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, 2011
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _______________ to _______________ | |
Commission file number 1-13175
VALERO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware | 74-1828067 |
(State or other jurisdiction of | (I.R.S. Employer |
incorporation or organization) | Identification No.) |
One Valero Way | 78249 | ||
San Antonio, Texas | (Zip Code) | ||
(Address of principal executive offices) | |||
Registrant’s telephone number, including area code: (210) 345-2000 | |||
Securities registered pursuant to Section 12(b) of the Act: Common stock, $0.01 par value per share listed on the New York Stock Exchange.
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes R No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes R No o
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No o
Indicate by check mark if disclosure of 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 $14.6 billion based on the last sales price quoted as of June 30, 2011 on the New York Stock Exchange, the last business day of the registrant’s most recently completed second fiscal quarter.
As of January 31, 2012, 555,069,442 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 3, 2012, at which directors will be elected. Portions of the 2012 Proxy Statement are incorporated by reference in Part III of this Form 10-K and are deemed to be a part of this report.
CROSS-REFERENCE SHEET
The following table indicates the headings in the 2012 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 2012 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 2011, KPMG Fees for Fiscal Year 2010, and Audit Committee Pre-Approval Policy | |
Copies of all documents incorporated by reference, other than exhibits to such documents, will be provided without charge to each person who receives a copy of this Form 10-K upon written request to Jay D. Browning, Senior Vice President – Corporate Law and Secretary, Valero Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-6000.
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CONTENTS
PAGE | ||
Item 11. | Executive Compensation | |
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | |
Item 13. | Certain Relationships and Related Transactions, and Director Independence | |
Item 14. | Principal Accountant Fees and Services | |
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PART I
The terms “Valero,” “we,” “our,” and “us,” as used in this report, may refer to Valero Energy Corporation, to one or more of our consolidated subsidiaries, or to all of them taken as a whole. In this Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources, under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. You should read our forward-looking statements together with our disclosures beginning on page 24 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, 2012, we had 21,942 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, and the U.K. through an extensive bulk and rack marketing network, and we sell refined products through a network of about 6,800 retail and branded wholesale outlets 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. with a combined ethanol nameplate production capacity of about 1.1 billion gallons per year.
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 Jay D. Browning, Senior Vice President – Corporate Law and Secretary, Valero Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-6000.
_____________________________
1 CBOB, or “conventional blendstock for oxygenate blending,” is conventional gasoline blendstock intended for blending with oxygenates downstream of the refinery where it was produced. CBOB becomes conventional gasoline after blending with oxygenates. 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, Canadian dealers/jobbers, truckstop facilities, cardlock facilities, and home heating oil operations. The retail segment is segregated into two geographic regions. Our retail operations in the U.S. are referred to as Retail-U.S. Our retail operations in Canada are referred to as Retail-Canada. |
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VALERO’S OPERATIONS
REFINING
On December 31, 2011, 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, 2011.
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 | 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. |
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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, 2011 (includes the results of operations of our Meraux and Pembroke Refineries from the dates of their acquisition through the end of the year). Our total combined throughput volumes averaged 2.4 million BPD for the year ended December 31, 2011.
Combined Total Refining System Charges and Yields | |||
Charges: | |||
sour crude oil | 37 | % | |
acidic sweet crude oil | 5 | % | |
sweet crude oil | 31 | % | |
residual fuel oil | 11 | % | |
other feedstocks | 5 | % | |
blendstocks | 11 | % | |
Yields: | |||
gasolines and blendstocks | 46 | % | |
distillates | 34 | % | |
petrochemicals | 3 | % | |
other products (includes gas oil, No. 6 fuel oil, petroleum coke, and asphalt) | 17 | % | |
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, 2011 (includes the results of operations of our Meraux Refinery from October 1, 2011, the date of its acquisition, through the end of the year). Total throughput volumes for the U.S. Gulf Coast refining region averaged 1.45 million BPD for the year ended December 31, 2011.
Combined U.S. Gulf Coast Region Charges and Yields | |||
Charges: | |||
sour crude oil | 50 | % | |
acidic sweet crude oil | 2 | % | |
sweet crude oil | 10 | % | |
residual fuel oil | 19 | % | |
other feedstocks | 6 | % | |
blendstocks | 13 | % | |
Yields: | |||
gasolines and blendstocks | 41 | % | |
distillates | 33 | % | |
petrochemicals | 4 | % | |
other products (includes gas oil, No. 6 fuel oil, petroleum coke, and asphalt) | 22 | % | |
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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. 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. 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.
