Edgar Filing: VALERO ENERGY CORP/TX

VLO 12.31.12 10K

FORM 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(Mark One)



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

For the fiscal year ended December 31, 2012



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _______________ to _______________

Commission file number 1-13175

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)



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



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

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

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

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

Yes R No o

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

Yes R No o

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule12b-2 of the Exchange Act.



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

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

The aggregate market value of the voting and non-voting common stock held by non-affiliates was approximately $13.3 billion based on the last sales price quoted as of June 29, 2012 on the New York Stock Exchange, the last business day of the registrant’s most recently completed second fiscal quarter.

As of January 31, 2013, 552,933,285 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

We intend to file with the Securities and Exchange Commission a definitive Proxy Statement for our Annual Meeting of Stockholders scheduled for May 2, 2013, at which directors will be elected. Portions of the 2013 Proxy Statement are incorporated by reference in Part III of this Form 10-K and are deemed to be a part of this report.

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CROSS-REFERENCE SHEET

The following table indicates the headings in the 2013 Proxy Statement where certain information required in Part III of this Form 10-K may be found.



Form 10-K Item No. and Caption		Heading in 2013 Proxy Statement

10.	Directors, Executive Officers and Corporate Governance	Information Regarding the Board of Directors, Independent Directors, Audit Committee, Proposal No. 1 Election of Directors, Information Concerning Nominees and Other Directors, Identification of Executive Officers, Section 16(a) Beneficial Ownership Reporting Compliance, and Governance Documents and Codes of Ethics

11.	Executive Compensation	Compensation Committee, Compensation Discussion and Analysis, Director Compensation, Executive Compensation, and Certain Relationships and Related Transactions

12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	Beneficial Ownership of Valero Securities and Equity Compensation Plan Information

13.	Certain Relationships and Related Transactions, and Director Independence	Certain Relationships and Related Transactions and Independent Directors

14.	Principal Accountant Fees and Services	KPMG Fees for Fiscal Year 2012, KPMG Fees for Fiscal Year 2011, 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 Valero Energy Corporation, Attn: Secretary, P.O. Box 696000, San Antonio, Texas 78269-6000.

CONTENTS



		PAGE
PART I
Items 1., 1A., & 2.	Business, Risk Factors, and Properties	1
	Segments	2
	Valero’s Operations	3
	Risk Factors	13
	Environmental Matters	19
	Properties	19
Item 1B.	Unresolved Staff Comments	19
Item 3.	Legal Proceedings	20
Item 4.	Mine Safety Disclosures	21

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	22
Item 6.	Selected Financial Data	25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	56
Item 8.	Financial Statements and Supplementary Data	58
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	137
Item 9A.	Controls and Procedures	137
Item 9B.	Other Information	137

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	138
Item 11.	Executive Compensation	138
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	138
Item 13.	Certain Relationships and Related Transactions, and Director Independence	138
Item 14.	Principal Accountant Fees and Services	138

PART IV
Item 15.	Exhibits and Financial Statement Schedules	138

Signature		142

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PART I

The terms “Valero,” “we,” “our,” and “us,” as used in this report, may refer to Valero Energy Corporation, to one or more of our consolidated subsidiaries, or to all of them taken as a whole. In this Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources, under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. You should read our forward-looking statements together with our disclosures beginning on page 26 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 corporate offices are at One Valero Way, San Antonio, Texas, 78249, and our telephone number is (210) 345-2000. Our common stock trades on the New York Stock Exchange under the symbol “VLO.” We were incorporated in Delaware in 1981 under the name Valero Refining and Marketing Company. We changed our name to Valero Energy Corporation on August 1, 1997. On January 31, 2013, we had 21,671 employees.

Our 16 petroleum refineries are located in the United States (U.S.), Canada, the United Kingdom (U.K.), and Aruba. Our refineries can produce conventional gasolines, distillates, jet fuel, asphalt, petrochemicals, lubricants, and other refined products as well as a slate of premium products including CBOB and RBOB¹, gasoline meeting the specifications of the California Air Resources Board (CARB), CARB diesel fuel, and low-sulfur and ultra-low-sulfur diesel fuel.

We market branded and unbranded refined products on a wholesale basis in the U.S., Canada, the U.K., and Ireland through an extensive bulk and rack marketing network, and we sell refined products through a network of 1,880 company-owned and leased retail sites in the U.S. and Canada and 5,450 branded wholesale sites that we neither own nor operate in the U.S., Canada, the U.K., Aruba, and Ireland.

We also own 10 ethanol plants in the central plains region of the U.S. that primarily produce ethanol, which we market on a wholesale basis through a bulk marketing network.

Available Information. Our website address is www.valero.com. Information 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 website (under “Investor Relations”) free of charge, soon after we file or furnish such material. In this same location, we also post our corporate governance guidelines, codes of ethics, and the charters of the committees of our board of directors. These documents are available in print to any stockholder that makes a written request to Valero Energy Corporation, Attn: Secretary, P.O. Box 696000, San Antonio, Texas 78269-6000.

_____________________________

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

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SEGMENTS

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


•	Our refining segment includes refining operations, wholesale marketing, product supply and distribution, and transportation operations. The refining segment is segregated geographically into the U.S. Gulf Coast, U.S. Mid-Continent, North Atlantic, and U.S. West Coast regions.


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


•	Our retail segment includes company-operated convenience stores in the U.S. and Canada; and filling stations, cardlock facilities, and heating oil operations in Canada. The retail segment is segregated into two geographic regions. Our retail operations in the U.S. are referred to as Retail–U.S. and our retail operations in Canada are referred to as Retail–Canada.

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VALERO’S OPERATIONS

REFINING

On December 31, 2012, our refining operations included 16 refineries in the U.S., Canada, the U.K., and Aruba, with a combined total throughput capacity of approximately 3.0 million barrels per day (BPD). The following table presents the locations of these refineries and their approximate feedstock throughput capacities as of December 31, 2012.



Refinery	Location	Throughput Capacity ^(a) (BPD)
U.S. Gulf Coast:
Corpus Christi ^(b)	Texas	325,000
Port Arthur	Texas	310,000
St. Charles	Louisiana	270,000
Texas City	Texas	245,000
Aruba ^(c)	Aruba	235,000
Houston	Texas	160,000
Meraux	Louisiana	135,000
Three Rivers	Texas	100,000
		1,780,000

U.S. Mid-Continent:
Memphis	Tennessee	195,000
McKee	Texas	170,000
Ardmore	Oklahoma	90,000
		455,000

North Atlantic:
Pembroke	Wales, U.K.	270,000
Quebec City	Quebec, Canada	235,000
		505,000

U.S. West Coast:
Benicia	California	170,000
Wilmington	California	135,000
		305,000
Total		3,045,000


^(a)	“Throughput capacity” represents estimated capacity for processing crude oil, intermediates, and other feedstocks. Total estimated crude oil capacity is approximately 2.6 million BPD.


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


^(c)	The operations of the Aruba Refinery were suspended in March 2012. For further discussion of this matter, see Note 4 in Notes to Consolidated Financial Statements.

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Total Refining System

The following table presents the percentages of principal charges and yields (on a combined basis) for all of our refineries for the year ended December 31, 2012. Our total combined throughput volumes averaged 2.6 million BPD for the year ended December 31, 2012.



Combined Total Refining System Charges and Yields

Charges:
	sour crude oil	38	%
	acidic sweet crude oil	3	%
	sweet crude oil	35	%
	residual fuel oil	8	%
	other feedstocks	5	%
	blendstocks	11	%
Yields:
	gasolines and blendstocks	47	%
	distillates	35	%
	petrochemicals	3	%
	other products (includes petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, and asphalt)	15	%

U.S. 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, 2012. Total throughput volumes for the U.S. Gulf Coast refining region averaged 1.49 million BPD for the year ended December 31, 2012.



Combined U.S. Gulf Coast Region Charges and Yields

Charges:
	sour crude oil	53	%
	acidic sweet crude oil	2	%
	sweet crude oil	14	%
	residual fuel oil	13	%
	other feedstocks	5	%
	blendstocks	13	%
Yields:
	gasolines and blendstocks	44	%
	distillates	34	%
	petrochemicals	4	%
	other products (includes gas oil, No. 6 fuel oil, petroleum coke, and asphalt)	18	%

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Corpus Christi East and West Refineries. Our Corpus Christi East and West Refineries are located on the Texas Gulf Coast along the Corpus Christi Ship Channel. The East Refinery processes sour crude oil into conventional gasoline, diesel, jet fuel, asphalt, aromatics, and other light products. The West Refinery specializes in processing primarily sour crude oil and residual fuel oil into premium products such as RBOB. The East and West Refineries allow for the transfer of various feedstocks and blending components between the two refineries and the sharing of resources. The refineries typically receive and deliver feedstocks and products by tanker and barge via deepwater docking facilities along the Corpus Christi Ship Channel. Three truck racks with a total of 16 bays service local markets for gasoline, diesel, jet fuels, liquefied petroleum gases, and asphalt. Finished products are distributed across the refineries’ docks into ships or barges, and are transported via third-party pipelines to the Colonial, Explorer, Valley, and other major pipelines.

Port Arthur Refinery. Our Port Arthur Refinery is located on the Texas Gulf Coast approximately 90 miles east of Houston. The refinery processes primarily heavy sour crude oils and other feedstocks into gasoline, diesel, jet fuel, petrochemicals, intermediates, petroleum coke, and sulfur. In 2012, we completed construction of a 57,000 BPD hydrocracker at this refinery, expanding the refinery’s yield of distillates. The refinery receives crude oil over marine docks and through crude oil pipelines, and has access to the Sunoco and Oiltanking terminals at Nederland, Texas. Finished products are distributed into the Colonial, Explorer, and TEPPCO pipelines and across the refinery docks into ships or barges.

