

Depreciation of property, plant and equipment is recorded on a straight-line basis over the estimated useful lives of the related facilities primarily using the composite method of depreciation. Leasehold improvements and assets acquired under capital leases are amortized using the straight-line method over the shorter of the lease term or the estimated useful life of the related asset.

Goodwill and Intangible Assets

Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over 1 to 40 years. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. We use October 1 of each year as our valuation date for annual impairment testing purposes.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Deferred Charges and Other Assets

“Deferred charges and other assets, net” include the following:

•

refinery turnaround costs, which are incurred in connection with planned major maintenance activities at our refineries and which are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs;

•

fixed-bed catalyst costs, representing the cost of catalyst that is changed out at periodic intervals when the quality of the catalyst has deteriorated beyond its prescribed function, which are deferred when incurred and amortized on a straight-line basis over the estimated useful life of the specific catalyst;

•

investments in certain entities we do not control, which are accounted for using the equity method of accounting; and

•

other noncurrent assets such as long-term investments, convenience store dealer incentive programs, pension plan assets, debt issuance costs, and various other costs.

We evaluate our equity method investments for impairment when there is evidence that we may not be able to recover the carrying amount of our investments or the investee is unable to sustain an earnings capacity that justifies the carrying amount. A loss in the value of an investment that is other than a temporary decline is recognized currently in earnings, and is based on the difference between the estimated current fair value of the investment and its carrying amount. We believe that the carrying amounts of our equity method investments as of December 31, 2006 are recoverable.

Effective January 1, 2006, we adopted Emerging Issues Task Force (EITF) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (EITF No. 04-5), which requires the general partner in a limited partnership to determine whether the limited partnership is controlled by, and therefore should be consolidated by, the general partner. The adoption of EITF No. 04-5 had no impact on the accounting for our investment in Valero L.P.

Impairment and Disposal of Long-Lived Assets

Long-lived assets (excluding goodwill, intangible assets with indefinite lives, equity method investments, and deferred tax assets) are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its fair value, with fair value determined based on discounted estimated net cash flows. We believe that the carrying amounts of our long-lived assets as of December 31, 2006 are recoverable.

Taxes Other than Income Taxes

“Taxes other than income taxes” includes primarily liabilities for ad valorem, excise, sales and use, and payroll taxes.

Income Taxes

Income taxes are accounted for under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred amounts are measured using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In December 2004, the Financial Accounting Standards Board (FASB) issued Staff Position No. FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Repatriation Provision within the American Jobs Creation Act of 2004,” which allowed an enterprise time beyond the end of the financial reporting period covering the date of enactment to evaluate the effect of the American Jobs Creation Act of 2004 (the 2004 Act) on its plan for reinvestment or repatriation of foreign earnings for purposes of applying Statement No. 109. As we have not repatriated and currently have no plans to repatriate funds under the provisions of the 2004 Act, there has been no impact on our consolidated financial statements as a result of adoption of Staff Position No. FAS 109-2.

See “New Accounting Pronouncements” below for a discussion of FASB Interpretation No. 48, which, beginning in 2007, prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in tax returns.

Asset Retirement Obligations

We record a liability, which is referred to as an asset retirement obligation, at fair value for the estimated cost to retire a tangible long-lived asset at the time we incur that liability, which is generally when the asset is purchased, constructed, or leased. We record the liability when we have a legal obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the liability’s fair value.

We have asset retirement obligations with respect to certain of our refinery assets due to various legal obligations to clean and/or dispose of various component parts of each refinery at the time they are retired. However, these component parts can be used for extended and indeterminate periods of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain our refinery assets and continue making improvements to those assets based on technological advances. As a result, we believe that our refineries have indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we would retire refinery assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of any component part of a refinery, we estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using established present value techniques.

We also have asset retirement obligations for the removal of underground storage tanks (USTs) for refined products at owned and leased retail locations. There is no legal obligation to remove USTs while they remain in service. However, environmental laws require that unused USTs be removed within certain periods of time after the USTs no longer remain in service, usually one to two years depending on the jurisdiction in which the USTs are located. We have estimated that USTs at our owned retail locations will not remain in service after 25 years of use and that we will have an obligation to remove those USTs at that time. For our leased retail locations, our lease agreements generally require that we remove certain improvements, primarily USTs and signage, upon termination of the lease. While our lease agreements typically contain options for multiple renewal periods, we have not assumed that such leases will be renewed for purposes of estimating our obligation to remove USTs and signage.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effective December 31, 2005, we adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 clarifies that the term “conditional asset retirement obligation”