Aruba Refinery. Our Aruba Refinery is located on the island of Aruba in the Caribbean Sea. It processes primarily heavy sour crude oil and produces intermediate feedstocks and finished distillate products. Significant amounts of the refinery’s intermediate feedstock production are transported and further processed in our other refineries in the U.S. Gulf Coast and U.S. West Coast regions. The refinery receives crude oil by ship at its two deepwater marine docks, which can berth ultra-large crude carriers. The refinery’s products are delivered by ship primarily into markets in the U.S., the Caribbean, Europe, and South America.
Houston Refinery. Our Houston Refinery is located on the Houston Ship Channel. It processes a mix of crude oils and low-sulfur residual fuel oil into reformulated gasoline and distillates. The refinery receives its feedstocks via tanker at deepwater docking facilities along the Houston Ship Channel and interconnecting pipelines with the Texas City Refinery. It delivers its products through major refined-product pipelines, including the Colonial, Explorer, Orion, and TEPPCO pipelines.
Meraux Refinery. Our Meraux Refinery is located in St. Bernard Parish southeast of New Orleans. We acquired the refinery on October 1, 2011. 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. The refinery distributes its refined products primarily through pipelines owned by NuStar Energy L.P.
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, 2011. Total throughput volumes for the U.S. Mid-Continent refining region averaged approximately 411,000 BPD for the year ended December 31, 2011.
Combined U.S. Mid-Continent Region Charges and Yields | |||
Charges: | |||
sour crude oil | 9 | % | |
sweet crude oil | 82 | % | |
other feedstocks | 1 | % | |
blendstocks | 8 | % | |
Yields: | |||
gasolines and blendstocks | 54 | % | |
distillates | 35 | % | |
petrochemicals | 5 | % | |
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. Mid-Continent region. The refinery distributes its products primarily via NuStar Energy L.P.’s pipelines to markets in Texas, New Mexico, Arizona, Colorado, and Oklahoma.
Ardmore Refinery. Our Ardmore Refinery is located in Ardmore, Oklahoma, approximately 100 miles south of Oklahoma City. It processes medium sour and sweet crude oils into conventional gasoline, ultra-low-sulfur diesel, liquefied petroleum gas products, and asphalt. Local crude oil is gathered by TEPPCO’s crude oil gathering/trunkline systems and trucking operations, and 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.
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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, 2011 (includes the results of operations of our Pembroke Refinery from August 1, 2011, the date of its acquisition, through the end of the year). Total throughput volumes for the North Atlantic refining region averaged approximately 317,000 BPD for the year ended December 31, 2011.
North Atlantic Region Charges and Yields | |||
Charges: | |||
sour crude oil | 2 | % | |
acidic sweet crude oil | 11 | % | |
sweet crude oil | 78 | % | |
residual fuel oil | 3 | % | |
other feedstocks | 1 | % | |
blendstocks | 5 | % | |
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. We acquired the refinery on August 1, 2011. 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 the Mainline pipeline system.
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. We charter large ice-strengthened, double-hulled crude oil tankers that can navigate the St. Lawrence River year-round. The refinery transports its products to its terminals in Quebec and Ontario primarily by train, and also uses ships and trucks extensively throughout eastern Canada.
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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, 2011. Total throughput volumes for the U.S. West Coast refining region averaged approximately 256,000 BPD for the year ended December 31, 2011.
Combined U.S. West Coast Region Charges and Yields | |||
Charges: | |||
sour crude oil | 48 | % | |
acidic sweet crude oil | 17 | % | |
sweet crude oil | 7 | % | |
other feedstocks | 13 | % | |
blendstocks | 15 | % | |
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. (CARBOB is a reformulated gasoline mixture that meets the specifications of the CARB when blended with ethanol.) The refinery receives crude oil feedstocks via a marine dock that can berth large crude oil carriers and a 20-inch crude oil pipeline connected to a southern California crude oil delivery system. Most of the refinery’s products are distributed via the Kinder Morgan pipeline system in California.
Wilmington Refinery. Our Wilmington 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 63 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 (including feedstocks originating in the Middle East, Africa, Asia, Mexico, and South America) 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, Quebec City, and Aruba Refineries rely on crude oil that is delivered to the refineries’ dock facilities by ship.
Refining Segment Sales
Our refining segment includes sales of refined products in both the wholesale rack and bulk markets. These sales include refined products that are manufactured in our refining operations as well as refined products purchased or received on exchange from third parties. Most of our refineries have access to marine transportation facilities and interconnect with common-carrier pipeline systems, allowing us to sell products in the U.S., Canada, the U.K., and other countries. No customer accounted for more than 10 percent of our total operating revenues in 2011.