St. Charles Refinery. Our St. Charles Refinery is located approximately 15 miles from New Orleans along the Mississippi River. The refinery processes sour crude oils and other feedstocks into gasoline, distillates, and other light products. In 2012, we continued construction on a planned 60,000 BPD hydrocracker at this refinery, which is expected to be completed in the second quarter of 2013. The refinery receives crude oil over five marine docks and has access to the Louisiana Offshore Oil Port where it can receive crude oil through a 24-inch pipeline. Finished products can be shipped over these docks or through the Colonial pipeline network for distribution to the eastern U.S.

Texas City Refinery. Our Texas City Refinery is located southeast of Houston on the Texas City Ship Channel. The refinery processes sour crude oils into a wide slate of products. The refinery receives and delivers its feedstocks and products by ship and barge via deepwater docking facilities along the Texas City Ship 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 a mix of crude oils and intermediate oils into reformulated gasoline and distillates. The refinery receives its feedstocks via interstate crude pipelines, tankers at deepwater docking facilities along the Houston Ship Channel and interconnecting pipelines with the Texas City Refinery. It delivers its products through major refined-product pipelines, including the Colonial, Explorer, Orion, and TEPPCO pipelines.

Meraux Refinery. Our Meraux Refinery is located in St. Bernard Parish southeast of New Orleans. The refinery processes primarily medium sour crude oils into gasoline, distillates, and other light products. The refinery receives crude oil at its marine dock and has access to the Louisiana Offshore Oil Port where it can receive crude oil via the Clovelly-Alliance-Meraux pipeline system. Finished products can be shipped from the refinery’s dock or through the Colonial pipeline network for distribution to the eastern U.S. The Meraux Refinery is located about 40 miles from our St. Charles Refinery, allowing for integration of feedstocks and refined product blending.

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Three Rivers Refinery. Our Three Rivers Refinery is located in South Texas between Corpus Christi and San Antonio. It processes sweet and medium sour crude oils into gasoline, distillates, and aromatics. The refinery has access to crude oil from sources outside the U.S. delivered to the Texas Gulf Coast at Corpus Christi as well as crude oil from U.S. sources through third-party pipelines and trucks. A 70-mile pipeline transports crude oil via connections to the Three Rivers Refinery from Corpus Christi. To capitalize on the increase in the production of domestic crude oil in South Texas, the refinery has installed facilities to receive domestic crude oil by truck and new third-party pipelines. The refinery distributes its refined products primarily through third-party pipelines.

Aruba Refinery. Our Aruba Refinery is located on the island of Aruba in the Caribbean Sea. The refinery heretofore processed primarily heavy sour crude oil and produced intermediate feedstocks and finished distillate products. The refinery receives crude oil by ship at its two deepwater marine docks, which can berth ultra-large crude carriers. The operations of the Aruba Refinery were suspended in March 2012, and in September 2012, we decided to reorganize the refinery into a crude oil and refined products terminal. We intend to maintain the refinery to allow it to be restarted and do not consider it to be abandoned. For additional information about this matter, see Note 4 of Notes to Consolidated Financial Statements.

U.S. Mid-Continent

The following table presents the percentages of principal charges and yields (on a combined basis) for the three refineries in this region for the year ended December 31, 2012. Total throughput volumes for the U.S. Mid-Continent refining region averaged approximately 430,000 BPD for the year ended December 31, 2012.



Combined U.S. Mid-Continent Region Charges and Yields

Charges:
	sour crude oil	9	%
	sweet crude oil	81	%
	other feedstocks	1	%
	blendstocks	9	%
Yields:
	gasolines and blendstocks	54	%
	distillates	36	%
	petrochemicals	4	%
	other products (includes gas oil, No. 6 fuel oil, and asphalt)	6	%

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

McKee Refinery. Our McKee Refinery is located in the Texas Panhandle. It processes primarily sweet crude oils into conventional gasoline, RBOB, low-sulfur diesel, jet fuels, and asphalt. The refinery has access to crude oil from Texas, Oklahoma, Kansas, and Colorado through third-party pipelines. The refinery also has access at Wichita Falls, Texas to third-party pipelines that transport crude oil from West Texas to the U.S.

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Mid-Continent region. The refinery distributes its products primarily via third-party pipelines to markets in Texas, New Mexico, Arizona, Colorado, and Oklahoma.

Ardmore Refinery. Our Ardmore Refinery is located in Ardmore, Oklahoma, approximately 100 miles south of Oklahoma City. It processes medium sour and sweet crude oils into conventional gasoline, ultra-low-sulfur diesel, liquefied petroleum gas products, and asphalt. Local crude oil is gathered by Enterprise’s crude oil gathering/trunkline systems and trucking operations, and is then transported to the refinery through third-party crude oil pipelines. The refinery also receives crude oil from other locations via third-party pipelines. Refined products are transported to market via railcars, trucks, and the Magellan pipeline system.

North Atlantic

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, 2012. Total throughput volumes for the North Atlantic refining region averaged approximately 428,000 BPD for the year ended December 31, 2012.



Combined North Atlantic Region Charges and Yields

Charges:
	sour crude oil	2	%
	acidic sweet crude oil	6	%
	sweet crude oil	81	%
	residual fuel oil	2	%
	other feedstocks	2	%
	blendstocks	7	%
Yields:
	gasolines and blendstocks	43	%
	distillates	44	%
	petrochemicals	1	%
	other products (includes gas oil, No. 6 fuel oil, and other products)	12	%

Pembroke Refinery. Our Pembroke Refinery is located in the County of Pembrokeshire in southwest Wales, U.K. The refinery processes primarily sweet crude oils into ultra-low sulfur gasoline and diesel, jet fuel, heating oil, and low sulfur fuel oil. The refinery receives all of its feedstocks and delivers the majority of its products by ship and barge via deepwater docking facilities along the Milford Haven Waterway with its remaining products being delivered by our Mainline pipeline system and by tanker trucks.

Quebec City Refinery. Our Quebec City Refinery is located in Lévis, Canada (near Quebec City). It processes sweet, high mercaptan crude oils and lower-quality, sweet acidic crude oils into conventional gasoline, low-sulfur diesel, jet fuel, heating oil, and propane. The refinery receives crude oil by ship at its deepwater dock on the St. Lawrence River. The refinery transports its products through our pipeline (commissioned in December 2012) from Quebec to our terminal in Montreal and to various other terminals throughout eastern Canada by trains, ships, truck and third-party pipeline.

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U.S. 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, 2012. Total throughput volumes for the U.S. West Coast refining region averaged approximately 267,000 BPD for the year ended December 31, 2012.



Combined U.S. West Coast Region Charges and Yields

Charges:
	sour crude oil	62	%
	acidic sweet crude oil	11	%
	sweet crude oil	4	%
	other feedstocks	10	%
	blendstocks	13	%
Yields:
	gasolines and blendstocks	62	%
	distillates	25	%
	other products (includes gas oil, No. 6 fuel oil, petroleum coke, and asphalt)	13	%

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, a reformulated gasoline mixture that meets the specifications of the CARB when blended with ethanol. The refinery receives crude oil feedstocks via a marine dock that can berth large crude oil carriers and a 20-inch crude oil pipeline connected to a southern California crude oil delivery system. Most of the refinery’s products are distributed via the Kinder Morgan pipeline system in California.

Wilmington Refinery. Our Wilmington 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 ultra-low-sulfur diesel, CARB diesel, and jet fuel. The refinery is connected by pipeline to marine terminals and associated dock facilities that can move and store crude oil and other feedstocks. Refined products are distributed via the Kinder Morgan pipeline system and various third-party terminals in southern California, Nevada, and Arizona.

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Feedstock Supply

Approximately 77 percent of our current crude oil feedstock requirements are purchased through term contracts while the remaining requirements are generally purchased on the spot market. Our term supply agreements include arrangements to purchase feedstocks at market-related prices directly or indirectly from various national oil companies as well as international and U.S. oil companies. The contracts generally permit the parties to amend the contracts (or terminate them), effective as of the next scheduled renewal date, by giving the other party proper notice within a prescribed period of time (e.g., 60 days, 6 months) before expiration of the current term. The majority of the crude oil purchased under our term contracts is purchased at the producer’s official stated price (i.e., the “market” price established by the seller for all purchasers) and not at a negotiated price specific to us.

The U.S. network of crude oil pipelines and terminals allows us to acquire crude oil from producing leases, crude oil trading centers, and ships delivering cargoes of crude oil. Our Pembroke and Quebec City Refineries rely on crude oil that is delivered to the refineries’ dock facilities by ship.

In 2012, our refining business benefited from processing sweet crude oils sourced from the inland U.S. This development is discussed further in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Outlook.”

Refining Segment Sales

Overview

Our refining segment includes sales of refined products in both the wholesale rack and bulk markets. These sales include refined products that are manufactured in our refining operations as well as refined products purchased or received on exchange from third parties. Most of our refineries have access to marine transportation facilities and interconnect with common-carrier pipeline systems, allowing us to sell products in the U.S., Canada, the U.K., and other countries. No customer accounted for more than 10 percent of our total operating revenues in 2012.

Wholesale Marketing

We market branded and unbranded refined products on a wholesale basis through an extensive rack marketing network. The principal purchasers of our refined products from terminal truck racks are wholesalers, distributors, retailers, and truck-delivered end users throughout the U.S., the U.K., and Ireland.

The majority of our rack volume is sold through unbranded channels. The remainder is sold to distributors and dealers that are members of the Valero-brand family that operate approximately 4,450 branded sites in the U.S. and approximately 1,000 branded sites in the U.K. and Ireland. These sites are independently owned and are supplied by us under multi-year contracts. For wholesale branded sites, we promote our Valero^®, Beacon^®, and Shamrock^® brands in the U.S., and the Texaco^® brand in the U.K. and Ireland.

Bulk Sales and Trading

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

We also enter into refined product exchange and purchase agreements. These agreements help minimize transportation costs, optimize refinery utilization, balance refined product availability, broaden geographic

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distribution, and provide access to markets not connected to our refined-product pipeline systems. Exchange agreements provide for the delivery of refined products by us to unaffiliated companies at our and third-parties’ terminals in exchange for delivery of a similar amount of refined products to us by these unaffiliated companies at specified locations. Purchase agreements involve our purchase of refined products from third parties with delivery occurring at specified locations.

Specialty Products

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


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


•	We produce naphthenic oils at one of our refineries suitable for a wide variety of lubricant and process applications.


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


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


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


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

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ETHANOL

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

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

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



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

The combined ethanol production from our plants in 2012 averaged 3.0 million gallons per day.

________________________

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

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

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RETAIL

Our retail segment operations include:


•	the sale of motor fuel at convenience stores, filling stations, and cardlocks;


•	the sale of convenience merchandise items and services at our convenience stores; and


•	the sale of heating oil to residential customers and heating oil and motor fuel to small commercial customers.

We are one of the largest independent retailers of motor fuel in the central and southwest U.S. and eastern Canada. Our retail operations are segregated geographically into two groups: Retail–U.S. and Retail–Canada.

We plan to separate our retail business under a new company named CST Brands, Inc. (CST). CST is a wholly owned subsidiary of Valero Energy Corporation. The separation is planned by way of a pro rata distribution of 80 percent of the outstanding shares of CST common stock to Valero stockholders. For a further discussion of the planned separation, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Outlook.”

Retail–U.S.

Sales in Retail–U.S. represent sales of motor fuel and convenience merchandise items and services through our company-operated convenience stores. For the year ended December 31, 2012, total sales of motor fuel through Retail–U.S.’s sites averaged 122,583 BPD. In addition to motor fuel, our company-operated stores sell convenience-type items, such as tobacco products, beer, snacks and beverages, and fast foods. Our stores also offer services such as ATM access, money orders, lottery tickets, car wash facilities, air and water, and video rentals. On December 31, 2012, we had 1,032 company-operated convenience stores in Retail–U.S. (of which 833 were owned and 199 were leased). Our company-operated convenience stores are operated primarily under the Corner Store^®brand name. Motor fuel sold in our Retail–U.S. stores are sold primarily under the Valero^® brand.

Retail–Canada

Sales in Retail–Canada include:


•	the sale of motor fuel and convenience merchandise items through our company-operated convenience stores and cardlocks,


•	the sale of motor fuel through filling stations owned and operated by independent dealers or agents where we retain title to the motor fuel and sell it directly to our customers, and


•	the sale of heating oil to residential and small commercial customers.

Retail–Canada includes retail operations in eastern Canada where we are a major supplier of motor fuel serving Quebec, Ontario, Newfoundland and Labrador, Nova Scotia, New Brunswick, and Prince Edward Island. For the year ended December 31, 2012, total retail sales of motor fuel through Retail–Canada averaged approximately 68,100 BPD. Motor fuel is sold under the Ultramar^® brand through a network of 848 retail sites throughout eastern Canada. On December 31, 2012, we owned or leased 261 convenience stores in Retail–Canada and sold motor fuel through 507 filling stations. In addition, Retail–Canada operates 80 cardlocks, which are card- or key-activated, self-service, unattended filling stations that allow commercial, trucking, and governmental fleets to buy motor fuel 24 hours a day. Retail–Canada operations also include the sale of heating oil to residential customers and heating oil and motor fuel to small commercial customers in eastern Canada. Our heating oil business is seasonal to the extent of increased demand for heating oil during the winter.

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RISK FACTORS

Risk Factors Related to Our Business

Our financial results are affected by volatile refining margins, which are dependent upon factors beyond our control.

Our financial results are primarily affected by the relationship, or margin, between refined product prices and the prices for crude oil and other feedstocks. Our cost to acquire feedstocks and the price at which we can ultimately sell refined products depend upon several factors beyond our control, including regional and global supply of and demand for crude oil, gasoline, diesel, and other feedstocks and refined products. These in turn depend on, among other things, the availability and quantity of imports, the production levels of U.S. and international suppliers, levels of refined product inventories, productivity and growth (or the lack thereof) of U.S. and global economies, U.S. relationships with foreign governments, political affairs, and the extent of governmental regulation. Historically, refining margins have been volatile, and we believe they will continue to be volatile in the future.

Economic turmoil and political unrest or hostilities, including the threat of future terrorist attacks, could affect the economies of the U.S. and other countries. Lower levels of economic activity could result in declines in energy consumption, including declines in the demand for and consumption of our refined products, which could cause our revenues and margins to decline and limit our future growth prospects.

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

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

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

Our ability to obtain credit and capital depends in large measure on capital markets and liquidity factors that we do not control. Our ability to access credit and capital markets may be restricted at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. In addition, the cost and availability of debt and equity financing may be adversely impacted by unstable or illiquid market conditions. Protracted uncertainty and illiquidity in these markets also could have an adverse impact on our lenders, commodity hedging counterparties, or our customers, causing them to fail to meet their obligations to us. In addition, decreased returns on pension fund assets may also materially increase our pension funding requirements.

Our access to credit and capital markets also depends on the credit ratings assigned to our debt by independent credit rating agencies. We currently maintain investment-grade ratings by Standard & Poor’s Ratings Services (S&P), Moody’s Investors Service (Moody’s), and Fitch Ratings (Fitch) on our senior unsecured debt. (Ratings from credit agencies are not recommendations to buy, sell, or hold our securities. Each rating should be evaluated independently of any other rating.) We cannot provide assurance that any of our current ratings

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will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Specifically, if S&P, Moody’s, or Fitch were to downgrade our long-term rating, particularly below investment grade, our borrowing costs would increase, which could adversely affect our ability to attract potential investors and our funding sources could decrease. In addition, we may not be able to obtain favorable credit terms from our suppliers or they may require us to provide collateral, letters of credit, or other forms of security which would increase our operating costs. As a result, a downgrade below investment grade in our credit ratings could have a material adverse impact on our financial position, results of operations, and liquidity.

From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we were unable to obtain necessary funds from financing activities. From time to time, we may need to supplement our cash generated from operations with proceeds from financing activities. We have existing revolving credit facilities, committed letter of credit facilities, and an accounts receivable sales facility to provide us with available financing to meet our ongoing cash needs. In addition, we rely on the counterparties to our derivative instruments to fund their obligations under such arrangements. Uncertainty and illiquidity in financial markets may materially impact the ability of the participating financial institutions and other counterparties to fund their commitments to us under our various financing facilities or our derivative instruments, which could have a material adverse effect on our financial position, results of operations, and liquidity.

Compliance with and changes in environmental laws, including proposed climate change laws and regulations, could adversely affect our performance.

The principal environmental risks associated with our operations are emissions into the air and releases into the soil, surface water, or groundwater. Our operations are subject to extensive 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. Certain of these laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities as well as at formerly owned properties or third-party sites where we have taken wastes for disposal or where our wastes have migrated. Environmental laws and regulations also may impose liability on us for the conduct of third parties, or for actions that complied with applicable requirements when taken, regardless of negligence or fault. If we violate or fail to comply with these laws and regulations, we could be fined or otherwise sanctioned.

Because environmental laws and regulations are becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, such as those relating to greenhouse gas emissions and climate change, the level of expenditures required for environmental matters could increase in the future. Current and future legislative action and regulatory initiatives could result in changes to operating permits, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we sell, and decreased demand for our products that cannot be assessed with certainty at this time. We may be required to make expenditures to modify operations or install pollution control equipment that could materially and adversely affect our business, financial condition, results of operations, and liquidity. For example, in 2012, the U.S. Environmental Protection Agency (EPA) proposed more stringent requirements for refinery air emissions through revisions to existing New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants. The EPA also issued final amendments to Subpart Ja of the New Source Performance Standards, which included revisions to certain emission limits, monitoring requirements, fuel gas concentration limits, and waste gas flow limits for process heaters and flares. In addition, the EPA has, in recent years, adopted final rules making more stringent the National

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Ambient Air Quality Standards (NAAQS) for ozone, sulfur dioxide and nitrogen dioxide, and the EPA is considering further revisions to the NAAQS. Emerging rules and permitting requirements implementing these revised standards may require us to install more stringent controls at our facilities, which may result in increased capital expenditures. Governmental restrictions on greenhouse gas emissions – including so-called “cap-and-trade” programs targeted at reducing carbon dioxide emissions – could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of, and reduction in demand for, the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

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

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

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

We are subject to interruptions of supply and increased costs as a result of our reliance on third-party transportation of crude oil and refined products.