Wholesale Marketing
We market branded and unbranded transportation fuels on a wholesale basis through an extensive rack marketing network. The principal purchasers of our transportation fuels from terminal truck racks are wholesalers, distributors, retailers, and truck-delivered end users throughout the U.S., the 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 4,000 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 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
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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 napthenic oils at one of our refineries suitable for a wide variety of lubricant and process applications. |
• | NGLs produced at our refineries include butane, isobutane, and propane. These products can be used for gasoline blending, home heating, and petrochemical plant feedstocks. |
• | We are a significant producer of petroleum coke, supplying primarily power generation customers and cement manufacturers. Petroleum coke is used largely as a substitute for coal. |
• | We produce and market a number of commodity petrochemicals including aromatic solvents (benzene, toluene, and xylene) and two grades of propylene. Aromatic solvents and propylenes are sold to customers in the chemical industry for further processing into such products as paints, plastics, and adhesives. |
• | We are a large producer of sulfur with sales primarily to customers in the agricultural sector. Sulfur is used in manufacturing fertilizer. |
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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 facilities1 that process corn to produce ethanol and distillers grains.2 We source our corn supply from local farmers and commercial elevators. Our facilities receive corn by rail and truck. 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 2011 averaged 3.4 million gallons per day.
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1 | Ethanol is commercially produced using either the wet mill or dry mill process. Wet milling involves separating the grain kernel into its component parts (germ, fiber, protein, and starch) prior to fermentation. In the dry mill process, the entire grain kernel is ground into flour. The starch in the flour is converted to ethanol during the fermentation process, creating carbon dioxide and distillers grains. |
2 | During fermentation, nearly all of the starch in the grain is converted into ethanol and carbon dioxide, while the remaining nutrients (proteins, fats, minerals, and vitamins) are concentrated to yield modified distillers grains, or, after further drying, dried distillers grains. Distillers grains generally are an economical partial replacement for corn, soybean, and dicalcium phosphate in feeds for livestock, swine, and poultry. |
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RETAIL
Our retail segment operations include:
• | sales of transportation fuels at retail stores and unattended self-service cardlocks, |
• | sales of convenience store merchandise and services in retail stores, and |
• | sales of home heating oil to residential customers. |
We are one of the largest independent retailers of transportation fuels in the central and southwest U.S. and eastern Canada. Our retail operations are segregated geographically into two groups: Retail-U.S. and Retail-Canada.
Retail-U.S.
Sales in Retail-U.S. represent sales of transportation fuels and convenience store merchandise and services through our company-operated retail sites. For the year ended December 31, 2011, total sales of transportation fuels through Retail-U.S.’s sites averaged 119,780 BPD. In addition to transportation fuels, 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, 2011, we had 998 company-operated sites in Retail-U.S. (of which 80 percent were owned and 20 percent were leased). Our company-operated stores are operated primarily under the Corner Store® brand name. Transportation fuels sold in our Retail-U.S. stores are sold primarily under the Valero® brand.
Retail-Canada
Sales in Retail-Canada include:
• | sales of transportation fuels and convenience store merchandise through our company-operated retail sites and cardlocks, |
• | sales of transportation fuels through sites owned by independent dealers and jobbers, and |
• | sales of home heating oil to residential customers. |
Retail-Canada includes retail operations in eastern Canada where we are a major supplier of transportation fuels serving Quebec, Ontario, Newfoundland, Nova Scotia, New Brunswick, and Prince Edward Island. For the year ended December 31, 2011, total retail sales of transportation fuels through Retail-Canada averaged approximately 76,100 BPD. Transportation fuels are sold under the Ultramar® brand through a network of 791 outlets throughout eastern Canada. On December 31, 2011, we owned or leased 381 retail stores in Retail-Canada and distributed gasoline to 410 dealers and independent jobbers. In addition, Retail-Canada operates 82 cardlocks, which are card- or key-activated, self-service, unattended stations that allow commercial, trucking, and governmental fleets to buy transportation fuel 24 hours a day. Retail-Canada operations also include a large home heating oil business that provides home heating oil to approximately 133,000 households in eastern Canada. Our home heating oil business is seasonal to the extent of increased demand for home heating oil during the winter.
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RISK FACTORS
Our financial results are affected by volatile refining margins, 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 will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely
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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 future operations and financial position.
From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we were unable to obtain necessary funds from financing activities. From time to time, we may need to supplement our cash generated from operations with proceeds from financing activities. We have existing revolving credit facilities, committed letter of credit facilities, and an accounts receivable sales facility to provide us with available financing to meet our ongoing cash needs. 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 operations and financial position.
Compliance with and changes in environmental laws, including proposed climate change laws and regulations, could adversely affect our performance.
The principal environmental risks associated with our operations are emissions into the air and releases into the soil, surface water, or groundwater. 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, the U.S. Environmental Protection Agency (EPA) has announced its intent to promulgate in 2012 more stringent requirements for refinery air emissions through revisions to existing New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants. In addition, the EPA has, in recent years, adopted final rules making more stringent the National 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.
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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 business, financial condition, results of operations, and liquidity.