We often use the services of third parties to transport feedstocks and refined products to and from our facilities. If we experience prolonged interruptions of supply or increases in costs to deliver refined products to market, or if the ability of the pipelines or vessels to transport feedstocks or refined products is disrupted because of weather events, accidents, governmental regulations, or third-party actions, it could have a material adverse effect on our financial position, results of operations, and liquidity.

Competitors that produce their own supply of feedstocks, have more extensive retail sites, have greater financial resources, or provide alternative energy sources may have a competitive advantage.

The refining and marketing industry is highly competitive with respect to both feedstock supply and refined product markets. We compete with many companies for available supplies of crude oil and other feedstocks and for sites for our refined products. We do not produce any of our crude oil feedstocks and, following the proposed separation of our retail business, will not have a company-owned retail network. Many of our competitors, however, obtain a significant portion of their feedstocks from company-owned production and some have extensive retail sites. Such competitors are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.

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

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

Our refineries are our principal operating assets. As a result, our operations could be subject to significant interruption if one or more of our refineries were to experience a major accident or mechanical failure, encounter work stoppages relating to organized labor issues, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs. Significant interruptions in our refining system could also lead to increased volatility in prices for crude oil feedstocks and refined products, and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain insurance coverage that we consider adequate.

In addition, our information technology systems and network infrastructure may be subject to unauthorized access or attack, which could result in a loss of sensitive business information, systems interruption, or the disruption of our business operations. There can be no assurance that our infrastructure protection technologies and disaster recovery plans can prevent a technology systems breach or systems failure, which could have a material adverse effect on our financial position or results of operations.

We are subject to operational risks and our insurance may not be sufficient to cover all potential losses arising from operating hazards. Failure by one or more insurers to honor its coverage commitments for an insured event could materially and adversely affect our financial position, results of operations, and liquidity.

Our refining and marketing operations are subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards, and natural catastrophes. As protection against these hazards, we maintain insurance coverage against some, but not all, such potential losses and liabilities. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase substantially. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, coverage for hurricane damage is very limited, and coverage for terrorism risks includes very broad exclusions. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.

Our insurance program includes a number of insurance carriers. Significant disruptions in financial markets could lead to a deterioration in the financial condition of many financial institutions, including insurance companies. We can make no assurances that we will be able to obtain the full amount of our insurance coverage for insured events.

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

We are subject to extensive tax liabilities imposed by multiple jurisdictions, including income taxes, indirect taxes (excise/duty, sales/use, gross receipts, and value-added taxes), payroll taxes, franchise taxes,

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withholding taxes, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Many of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties.

We may incur losses as a result of our forward-contract activities and derivative transactions.

We currently use commodity derivative instruments, and we expect to continue their use in the future. If the instruments we use to hedge our exposure to various types of risk are not effective, we may incur losses.

Risk Factors Related to the Planned Separation of our Retail Business

Risks associated with the separation of CST.

Our planned separation of CST is subject to a number of risks, including the following:

Risk of Non-Consummation. Although we expect to distribute 80 percent of the shares of CST common stock to Valero stockholders, the distribution remains subject to conditions, including, but not limited to: (i) the SEC having declared effective CST’s registration statement on Form 10; (ii) the receipt of a private letter ruling from the Internal Revenue Service (IRS) to the effect that the distribution, together with certain related transactions, will qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Internal Revenue Code of 1986, as amended (Code); and (iii) the receipt of an opinion from a nationally recognized investment banking firm or other authority confirming the solvency and financial viability of CST after the distribution. There can be no assurance that any or all of these conditions will be met and that the distribution will be completed in the manner currently contemplated, or at all. In addition, the fulfillment of these conditions does not create any obligations on our part to effect the distribution, and our board of directors has reserved the right, in its sole discretion, to abandon, modify, or change the terms of the distribution.

Risks of Not Obtaining Benefits from the Separation. We and CST may not realize some or all of the benefits we expect from the separation in the time frame currently contemplated, or at all.

Risks Relating to Less Diversification. If the distribution is completed, our diversification of revenue sources will diminish due to the separation of CST from our other businesses, and it is possible that our results of operations, cash flows, working capital and financing requirements may be subject to increased volatility as a result.

Risks Relating to Taxes. We are seeking a private letter ruling from the IRS substantially to the effect that, for U.S. federal income tax purposes, the distribution of 80 percent of the shares of CST common stock, except for cash received in lieu of fractional shares, will qualify as tax-free under Sections 355 and 361 of the Code, and that certain internal transactions undertaken in anticipation of the distribution will qualify for favorable treatment. Notwithstanding the private letter ruling, the IRS could determine on audit that the distribution or the internal transactions should be treated as taxable transactions if it determines that any of the facts, assumptions, representations, or undertakings we or CST have made or provided to the IRS is not correct, or that the distribution or the internal transactions should be taxable for other reasons, including as a result of a significant change in stock or asset ownership after the distribution. If the distribution ultimately is determined to be taxable, we and/or our stockholders that are subject to U.S. federal income tax could incur significant U.S. federal income tax liabilities.

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Risks Relating to Post-Separation Share Value. Until the market has fully analyzed the value of our company after the distribution, we may experience more stock price volatility than usual. In addition, it is possible that the combined trading prices of our common stock and CST common stock immediately after the distribution will be less than the trading price of shares of our common stock immediately before the distribution.

Our minority investment in CST will be subject to certain risks and uncertainties and we may not be able to capture the full benefits from this investment.

After the distribution, we expect to retain 20 percent of the outstanding shares of CST common stock. As with any investment in a publicly traded company, our investment in CST will be subject to certain risks and uncertainties, which are disclosed in more detail in CST’s filings with the SEC. In addition, in connection with the separation, we will agree, and will grant to CST a proxy, to vote all of the shares of CST common stock that we retain in proportion to the votes cast by CST’s other stockholders. As a result, after the distribution, we may be required to vote our shares of CST common stock in a manner that is contrary to the manner we would otherwise have voted such shares.

We currently plan to dispose of all of the shares of CST common stock we will retain after the distribution through one or more exchanges for our indebtedness outstanding at the time of such exchange. We expect that pursuant to the private letter ruling we are seeking from the IRS in connection with the distribution, we will be required to dispose of any shares we do not dispose of pursuant to such exchanges as soon as practicable and consistent with our reasons for retaining such shares, but in no event later than five years after the distribution in connection with the separation. As a result, we may be required to sell some or all of our retained shares of CST common stock at a time when we might not otherwise choose to do so, and any such disposition in the public market, or the perception that such dispositions could occur, could adversely affect prevailing market prices for CST common stock and/or the value or the terms of such disposition.

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ENVIRONMENTAL MATTERS

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


•	Item 1 under the caption “Risk Factors – Compliance with and changes in environmental laws, including proposed climate change laws and regulations, could adversely affect our performance,”


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


•	Item 8, “Financial Statements and Supplementary Data” in Note 10 of Notes to Consolidated Financial Statements under the caption “Environmental Liabilities” and Note 12 of Notes to Consolidated Financial Statements under the caption “Environmental Matters.”

Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2012, our capital expenditures attributable to compliance with environmental regulations were $135 million, and are currently estimated to be $100 million for 2013 and $70 million for 2014. The estimates for 2013 and 2014 do not include amounts related to capital investments at our facilities that management has deemed to be strategic investments. These amounts could materially change as a result of governmental and regulatory actions.

PROPERTIES

Our principal properties are described above under the caption “Valero’s Operations,” and that information is incorporated herein by reference. We also own feedstock and refined product storage and transportation facilities in various locations. We believe that our properties and facilities are generally adequate for our operations and that our facilities are maintained in a good state of repair. As of December 31, 2012, we were the lessee under a number of cancelable and noncancelable leases for certain properties. Our leases are discussed more fully in Notes 11 and 12 of Notes to Consolidated Financial Statements.

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 3. LEGAL PROCEEDINGS

Litigation

We incorporate by reference into this Item our disclosures made in Part II, Item 8 of this report included in Note 12 of Notes to Consolidated Financial Statements under the caption “Litigation Matters.”

Environmental Enforcement Matters

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

EPA (Linden ethanol plant). In the third quarter of 2012, the EPA issued a notice of violation (NOV) to our Linden, Indiana ethanol plant. The EPA seeks penalties of $205,000, alleging excess air emissions. We are evaluating our response to the NOV.

EPA (Port Arthur Refinery). In our annual report on Form 10-K for the year ended December 31, 2011, and in our quarterly report on Form 10-Q for the quarter ended March 31, 2012, we reported potential stipulated penalties payable to the EPA and the Texas Commission on Environmental Quality (TCEQ) relating to certain flaring events at our Port Arthur Refinery. In the third quarter of 2012, we received a total stipulated penalty demand of $5,197,500 for the flaring events. In the fourth quarter of 2012, we paid the demanded amount resolving this matter with the EPA.

Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery). We currently have 104 outstanding Violation Notices (VNs) issued by the BAAQMD. These VNs are for various alleged air regulation and air permit violations at our Benicia Refinery and asphalt plant.

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

South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). In our annual report on Form 10-K for the year ended December 31, 2011, we reported that our Wilmington Refinery received a penalty demand from the SCAQMD due to excess flare related emissions in 2011. In 2012, we paid mitigation fees under SCAQMD Rule 1118 to resolve the matter.

SCAQMD (Wilmington Refinery). In the fourth quarter of 2012, the SCAQMD issued three NOVs to our Wilmington Refinery for alleged reporting violations and excess emissions, which we reasonably believe may result in penalties of $100,000 or more. We are evaluating the NOVs.

TCEQ (Port Arthur Refinery). In our quarterly report on Form 10-Q for the quarter ended March 31, 2012, we reported that our Port Arthur Refinery received a proposed agreed order from the TCEQ that assessed a penalty of $180,911 for various alleged air emission and reporting violations. We are working with the TCEQ to resolve this matter.

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TCEQ (Port Arthur Refinery). In the fourth quarter of 2012, the TCEQ issued a Notice of Enforcement (NOE) for unauthorized flare emissions. We are evaluating the NOE. Potential stipulated penalties under our EPA §114 Clean Air Act Consent Decree for these three incidents are expected to be $166,000 if the EPA issues a stipulated penalty demand letter for these events.

ITEM 4. MINE SAFETY DISCLOSURES

None.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

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

As of January 31, 2013, there were 7,305 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 2012 and 2011.



	Sales Prices of the Common Stock				Dividends Per Common Share
Quarter Ended	High		Low		Dividends Per Common Share
2012:
December 31	$	34.38	$	28.20	$	0.175
September 30	33.75		23.64		0.175
June 30	26.33		20.37		0.150
March 31	28.56		19.61		0.150
2011:
December 31	26.70		17.17		0.150
September 30	26.89		17.78		0.050
June 30	30.50		23.18		0.050
March 31	30.73		23.19		0.050

On January 23, 2013, our board of directors declared a quarterly cash dividend of $0.20 per common share payable March 13, 2013 to holders of record at the close of business on February 13, 2013.

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

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The following table discloses purchases of shares of Valero’s common stock made by us or on our behalf during the fourth quarter of 2012.



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Not Purchased as Part of Publicly Announced Plans or Programs (a)	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (b)
October 2012	50,163	$	29.01	50,163	—	$ 3.46 billion
November 2012	927,587	$	30.43	427,587	500,000	$ 3.44 billion
December 2012	3,214,969	$	32.10	14,637	3,200,332	$ 3.34 billion
Total	4,192,719	$	31.69	492,387	3,700,332	$ 3.34 billion

(a)

The shares reported in this column represent purchases settled in the fourth quarter of 2012 relating to (i) our purchases of shares in open-market transactions to meet our obligations under incentive compensation plans, and (ii) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our incentive compensation plans.

(b)

On April 26, 2007, we publicly announced an increase in our common stock purchase program from $2 billion to $6 billion, as authorized by our board of directors on April 25, 2007. The $6 billion common stock purchase program has no expiration date. On February 28, 2008, we announced that our board of directors approved a $3 billion common stock purchase program, which is in addition to the $6 billion program. This $3 billion program has no expiration date.

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

This performance graph and the related textual information are based on historical data and are not indicative of future performance. The following line graph compares the cumulative total return¹ on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (that we selected) for the five-year period commencing December 31, 2007 and ending December 31, 2012. Our peer group consists of the following ten companies: Alon USA Energy, Inc.; BP plc (BP); CVR Energy, Inc.; Hess Corporation; HollyFrontier Corporation; Marathon Petroleum Corporation; Phillips 66 (PSX); Royal Dutch Shell plc (RDS); Tesoro Corporation; and Western Refining, Inc. Our peer group previously included Chevron Corporation (CVX) and Exxon Mobil Corporation (XOM) but they were replaced with BP, PSX, and RDS. In 2012, PSX became an independent downstream energy company and was added to our peer group. CVX and XOM were replaced with BP and RDS as they were viewed as having operations that more closely aligned with our core businesses.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN¹

Among Valero Energy Corporation, the S&P 500 Index,

Old Peer Group, and New Peer Group



	12/2007		12/2008		12/2009		12/2010		12/2011		12/2012
Valero Common Stock	$	100.00	$	31.45	$	25.09	$	35.01	$	32.26	$	53.61
S&P 500	100.00		63.00		79.67		91.67		93.61		108.59
Old Peer Group	100.00		80.98		76.54		88.41		104.33		111.11
New Peer Group	100.00		66.27		86.87		72.84		74.70		76.89

____________


¹	Assumes that an investment in Valero common stock and each index was $100 on December 31, 2007. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from December 31, 2007 through December 31, 2012.

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ITEM 6. SELECTED FINANCIAL DATA

The selected financial data for the five-year period ended December 31, 2012 was derived from our audited financial statements. The following table should be read together with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with the historical financial statements and accompanying notes included in Item 8, “Financial Statements and Supplementary Data.”

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



	Year Ended December 31,
	2012 (a)		2011 (b)		2010 (c)		2009 (c)			2008
Operating revenues	$	139,250	$	125,987	$	82,233	$	64,599		$	106,676
Income (loss) from continuing operations	2,080		2,096		923		(273		)	(1,154		)
Earnings per common share from continuing operations – assuming dilution	3.75		3.69		1.62		(0.50		)	(2.20		)
Dividends per common share	0.65		0.30		0.20		0.60			0.57
Total assets	44,477		42,783		37,621		35,572			34,417
Debt and capital lease obligations, less current portion	6,463		6,732		7,515		7,163			6,264

___________________________


(a)	The operations of the Aruba Refinery were suspended in March 2012, as further described in Note 4 in Notes to Consolidated Financial Statements.


(b)	We acquired the Meraux Refinery on October 1, 2011 and the Pembroke Refinery on August 1, 2011. The information presented for 2011 includes the results of operations from these acquisitions commencing on their respective acquisition dates.


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

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following review of our results of operations and financial condition should be read in conjunction with Items 1, 1A, and 2, “Business, Risk Factors, and Properties,” and Item 8, “Financial Statements and Supplementary Data,” included in this report.

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

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

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


•	future refining margins, including gasoline and distillate margins;


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


•	future ethanol margins;


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


•	anticipated levels of crude oil and refined product inventories;


•	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 these capital investments on our results of operations;


•	anticipated trends in the supply of and demand for crude oil and other feedstocks and refined products globally and in the regions where we operate;


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


•	the effect of general economic and other conditions on refining, retail, and ethanol 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 produce crude oil or consume refined products;


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


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

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


•	the level of consumer demand, including seasonal fluctuations;


•	refinery overcapacity or undercapacity;


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


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


•	the level of competitors’ imports into markets that we supply;


•	accidents, unscheduled shutdowns, or other catastrophes affecting our refineries, machinery, pipelines, equipment, and information systems, or those of our suppliers or customers;


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


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


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


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


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


•	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 legislation or rulemakings by governmental authorities, including tax and environmental regulations, such as those to be implemented under the California Global Warming Solutions Act (also known as AB 32) and the EPA’s regulation of greenhouse gases, 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, the pound sterling, and the euro relative to the U.S. dollar;


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


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

Any one of these factors, or a combination of these factors, could materially affect our future results of operations and whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-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 any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

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OVERVIEW AND OUTLOOK

Overview

For the year ended December 31, 2012, we reported net income attributable to Valero stockholders from continuing operations of $2.1 billion, or $3.75 per share (assuming dilution), which was comparable to the $2.1 billion, or $3.69 per share (assuming dilution), in net income attributable to Valero stockholders from continuing operations for the year ended December 31, 2011. Included in our 2012 results, however, were noncash asset impairment losses totaling $983 million after taxes, or $1.77 per share (assuming dilution), primarily related to the impairment of the refining assets of our Aruba Refinery in connection with our decision in September 2012 to reorganize the refinery into a crude oil and refined products terminal. This matter is more fully discussed in Note 4 of Notes to Consolidated Financial Statements.

Our operating income increased $330 million from 2011 to 2012 as outlined by business segment in the following table (in millions):



	Year Ended December 31,
	2012			2011			Change
Operating income (loss) by business segment:
Refining	$	4,450		$	3,516		$	934
Retail	348			381			(33		)
Ethanol	(47		)	396			(443		)
Corporate	(741		)	(613		)	(128		)
Total	$	4,010		$	3,680		$	330

Operating income for 2012 was also negatively impacted by the noncash asset impairment losses discussed above, as well as severance expense of $41 million related to the operations at our Aruba Refinery, and operating income for 2011 was impacted by a $542 million loss on commodity derivative contracts related to forward sales of refined product. Excluding these significant items, total operating income for 2012 and 2011 would have been $5.1 billion and $4.2 billion, respectively, reflecting a $900 million favorable increase between the years, and refining segment operating income for 2012 and 2011 would have been $5.5 billion and $4.1 billion, respectively, reflecting a favorable increase of $1.4 billion between the years.

The $1.4 billion increase in refining segment operating income was primarily the result of improvements in the margin generated by our U.S. Mid-Continent and North Atlantic refining operations, which experienced increases in throughput margin of $2.58 per barrel and $3.81 per barrel, respectively, in 2012 compared to 2011. Our U.S. Mid-Continent region continued to benefit from the favorable difference between the price of Brent crude oil and WTI-type crude oil, which is the type of crude oil primarily processed by our refineries in this region. Because the market for refined products generally tracks the price of Brent crude oil, we benefit when the price of WTI-type crude oil is lower than the price of Brent crude oil. The favorable difference between the price of WTI and Brent crude oil improved by $1.67 per barrel in 2012 compared to 2011, which contributed significantly to the increase in the throughput margin generated by our operations in this region. The results of our North Atlantic region were favorably impacted by increases in refined product prices due largely to a reduction in the supply of refined products in this region as compared to the prior year. This reduction in supply resulted from the continued shutdown of refineries in the U.S. East Coast, Caribbean, and Western Europe during 2012, which was due to poor refining economics in these areas, and supply disruptions caused by Hurricane Sandy, which struck the U.S. East Coast in October 2012.