Competitors that produce their own supply of feedstocks, have more extensive retail outlets, 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 outlets for our refined products. We do not produce any of our crude oil feedstocks. Many of our competitors, however, obtain a significant portion of their feedstocks from company-owned production and some have more extensive retail outlets than we have. Competitors that have their own production or extensive retail outlets (and greater brand-name recognition) are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.
Some of our competitors also have materially greater financial and other resources than we have. Such competitors have a greater ability to bear the economic risks inherent in all phases of our industry. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial, and individual consumers.
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A significant interruption in one or more of our refineries could adversely affect our business.
Our refineries are our principal operating assets. As a result, our operations could be subject to significant interruption if one or more of our refineries were to experience a major accident or mechanical failure, encounter work stoppages relating to organized labor issues, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs. 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.
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 future liquidity, operating results, and financial condition.
Our refining and marketing operations are subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards, and natural catastrophes. As protection against these hazards, we maintain insurance coverage against some, but not all, such potential losses and liabilities. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies 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, transactional taxes (excise/duty, sales/use, and value-added taxes), payroll taxes, franchise taxes, 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.
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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 2011, our capital expenditures attributable to compliance with environmental regulations were approximately $241 million, and are currently estimated to be $140 million for 2012 and $155 million for 2013. The estimates for 2012 and 2013 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, 2011, 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 or results of operations. We are reporting these proceedings to comply with SEC regulations, which require us to disclose certain information about proceedings arising under federal, state, or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.
EPA (mobile source enforcement). In November 2010, the EPA issued a letter to us formalizing a proposed penalty of $585,000 in connection with eight alleged violations of U.S. federal fuels regulations (most of which were self-reported) purportedly occurring from March 2004 to 2006 at various refineries and terminals. We are negotiating with the EPA to resolve this matter.
EPA (Port Arthur Refinery). We expect the EPA to assess a penalty in an amount greater than $100,000 for a flaring event that occurred at our Port Arthur Refinery in 2011. The penalty would be a stipulated amount prescribed under our consent decree with the EPA. We have not yet received a formal penalty assessment from the EPA.
EPA (Three Rivers Refinery). We expect the EPA to assess a penalty in an amount greater than $100,000 for a flaring event that occurred at our Three Rivers Refinery in 2011. The penalty would be a stipulated amount prescribed under our consent decree with the EPA. We have not yet received a formal penalty assessment from the EPA.
Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery). In the fourth quarter of 2011, we settled 23 violation notices (VN’s) with the BAAQMD that were issued in 2009. In the first quarter of 2012, we settled five VN’s from 2009 and nine VN’s from 2010. We presently have outstanding 75 VN’s issued by the BAAQMD from 2010 to the present. These VN’s 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 notices of violation alleging violations of air and waste regulations at Premcor’s Hartford, Illinois terminal and closed refinery. We are negotiating the terms of a consent order for corrective action.
South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). Due to excess flare related emissions in 2011 at our Wilmington Refinery, we will pay a mitigation fee of about $2.3 million under SCAQMD Rule 1118 for emissions from refinery flares. We will pay the fee in the first quarter of 2012.
Texas Commission on Environmental Quality (TCEQ) (Corpus Christi West Refinery). In our annual report on Form 10-K for the year ended December 31, 2010, we disclosed that in the second quarter of 2009, the TCEQ issued a notice of enforcement (NOE) to our Corpus Christi West Refinery. The NOE alleged excess air emissions relating to two cooling tower leaks that occurred in 2008. We settled this matter with the TCEQ
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in the fourth quarter of 2011.
TCEQ (Three Rivers Refinery). In our quarterly report on Form 10-Q for the quarter ended September 30, 2011, we disclosed that the TCEQ had issued a proposed agreed order to our Three Rivers Refinery for various alleged air violations. We settled this matter with the TCEQ in the first quarter of 2012.
ITEM 4. RESERVED
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock trades on the New York Stock Exchange under the symbol “VLO.”
As of January 31, 2012 there were 7,659 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 2011 and 2010.
Sales Prices of the Common Stock | Dividends Per Common Share | |||||||||||
Quarter Ended | High | Low | ||||||||||
2011: | ||||||||||||
December 31 | $ | 26.70 | $ | 17.17 | $ | 0.15 | ||||||
September 30 | 26.89 | 17.78 | 0.05 | |||||||||
June 30 | 30.50 | 23.18 | 0.05 | |||||||||
March 31 | 30.73 | 23.19 | 0.05 | |||||||||
2010: | ||||||||||||
December 31 | $ | 23.35 | $ | 17.25 | $ | 0.05 | ||||||
September 30 | 18.31 | 15.65 | 0.05 | |||||||||
June 30 | 21.37 | 16.36 | 0.05 | |||||||||
March 31 | 20.69 | 17.45 | 0.05 | |||||||||
On January 24, 2012, our board of directors declared a quarterly cash dividend of $0.15 per common share payable March 14, 2012 to holders of record at the close of business on February 15, 2012.