The favorable results of our refining segment were partially offset by the $443 million decrease in our ethanol segment’s operating income in 2012 compared to 2011. This decrease was due to significantly lower gross

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margins in 2012 caused by a combination of high corn prices and an oversupply of ethanol in the market. The increase in corn prices in 2012 was largely due to the severe drought experienced in grain producing regions of the U.S. in 2012, and the oversupply of ethanol inventories was largely attributable to lower exports of ethanol to Europe and increased imports of ethanol from Brazil.

Outlook

Throughout 2011 and 2012, our refining business benefited from processing sweet crude oils sourced from the inland U.S., such as WTI crude oil, due to the favorable difference between the price of this type of crude oil and the price of a benchmark sweet crude oil, such as Brent crude oil. Historically, the price of WTI-type crude oil has closely approximated Brent crude oil, but due to the significant development of crude oil reserves within the U.S. Mid-Continent region and increased deliveries of crude oil from Canada into the U.S. Mid-Continent region, the increased supply of WTI crude oil has resulted in WTI crude oil being priced at a significant discount to Brent crude oil. This benefit, however, may decline as various crude oil pipeline and logistics projects are completed. These projects will allow cost-advantaged crude oils from the inland U.S. and Canada to be transported to the U.S. Gulf Coast region, which is expected to result in a narrowing of the price differential of WTI-priced crude oils relative to Brent-priced crude oils. As a result, the margins for refined products for refiners that process WTI-priced crude oils may decline.

Continued refinery closures in the U.S. East Coast, Caribbean, and Western Europe and additional closures expected to occur in the industry combined with poor reliability and low utilization in Latin American refineries create opportunities for competitive refineries to export quality products at higher margins. However, some marginally profitable refineries may continue to be operated, which could negatively impact refined product margins.

Thus far in the first quarter of 2013, ethanol margins have improved, but the improvement is not significant and the margins remain far below those experienced in 2011. We expect a continued modest improvement in ethanol margins throughout 2013 relative to those in 2012.

Energy markets and margins are volatile, and we expect them to continue to be volatile in the near to mid-term.

We continue to make progress in the separation of our retail business under a new company named CST Brands, Inc. The separation is planned by way of a pro rata distribution of 80 percent of the outstanding shares of CST common stock to Valero stockholders. The distribution is expected to take place in the second quarter of 2013, assuming a favorable private letter ruling from the IRS and clearance of all comments from the SEC relating to CST’s registration statement on Form 10. When the distribution occurs, we expect to receive approximately $1.1 billion of cash and incur a tax liability of approximately $230 million. We also expect to liquidate the remaining 20 percent of CST outstanding shares within 18 months of the distribution. Details of the separation and distribution are provided in filings with the SEC by CST.

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RESULTS OF OPERATIONS

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

2012 Compared to 2011

Financial Highlights (a) (b)

(millions of dollars, except per share amounts)



	Year Ended December 31,
	2012			2011			Change
Operating revenues	$	139,250		$	125,987		$	13,263
Costs and expenses:
Cost of sales (c)	127,268			115,719			11,549
Operating expenses:
Refining (d)	3,668			3,406			262
Retail	686			678			8
Ethanol	332			399			(67		)
General and administrative expenses	698			571			127
Depreciation and amortization expense:
Refining	1,370			1,338			32
Retail	119			115			4
Ethanol	42			39			3
Corporate	43			42			1
Asset impairment loss (e)	1,014			—			1,014
Total costs and expenses	135,240			122,307			12,933
Operating income	4,010			3,680			330
Other income, net	9			43			(34		)
Interest and debt expense, net of capitalized interest	(313		)	(401		)	88
Income from continuing operations before income tax expense	3,706			3,322			384
Income tax expense	1,626			1,226			400
Income from continuing operations	2,080			2,096			(16		)
Loss from discontinued operations, net of income taxes	—			(7		)	7
Net income	2,080			2,089			(9		)
Less: Net loss attributable to noncontrolling interests	(3		)	(1		)	(2		)
Net income attributable to Valero stockholders	$	2,083		$	2,090		$	(7	)

Net income attributable to Valero stockholders:
Continuing operations	$	2,083		$	2,097		$	(14	)
Discontinued operations	—			(7		)	7
Total	$	2,083		$	2,090		$	(7	)

Earnings per common share – assuming dilution:
Continuing operations	$	3.75		$	3.69		$	0.06
Discontinued operations	—			(0.01		)	0.01
Total	$	3.75		$	3.68		$	0.07

________________

See note references on page 35.

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Refining Operating Highlights

(millions of dollars, except per barrel amounts)



	Year Ended December 31,
	2012		2011		Change
Refining (a) (b):
Operating income (c) (d) (e)	$	4,450	$	3,516	$	934
Throughput margin per barrel (f)	$	10.96	$	9.91	$	1.05
Operating costs per barrel:
Operating expenses (d)	3.79		3.83		(0.04		)
Depreciation and amortization expense	1.44		1.51		(0.07		)
Total operating costs per barrel (e)	5.23		5.34		(0.11		)
Operating income per barrel	$	5.73	$	4.57	$	1.16

Throughput volumes (thousand BPD):
Feedstocks:
Heavy sour crude	453		454		(1		)
Medium/light sour crude	547		442		105
Acidic sweet crude	81		116		(35		)
Sweet crude	910		745		165
Residuals	200		282		(82		)
Other feedstocks	120		122		(2		)
Total feedstocks	2,311		2,161		150
Blendstocks and other	302		273		29
Total throughput volumes	2,613		2,434		179

Yields (thousand BPD):
Gasolines and blendstocks	1,251		1,120		131
Distillates	918		834		84
Other products (g)	467		494		(27		)
Total yields	2,636		2,448		188

__________

See note references on page 35.

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Refining Operating Highlights by Region (h)

(millions of dollars, except per barrel amounts)



	Year Ended December 31,
	2012			2011			Change
U.S. Gulf Coast (a):
Operating income (c) (d) (e)	$	2,541		$	2,205		$	336
Throughput volumes (thousand BPD)	1,488			1,450			38
Throughput margin per barrel (c) (f)	$	9.65		$	9.33		$	0.32
Operating costs per barrel:
Operating expenses (d)	3.55			3.66			(0.11		)
Depreciation and amortization expense	1.44			1.50			(0.06		)
Total operating costs per barrel (d) (e)	4.99			5.16			(0.17		)
Operating income per barrel	$	4.66		$	4.17		$	0.49

U.S. Mid-Continent:
Operating income (c)	$	2,044		$	1,535		$	509
Throughput volumes (thousand BPD)	430			411			19
Throughput margin per barrel (c) (f)	$	18.49		$	15.91		$	2.58
Operating costs per barrel:
Operating expenses	4.02			4.15			(0.13		)
Depreciation and amortization expense	1.48			1.52			(0.04		)
Total operating costs per barrel	5.50			5.67			(0.17		)
Operating income per barrel	$	12.99		$	10.24		$	2.75

North Atlantic (b):
Operating income	$	752		$	171		$	581
Throughput volumes (thousand BPD)	428			317			111
Throughput margin per barrel (f)	$	9.24		$	5.43		$	3.81
Operating costs per barrel:
Operating expenses	3.59			3.08			0.51
Depreciation and amortization expense	0.85			0.87			(0.02		)
Total operating costs per barrel	4.44			3.95			0.49
Operating income per barrel	$	4.80		$	1.48		$	3.32

U.S. West Coast:
Operating income (c)	$	147		$	147		$	—
Throughput volumes (thousand BPD)	267			256			11
Throughput margin per barrel (c) (f)	$	8.84		$	9.11		$	(0.27	)
Operating costs per barrel:
Operating expenses	5.09			5.25			(0.16		)
Depreciation and amortization expense	2.25			2.29			(0.04		)
Total operating costs per barrel	7.34			7.54			(0.20		)
Operating income per barrel	$	1.50		$	1.57		$	(0.07	)

Operating income for regions above	$	5,484		$	4,058		$	1,426
Loss on derivative contracts related to the forward sales of refined product (c)	—			(542		)	542
Severance expense (d)	(41		)	—			(41		)
Asset impairment loss applicable to refining (e)	(993		)	—			(993		)
Total refining operating income	$	4,450		$	3,516		$	934

__________

See note references on page 35.

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Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)



	Year Ended December 31,
	2012			2011			Change
Feedstocks:
Brent crude oil	$	111.70		$	110.93		0.77
Brent less WTI crude oil	17.55			15.88			1.67
Brent less Alaska North Slope (ANS) crude oil	1.08			1.39			(0.31	)
Brent less LLS crude oil	(0.91		)	(0.54		)	(0.37	)
Brent less Mars crude oil	3.97			3.46			0.51
Brent less Maya crude oil	12.06			12.18			(0.12	)
LLS crude oil	112.61			111.47			1.14
LLS less Mars crude oil	4.88			4.00			0.88
LLS less Maya crude oil	12.97			12.72			0.25
WTI crude oil	94.15			95.05			(0.90	)

Natural gas (dollars per million British thermal units)	2.71			3.96			(1.25	)

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less Brent	6.49			5.58			0.91
Ultra-low-sulfur diesel less Brent	16.48			13.78			2.70
Propylene less Brent	(22.38		)	8.23			(30.61	)
Conventional 87 gasoline less LLS	5.58			5.04			0.54
Ultra-low-sulfur diesel less LLS	15.57			13.24			2.33
Propylene less LLS	(23.29		)	7.69			(30.98	)
U.S. Mid-Continent:
Conventional 87 gasoline less WTI	25.40			22.37			3.03
Ultra-low-sulfur diesel less WTI	34.96			31.06			3.90
North Atlantic:
Conventional 87 gasoline less Brent	11.46			6.24			5.22
Ultra-low-sulfur diesel less Brent	19.06			15.64			3.42
U.S. West Coast:
CARBOB 87 gasoline less ANS	15.39			11.48			3.91
CARB diesel less ANS	19.93			18.47			1.46
CARBOB 87 gasoline less WTI	31.86			25.97			5.89
CARB diesel less WTI	36.40			32.96			3.44
New York Harbor corn crush (dollars per gallon)	(0.15		)	0.25			(0.40	)

__________

See note references on page 35.

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Retail and Ethanol Operating Highlights

(millions of dollars, except per gallon amounts)



	Year Ended December 31,
	2012			2011			Change
Retail–U.S.:
Operating income (e)	$	240		$	213		$	27
Company-operated fuel sites (average)	1,013			994			19
Fuel volumes (gallons per day per site)	5,083			5,060			23
Fuel margin per gallon	$	0.162		$	0.144		$	0.018
Merchandise sales	$	1,239		$	1,223		$	16
Merchandise margin (percentage of sales)	29.7		%	28.7		%	1.0		%
Margin on miscellaneous sales	$	89		$	88		$	1
Operating expenses	$	434		$	416		$	18
Depreciation and amortization expense	$	77		$	77		$	—
Asset impairment loss (e)	$	12		$	—		$	12

Retail–Canada:
Operating income (e)	$	108		$	168		$	(60	)
Fuel volumes (thousand gallons per day)	3,096			3,195			(99		)
Fuel margin per gallon	$	0.258		$	0.299		$	(0.041	)
Merchandise sales	$	257		$	261		$	(4	)
Merchandise margin (percentage of sales)	29.0		%	29.4		%	(0.4		)%
Margin on miscellaneous sales	$	44		$	43		$	1
Operating expenses	$	252		$	262		$	(10	)
Depreciation and amortization expense	$	42		$	38		$	4
Asset impairment loss (e)	$	9		$	—		$	9

Ethanol:
Operating income (loss)	$	(47	)	$	396		$	(443	)
Ethanol production (thousand gallons per day)	2,967			3,352			(385		)
Gross margin per gallon of production (f)	$	0.30		$	0.68		$	(0.38	)
Operating costs per gallon of production:
Operating expenses	0.30			0.33			(0.03		)
Depreciation and amortization expense	0.04			0.03			0.01
Total operating costs per gallon of production	0.34			0.36			(0.02		)
Operating income (loss) per gallon of production	$	(0.04	)	$	0.32		$	(0.36	)

__________

See note references on page 35.

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The following notes relate to references on pages 30 through 34.


(a)	The financial highlights and operating highlights for the refining segment and U.S. Gulf Coast region reflect the results of operations of our Meraux Refinery, including related logistics assets, from the date of its acquisition on October 1, 2011.


(b)	The financial highlights and operating highlights for the refining segment and North Atlantic region reflect the results of operations of our Pembroke Refinery, including the related market and logistics business, from the date of its acquisition on August 1, 2011.

(c)

Cost of sales for the year ended December 31, 2011 includes a loss of $542 million ($352 million after taxes) on commodity derivative contracts related to the forward sales of refined product. These contracts were closed and realized during the first quarter of 2011. This loss is reflected in refining segment operating income for the year ended December 31, 2011, but throughput margin per barrel for the refining segment has been restated from the amount previously presented to exclude this $542 million loss ($0.61 per barrel). In addition, operating income and throughput margin per barrel for the U.S. Gulf Coast, the U.S. Mid-Continent, and the U.S. West Coast regions for the year ended December 31, 2011 have been restated from the amounts previously presented to exclude the portion of this loss that had been allocated to them of $372 million ($0.70 per barrel), $122 million ($0.81 per barrel), and $48 million ($0.51 per barrel), respectively.

(d)

In September 2012, we decided to reorganize our Aruba Refinery into a crude oil and refined products terminal. These terminal operations require a considerably smaller workforce; therefore, the reorganization resulted in the termination of the majority of our employees in Aruba. We recognized severance expense of $41 million in September 2012. This expense is reflected in refining segment operating income for the year ended December 31, 2012, but it is excluded from operating costs per barrel for the refining segment and the U.S. Gulf Coast region. No income tax benefits were recognized related to this severance expense.


(e)	During the year ended December 31, 2012, we recognized the following asset impairment losses (in millions):



Refining segment:
Aruba Refinery	$	928
Cancelled capital projects	65
Asset impairment losses - refining segment	993
Retail segment:
U.S. stores	12
Canada stores	9
Asset impairment losses - retail segment	21
Total asset impairment losses	$	1,014

The asset impairment loss related to the Aruba Refinery resulted from our decision in March 2012 to suspend refining operations at the refinery and our subsequent decision in September 2012 to reorganize the refinery into a crude oil and refined products terminal, as discussed in note (d). We recognized an asset impairment loss of $595 million in March 2012 and an additional asset impairment loss of $308 million in September 2012, resulting in no remaining book value being associated with the refinery’s idled processing units and related infrastructure (refining assets). In addition, we recorded a loss of $25 million related to supplies inventories that supported the refining operations. The refining operations will remain suspended indefinitely; however, we continue to maintain the refining assets to allow them to be restarted and do not consider them to be abandoned. No income tax benefits were recorded related to this asset impairment loss.

We also recognized asset impairment losses related to permanently cancelled capital projects at certain of our refineries and related to our determination that the net book values of certain of our retail stores were not recoverable through the future operation and disposition of those stores. The after-tax amount of these asset impairment losses was $55 million for the year ended December 31, 2012.

The asset impairment losses reflected in the table above are included in the operating income of the respective segment for the year ended December 31, 2012. However, the asset impairment losses related to the refining segment are excluded from the segment’s operating costs per barrel and from the operating income and operating costs per barrel by region.


(f)	Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.


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

(h)

The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, St. Charles, Aruba, Port Arthur, and Meraux Refineries; the U.S. Mid-Continent region includes the McKee, Ardmore, and Memphis Refineries; the North Atlantic region includes the Pembroke and Quebec City Refineries; and the U.S. West Coast region includes the Benicia and Wilmington Refineries.

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General

Operating revenues increased 11 percent (or $13.3 billion) for the year ended December 31, 2012 compared to the year ended December 31, 2011 primarily as a result of higher average refined product prices for most of the products we produce and higher throughput volumes between the two years related to our refining segment operations. Refined product prices are most significantly influenced by the price of crude oil, which is a worldwide commodity whose price is influenced by many factors, including, but not limited to, worldwide supply and demand characteristics, worldwide political conditions, and worldwide economic conditions. However, regional factors also impact the price of refined product prices in those geographic regions. Regional factors can be similar to those that affect the worldwide price of crude oil, but they can also be significantly influenced by weather conditions that disrupt the supply of and demand for refined products in the region. For example, in October 2012, Hurricane Sandy struck the U.S. East Coast and disrupted the supply of refined products in that region for some time, which contributed to the increase of $5.99 per barrel in the North Atlantic benchmark reference price of conventional 87 gasoline in 2012 compared to 2011. The higher throughput volumes in 2012 resulted primarily from the incremental throughput of 75,000 BPD from the Meraux Refinery, which was acquired on October 1, 2011, and incremental throughput of 95,000 BPD from the Pembroke Refinery, which was acquired on August 1, 2011.

Operating income increased $330 million and income from continuing operations before income tax expense increased $384 million for the year ended December 31, 2012 compared to the amounts reported for the year ended December 31, 2011 due to a $934 million increase in refining segment operating income, a $33 million decrease in retail segment operating income, a $443 million decrease in ethanol segment operating income, and a $128 million increase in corporate expenses. The reasons for these changes are described below.

Refining

Refining segment operating income increased from $3.5 billion for the year ended December 31, 2011 to $4.5 billion for the year ended December 31, 2012. This increase was impacted by asset impairment losses of $928 million related to the Aruba Refinery and $65 million related to cancelled capital projects in 2012, $41 million of severance expense related to the Aruba Refinery, and a $542 million loss on derivative contracts in 2011. (See Notes 4 and 10 of Notes to Consolidated Financial Statements for further discussions of the asset impairment losses and the severance expense, respectively). Excluding these amounts, our refining segment operating income increased $1.4 billion from $4.1 billion for the year ended December 31, 2011 to $5.5 billion for the year ended December 31, 2012. This $1.4 billion improvement in operating income was primarily due to a $1.7 billion increase in refining margin, partially offset by a $262 million increase in operating expenses.

The $1.7 billion increase in refining margin (a $1.05 per barrel, or 11 percent, increase between 2012 and 2011) was primarily the result of improvements in the margin generated in our U.S. Mid-Continent and North Atlantic regions, which experienced increases in refining margin of $526 million (a $2.58 per barrel increase), and $821 million (a $3.81 per barrel increase), respectively.