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 2011.
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 2011 | 195,078 | $ | 25.08 | 195,078 | — | $ 3.46 billion | ||||
November 2011 | 1,986,045 | $ | 23.43 | 1,986,045 | — | $ 3.46 billion | ||||
December 2011 | 1,338,789 | $ | 20.76 | 1,338,789 | — | $ 3.46 billion | ||||
Total | 3,519,912 | $ | 22.51 | 3,519,912 | — | $ 3.46 billion | ||||
(a) | The shares reported in this column represent purchases settled in the fourth quarter of 2011 relating to (a) our purchases of shares in open-market transactions to meet our obligations under incentive compensation plans, and (b) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our incentive compensation plans. |
(b) | On April 26, 2007, we publicly announced an increase in our common stock purchase program from $2 billion to $6 billion, as authorized by our board of directors on April 25, 2007. The $6 billion common stock purchase program has no expiration date. On February 28, 2008, we announced that our board of directors approved a $3 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, 2006 and ending December 31, 2011. Our peer group consists of the following nine companies that are engaged in refining operations in the U.S.: Alon USA Energy, Inc.; Chevron Corporation; CVR Energy, Inc.; Exxon Mobil Corporation; Hess Corporation; HollyFrontier Corporation; Marathon Petroleum Corporation; Tesoro Corporation; and Western Refining, Inc. Our peer group previously included ConocoPhillips; Marathon Oil Corporation; Murphy Oil Corporation; and Sunoco, Inc., but they are not included in our current peer group because they have exited or are exiting refining operations in the U.S. Frontier Oil Corporation and Holly Corporation are now represented in our peer group as HollyFrontier Corporation.
12/2006 | 12/2007 | 12/2008 | 12/2009 | 12/2010 | 12/2011 | ||||||||||||||||||
Valero Common Stock | $ | 100.00 | $ | 137.91 | $ | 43.38 | $ | 34.60 | $ | 48.28 | $ | 44.49 | |||||||||||
S&P 500 | 100.00 | 105.49 | 66.46 | 84.05 | 96.71 | 98.75 | |||||||||||||||||
Old Peer Group | 100.00 | 127.94 | 98.91 | 94.54 | 112.51 | 130.65 | |||||||||||||||||
New Peer Group | 100.00 | 127.92 | 103.60 | 97.91 | 113.09 | 133.47 | |||||||||||||||||
1 | Assumes that an investment in Valero common stock and each index was $100 on December 31, 2006. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from December 31, 2006 through December 31, 2011. |
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ITEM 6. SELECTED FINANCIAL DATA
The selected financial data for the five-year period ended December 31, 2011 was derived from our audited financial statements. The following table should be read together with the historical financial statements and accompanying notes included in Item 8, “Financial Statements and Supplementary Data,” and with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
The following summaries are in millions of dollars, except for per share amounts:
Year Ended December 31, | |||||||||||||||||||
2011 (a) | 2010 (b) | 2009 (b) | 2008 | 2007 | |||||||||||||||
Operating revenues | $ | 125,987 | $ | 82,233 | $ | 64,599 | $ | 106,676 | $ | 85,079 | |||||||||
Income (loss) from continuing operations | 2,096 | 923 | (273 | ) | (1,154 | ) | 4,230 | ||||||||||||
Earnings per common share from continuing operations - assuming dilution | 3.69 | 1.62 | (0.50 | ) | (2.20 | ) | 7.31 | ||||||||||||
Dividends per common share | 0.30 | 0.20 | 0.60 | 0.57 | 0.48 | ||||||||||||||
Total assets | 42,783 | 37,621 | 35,572 | 34,417 | 42,722 | ||||||||||||||
Debt and capital lease obligations, less current portion | 6,732 | 7,515 | 7,163 | 6,264 | 6,470 | ||||||||||||||
___________________________
(a) | 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. |
(b) | We acquired three ethanol plants in the first quarter of 2010 and seven ethanol plants in the second quarter of 2009. The information presented for 2010 and 2009 includes the results of operations of 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. In the discussions that follow, per-share amounts include the effect of common equivalent shares for periods reflecting income from continuing operations and exclude the effect of common equivalent shares for periods reflecting a loss from continuing operations.
CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report, including without limitation our disclosures below under the heading “OVERVIEW AND OUTLOOK,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “believe,” “expect,” “plan,” “intend,” “estimate,” “project,” “projection,” “predict,” “budget,” “forecast,” “goal,” “guidance,” “target,” “could,” “should,” “may,” and similar expressions.