The $526 million increase in refining margin in the U.S. Mid-Continent region was largely due to improved gasoline and distillate margins in that region in 2012 compared to 2011. For example, the U.S. Mid-Continent benchmark reference margins for conventional 87 gasoline and ultra-low-sulfur diesel, a type of distillate, increased year over year by $3.03 per barrel and $3.90 per barrel, respectively, and these increases were primarily the result of a $1.67 per barrel increase in the discount between the price of WTI crude oil versus Brent crude oil. Brent crude oil is the type of crude oil used by the market to set the price of refined products, but our refineries in the U.S. Mid-Continent region primarily process WTI-type crude oil; therefore, the increase in the price discount between WTI crude oil versus Brent crude oil had a positive impact to our refining margin in this region of approximately $300 million. WTI crude oil priced at a significant discount

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to Brent crude oil during 2012 because of increases in crude oil reserves within the U.S. Mid-Continent region and increased deliveries of crude oil from Canada into that region, coupled with the inability to transport significant quantities of that crude oil to refineries in other regions of the country. As discussed in “OVERVIEW AND OUTLOOK.” we believe these conditions to remain in the near term; however, we believe the discount will begin to narrow as crude oil pipeline and logistics projects are completed and other forms of transportation are obtained, such as rail cars, to enable significant quantities of WTI-type crude oil to be transported to other regions.

The $821 million increase in refining margin in the North Atlantic region was also due to improved gasoline and distillate margins in that region in 2012 compared to 2011. For example, the North Atlantic benchmark reference margins for conventional 87 gasoline and ultra-low-sulfur diesel increased year over year by $5.22 per barrel and $3.42 per barrel, respectively, and these increases were due largely to a reduction in the supply of refined products, which resulted from the continued shutdown of refineries in the U.S. East Coast, Caribbean, and Western Europe during 2012, and supply disruptions caused by Hurricane Sandy, which struck the U.S. East Coast in October 2012.

The increase of $262 million in operating expenses discussed above was primarily due to an increase of $123 million in operating expenses of the Meraux Refinery, an increase of $214 million in operating expenses incurred by the Pembroke Refinery, and a decrease of $123 million in operating expenses incurred by the Aruba Refinery. We acquired the Pembroke Refinery on August 1, 2011 and the Meraux Refinery on October 1, 2011; therefore, operating expenses for 2011 only reflected five months of operating expenses of the Pembroke Refinery and three months of operating expenses of the Meraux Refinery. In addition, in March 2012, we suspended the operations of the Aruba Refinery, which resulted in a significant decrease in operating expenses related to that refinery in 2012. The remaining increase in operating expenses of $48 million was primarily due to an increase of $31 million in employee-related expenses due to higher compensation expense related to merit increases and promotions and higher expenses for employee benefit costs, an increase of $9 million in catalyst and chemical costs due to higher prices of rare earth metals used in our fluid catalytic cracking units, an increase of $61 million in ad valorem taxes and insurance expense due to increased insurance reserves in 2012 combined with a nonrecurring favorable ad valorem tax adjustment in 2011, and a decrease of $63 million in energy costs due to lower natural gas prices. Even though operating expenses increased year over year, operating expenses per barrel in 2012 were comparable to 2011 due to the incremental throughput of 179,000 BPD, which primarily resulted from the incremental throughput of the Pembroke and Meraux Refineries discussed above.

Retail

Retail operating income was $348 million for the year ended December 31, 2012 compared to $381 million for the year ended December 31, 2011. This 9 percent (or $33 million) decrease was primarily due to a $21 million noncash asset impairment loss related to certain convenience stores (see Note 4 of Notes to Consolidated Financial Statements), a $56 million decrease in fuel margin from our Canadian retail operations, and a $41 million increase in fuel margin in our U.S. retail operations.

The Canadian retail fuel margin for 2012 was impacted by a decline in fuel volumes sold as a result of fewer retail sites combined with a decline in the fuel margin per gallon, which was due to pricing pressure from our competitors and changes in wholesale motor fuel prices during the year. Our U.S. retail fuel margin improved during 2012 due to increased fuel volumes sold as a result of more retail sites combined with improved fuel margin per gallon as wholesale motor fuel prices peaked in March 2012 and declined throughout the remainder of the year.

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Ethanol

Ethanol segment operating loss was $47 million for the year ended December 31, 2012 compared to operating income of $396 million for the year ended December 31, 2011. This decrease of $443 million was primarily due to a $507 million decrease in gross margin, partially offset by a $67 million decrease in operating expenses.

The decrease in gross margin was due to a 56 percent decrease in the gross margin per gallon of ethanol production (a $0.38 per gallon decrease between the comparable periods) primarily due to lower ethanol prices in 2012 versus 2011. Ethanol prices during 2012 were pressured by a surplus of ethanol supply due to reduced demand for ethanol associated with the decline in gasoline demand in the U.S., lower exports of ethanol to Europe, and increased imports of ethanol from Brazil. In addition, ethanol production decreased 385,000 gallons per day between the comparable periods due to lower utilization rates at our ethanol plants during 2012. The reduction in operating expenses was due primarily to a $57 million decrease in energy costs resulting from decreased consumption because of the lower utilization rates previously discussed, combined with lower natural gas prices versus the comparable period of 2011.

Corporate Expenses and Other

General and administrative expenses increased $127 million for the year ended December 31, 2012 compared to the year ended December 31, 2011 due to $58 million in administrative costs related to our European operations, which we acquired on August 1, 2011, a $23 million increase in employee benefits expense (primarily related to increased costs for medical and retirement benefits), and favorable legal settlements of $47 million in 2011, which did not recur in 2012.

“Other income, net” for the year ended December 31, 2012 decreased $34 million from the year ended December 31, 2011 due to an increase of $15 million of foreign currency transaction losses, an $11 million reduction in interest income due to the collection of a note receivable from PBF Holdings LLC in February 2012, and a $7 million reduction in bank interest income due to lower levels of temporary cash investments during 2012 as compared to the prior year.

“Interest and debt expense, net of capitalized interest” for the year ended December 31, 2012 decreased $88 million from the year ended December 31, 2011. This decrease is primarily due to an increase of $69 million in capitalized interest related to an increase in capital expenditures between the years and a $33 million favorable impact from the decrease in average borrowings, partially offset by a $12 million write-off of unamortized debt discounts related to the early redemption of certain industrial revenue bonds in the first quarter of 2012.

Income tax expense for the year ended December 31, 2012 increased $400 million from the year ended December 31, 2011 partially as a result of higher operating income in 2012. The variation in the customary relationship between income tax expense and income from continuing operations before income tax expense for the year ended December 31, 2012 was primarily due to not recognizing the tax benefits associated with the asset impairment loss of $928 million and the severance expense of $41 million related to the Aruba Refinery as we do not expect to realize a tax benefit from these losses.

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2011 Compared to 2010

Financial Highlights (a) (b) (d) (e)

(millions of dollars, except per share amounts)



	Year Ended December 31,
	2011			2010			Change
Operating revenues	$	125,987		$	82,233		$	43,754
Costs and expenses:
Cost of sales (c)	115,719			74,458			41,261
Operating expenses:
Refining	3,406			2,944			462
Retail	678			654			24
Ethanol	399			363			36
General and administrative expenses	571			531			40
Depreciation and amortization expense:
Refining	1,338			1,210			128
Retail	115			108			7
Ethanol	39			36			3
Corporate	42			51			(9		)
Asset impairment loss	—			2			(2		)
Total costs and expenses	122,307			80,357			41,950
Operating income	3,680			1,876			1,804
Other income, net	43			106			(63		)
Interest and debt expense, net of capitalized interest	(401		)	(484		)	83
Income from continuing operations before income tax expense	3,322			1,498			1,824
Income tax expense	1,226			575			651
Income from continuing operations	2,096			923			1,173
Loss from discontinued operations, net of income taxes	(7		)	(599		)	592
Net income	2,089			324			1,765
Less: Net loss attributable to noncontrolling interest	(1		)	—			(1		)
Net income attributable to Valero stockholders	$	2,090		$	324		$	1,766

Net income (loss) attributable to Valero stockholders:
Continuing operations	$	2,097		$	923		$	1,174
Discontinued operations	(7		)	(599		)	592
Total	$	2,090		$	324		$	1,766

Earnings per common share – assuming dilution:
Continuing operations	$	3.69		$	1.62		$	2.07
Discontinued operations	(0.01		)	(1.05		)	1.04
Total	$	3.68		$	0.57		$	3.11

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See note references on page 44.

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Refining Operating Highlights

(millions of dollars, except per barrel amounts)



	Year Ended December 31,
	2011		2010		Change
Refining (a) (b) (d):
Operating income (c)	$	3,516	$	1,903	$	1,613
Throughput margin per barrel (f)	$	9.91	$	7.80	$	2.11
Operating costs per barrel:
Operating expenses	3.83		3.79		0.04
Depreciation and amortization expense	1.51		1.56		(0.05		)
Total operating costs per barrel	5.34		5.35		(0.01		)
Operating income per barrel	$	4.57	$	2.45	$	2.12

Throughput volumes (thousand BPD):
Feedstocks:
Heavy sour crude	454		458		(4		)
Medium/light sour crude	442		386		56
Acidic sweet crude	116		60		56
Sweet crude	745		668		77
Residuals	282		204		78
Other feedstocks	122		110		12
Total feedstocks	2,161		1,886		275
Blendstocks and other	273		243		30
Total throughput volumes	2,434		2,129		305

Yields (thousand BPD):
Gasolines and blendstocks	1,120		1,048		72
Distillates	834		712		122
Other products (g)	494		395		99
Total yields	2,448		2,155		293

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See note references on page 44.

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Refining Operating Highlights by Region (h)

(millions of dollars, except per barrel amounts)



	Year Ended December 31,
	2011		2010		Change
U.S. Gulf Coast (a):
Operating income (c)	$	2,205	$	1,349	$	856
Throughput volumes (thousand BPD)