These forward-looking statements include, among other things, statements regarding:
• | future refining margins, including gasoline and distillate margins; |
• | future retail margins, including gasoline, diesel, home heating oil, and convenience store merchandise margins; |
• | future ethanol margins; |
• | expectations regarding feedstock costs, including crude oil differentials, and operating expenses; |
• | anticipated levels of crude oil and refined product inventories; |
• | 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, home 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 levels 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.
25
OVERVIEW AND OUTLOOK
We reported net income attributable to Valero stockholders from continuing operations of $2.1 billion, or $3.69 per share, for the year ended December 31, 2011 compared to $923 million, or $1.62 per share, for the year ended December 31, 2010. The improvement in net income attributable to Valero stockholders from continuing operations in 2011 versus 2010 was primarily due to an increase in operating income of $1.8 billion attributable to the business segments outlined in the following table (in millions):
Year Ended December 31, | ||||||||||||
2011 | 2010 | Change | ||||||||||
Operating income (loss) by business segment: | ||||||||||||
Refining | $ | 3,516 | $ | 1,903 | $ | 1,613 | ||||||
Retail | 381 | 346 | 35 | |||||||||
Ethanol | 396 | 209 | 187 | |||||||||
Corporate | (613 | ) | (582 | ) | (31 | ) | ||||||
Total | $ | 3,680 | $ | 1,876 | $ | 1,804 | ||||||
The increase of $1.6 billion in refining operating income was primarily due to the favorable difference between the price of sweet crude oils sourced from the inland U.S., such as West Texas Intermediate (WTI), versus the price of benchmark sweet crude oils, such as LLS and Brent. Historically, the price of WTI-type crude oil has closely approximated LLS and Brent crude oils. 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-type crude oil resulted in WTI-type crude oil being priced at a significant discount to LLS and Brent crude oils for most of 2011 as compared to 2010. Our McKee and Ardmore Refineries in the U.S. Mid-Continent region process WTI-type crude oils and significantly benefited from this favorable price difference.
The increase of $35 million in retail operating income was primarily due to higher fuel margins and volumes in our Canadian operations, including a favorable impact from the strengthening of the Canadian dollar relative to the U.S. dollar.
The increase of $187 million in ethanol operating income was primarily due to improved operating margins combined with an increase in production volumes to an average of 3.4 million gallons per day. The ethanol business is dependent on margins between ethanol and corn feedstocks and is impacted by U.S. government subsidies and biofuels (including ethanol) mandates.
On August 1, 2011, we acquired 100 percent of the outstanding shares of Chevron Limited from a subsidiary of Chevron Corporation and we subsequently changed the name of Chevron Limited to Valero Energy Ltd. Valero Energy Ltd owns and operates the Pembroke Refinery. Valero Energy Ltd also owns, directly and through various subsidiaries, an extensive network of marketing and logistics assets throughout the U.K. and Ireland. On the acquisition date, we initially paid $1.8 billion from available cash, of which $1.1 billion was for working capital. Subsequent to the acquisition date, we recorded an adjustment to working capital (primarily inventory), resulting in an adjusted purchase price of $1.7 billion. This acquisition is referred to as the Pembroke Acquisition.
26
On October 1, 2011, we acquired the Meraux Refinery and related logistics assets from Murphy Oil Corporation for an initial payment of $586 million, which was funded from available cash. In the fourth quarter of 2011, we recorded an adjustment related to inventories acquired that reduced the purchase price to $547 million.
The benefit we experienced in our refining business for most of 2011 from processing discounted WTI-type crude oils declined significantly during the fourth quarter of 2011 as the premium of LLS and Brent crude oils versus WTI-type crude oil narrowed considerably. In addition, our fourth quarter 2011 results reflected a significant decline in margins for most of the products we produce. Product margins have since improved in early 2012, but we expect the energy markets and margins to be volatile. The U.S. and worldwide refining business continues to experience capacity rationalization, particularly in Europe, the U.S. East Coast, and the Caribbean, where declining product margins have negatively impacted refineries in those regions. In particular, our Aruba Refinery has been negatively impacted. We restarted the Aruba Refinery in January 2011 after shutting it down temporarily in July 2009, but the refinery has not yet generated positive cash flows on a sustained basis. We are exploring strategic alternatives for the refinery, including alternative feedstocks, configuration changes, and a temporary or permanent shutdown of the refinery facilities. We expect to conclude our evaluation of these strategic alternatives in the first quarter of 2012. A decision to temporarily or permanently shut down the refinery or a revision to the future operating plans for the refinery that results in a decrease in future expected cash flows could result in the refinery being impaired. The Aruba Refinery had a net book value of $958 million as of December 31, 2011; therefore, an impairment loss would be material to our results of operations.
As of the date of the filing of this report, the financial markets continue to experience significant volatility and the overall impact on our business is uncertain at this time.
27
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.
2011 Compared to 2010
Financial Highlights (a) (b) (c) (d)
(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 | 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 interests | (1 | ) | — | (1 | ) | ||||||
Net income attributable to Valero stockholders | $ | 2,090 | $ | 324 | $ | 1,766 | |||||
Net income 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 | |||||
________________
See note references on page 33.
28
Operating Highlights
(millions of dollars, except per barrel amounts)
Year Ended December 31, | |||||||||||
2011 | 2010 | Change | |||||||||
Refining (a) (b) (c): | |||||||||||
Operating income | $ | 3,516 | $ | 1,903 | $ | 1,613 | |||||
Throughput margin per barrel (e) | $ | 9.30 | $ | 7.80 | $ | 1.50 | |||||
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 | $ | 3.96 | $ | 2.45 | $ | 1.51 | |||||
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 (f) | 494 | 395 | 99 | ||||||||
Total yields | 2,448 | 2,155 | 293 | ||||||||
See note references on page 33.
29
Refining Operating Highlights by Region (g)
(millions of dollars, except per barrel amounts)
Year Ended December 31, | |||||||||||
2011 | 2010 | Change | |||||||||
U.S. Gulf Coast: (a) | |||||||||||
Operating income | $ | 1,833 | $ | 1,349 | $ | 484 | |||||
Throughput volumes (thousand BPD) | 1,450 | 1,280 | 170 | ||||||||
Throughput margin per barrel (e) | $ | 8.63 | $ | 8.20 | $ | 0.43 | |||||
Operating costs per barrel: | |||||||||||
Operating expenses | 3.66 | 3.71 | (0.05 | ) | |||||||
Depreciation and amortization expense | 1.50 | 1.60 | (0.10 | ) | |||||||
Total operating costs per barrel | 5.16 | 5.31 | (0.15 | ) | |||||||
Operating income per barrel | $ | 3.47 | $ | 2.89 | $ | 0.58 | |||||
U.S. Mid-Continent: | |||||||||||
Operating income | $ | 1,413 | $ | 339 | $ | 1,074 | |||||
Throughput volumes (thousand BPD) | 411 | 398 | 13 | ||||||||
Throughput margin per barrel (e) | $ | 15.10 | $ | 7.33 | $ | 7.77 | |||||
Operating costs per barrel: | |||||||||||
Operating expenses | 4.15 | 3.60 | 0.55 | ||||||||
Depreciation and amortization expense | 1.52 | 1.40 | 0.12 | ||||||||
Total operating costs per barrel | 5.67 | 5.00 | 0.67 | ||||||||
Operating income per barrel | $ | 9.43 | $ | 2.33 | $ | 7.10 | |||||
North Atlantic (b): | |||||||||||
Operating income | $ | 171 | $ | 129 | $ | 42 | |||||
Throughput volumes (thousand BPD) | 317 | 195 | 122 | ||||||||
Throughput margin per barrel (e) | $ | 5.43 | $ | 6.18 | $ | (0.75 | ) | ||||
Operating costs per barrel: | |||||||||||
Operating expenses | 3.08 | 2.99 | 0.09 | ||||||||
Depreciation and amortization expense | 0.87 | 1.39 | (0.52 | ) | |||||||
Total operating costs per barrel | 3.95 | 4.38 | (0.43 | ) | |||||||
Operating income per barrel | $ | 1.48 | $ | 1.80 | $ | (0.32 | ) | ||||
U.S. West Coast: | |||||||||||
Operating income | $ | 99 | $ | 88 | $ | 11 | |||||
Throughput volumes (thousand BPD) | 256 | 256 | — | ||||||||
Throughput margin per barrel (e) | $ | 8.60 | $ | 7.73 | $ | 0.87 | |||||
Operating costs per barrel: | |||||||||||
Operating expenses | 5.25 | 5.09 | 0.16 | ||||||||
Depreciation and amortization expense | 2.29 | 1.69 | 0.60 | ||||||||
Total operating costs per barrel | 7.54 | 6.78 | 0.76 | ||||||||
Operating income per barrel | $ | 1.06 | $ | 0.95 | $ | 0.11 | |||||
Operating income for regions above | $ | 3,516 | $ | 1,905 | $ | 1,611 | |||||
Asset impairment loss applicable to refining | — | (2 | ) | 2 | |||||||
Total refining operating income | $ | 3,516 | $ | 1,903 | $ | 1,613 | |||||
__________
See note references on page 33.
30
Average Market Reference Prices and Differentials (h)
(dollars per barrel, except as noted)
Year Ended December 31, | |||||||||||
2011 | 2010 | Change | |||||||||
Feedstocks: | |||||||||||
LLS crude oil | $ | 111.47 | $ | 81.62 | $ | 29.85 | |||||
LLS less WTI crude oil | 16.42 | 2.21 | 14.21 | ||||||||
LLS less Alaska North Slope (ANS) crude oil | 1.93 | 2.55 | (0.62 | ) | |||||||
LLS less Brent crude oil | 0.54 | 2.09 | (1.55 | ) | |||||||
LLS less Mars crude oil | 4.00 | 3.62 | 0.38 | ||||||||
LLS less Maya crude oil | 12.72 | 11.34 | 1.38 | ||||||||
WTI crude oil | 95.05 | 79.41 | 15.64 | ||||||||
WTI less Mars crude oil | (12.42 | ) | 1.41 | (13.83 | ) | ||||||
WTI less Maya crude oil | (3.70 | ) | 9.13 | (12.83 | ) | ||||||
Products: | |||||||||||
U.S. Gulf Coast: | |||||||||||
Conventional 87 gasoline less LLS | $ | 5.04 | $ | 5.30 | $ | (0.26 | ) | ||||
Ultra-low-sulfur diesel less LLS | 13.24 | 8.93 | 4.31 | ||||||||
Propylene less LLS | 7.69 | 5.71 | 1.98 | ||||||||
Conventional 87 gasoline less WTI | 21.46 | 7.51 | 13.95 | ||||||||
Ultra-low-sulfur diesel less WTI | 29.66 | 11.14 | 18.52 | ||||||||
Propylene less WTI | 24.11 | 7.92 | 16.19 | ||||||||
U.S. Mid-Continent: | |||||||||||
Conventional 87 gasoline less WTI | 22.37 | 8.20 | 14.17 | ||||||||
Ultra-low-sulfur diesel less WTI | 31.06 | 11.91 | 19.15 | ||||||||
North Atlantic: | |||||||||||
Conventional 87 gasoline less Brent | 6.24 | 8.38 | (2.14 | ) | |||||||
Ultra-low-sulfur diesel less Brent | 15.64 | 12.63 | 3.01 | ||||||||
Conventional 87 gasoline less WTI | 22.12 | 8.50 | 13.62 | ||||||||
Ultra-low-sulfur diesel less WTI | 31.52 | 12.76 | 18.76 | ||||||||
U.S. West Coast: | |||||||||||
CARBOB 87 gasoline less ANS | 11.48 | 14.21 | (2.73 | ) | |||||||
CARB diesel less ANS | 18.47 | 13.79 | 4.68 | ||||||||
CARBOB 87 gasoline less WTI | 25.97 | 13.88 | 12.09 | ||||||||
CARB diesel less WTI | 32.96 | 13.45 | 19.51 | ||||||||
New York Harbor corn crush (dollars per gallon) | 0.25 | 0.39 | (0.14 | ) | |||||||
__________
See note references on page 33.
31
Operating Highlights (continued)
(millions of dollars, except per gallon amounts)
Year Ended December 31, | |||||||||||
2011 | 2010 | Change | |||||||||
Retail–U.S.: | |||||||||||
Operating income | $ | 213 | $ | 200 | $ | 13 | |||||
Company-operated fuel sites (average) | 994 | 990 | 4 | ||||||||
Fuel volumes (gallons per day per site) | 5,060 | 5,086 | (26 | ) | |||||||
Fuel margin per gallon | $ | 0.144 | $ | 0.140 | $ | 0.004 | |||||
Merchandise sales | $ | 1,223 | $ | 1,205 | $ | 18 | |||||
Merchandise margin (percentage of sales) | 28.7 | % | 28.3 | % | 0.4 | % | |||||
Margin on miscellaneous sales | $ | 88 | $ | 86 | $ | 2 | |||||
Operating expenses | $ | 416 | $ | 412 | $ | 4 | |||||
Depreciation and amortization expense | $ | 77 | $ | 73 | $ | 4 | |||||
Retail–Canada: | |||||||||||
Operating income | $ | 168 | $ | 146 | $ | 22 | |||||
Fuel volumes (thousand gallons per day) | 3,195 | 3,168 | 27 | ||||||||
Fuel margin per gallon | $ | 0.299 | $ | 0.271 | $ | 0.028 | |||||
Merchandise sales | $ | 261 | $ | 240 | $ | 21 | |||||
Merchandise margin (percentage of sales) | 29.4 | % | 30.1 | % | (0.7 | )% | |||||
Margin on miscellaneous sales | $ | 43 | $ | 38 | $ | 5 | |||||
Operating expenses | $ | 262 | $ | 242 | $ | 20 | |||||
Depreciation and amortization expense | $ | 38 | $ | 35 | $ | 3 | |||||
Ethanol (d): | |||||||||||
Operating income | $ | 396 | $ | 209 | $ | 187 | |||||
Ethanol production (thousand gallons per day) | 3,352 | 3,021 | 331 | ||||||||
Gross margin per gallon of ethanol production (e) | $ | 0.68 | $ | 0.55 | $ | 0.13 | |||||
Operating costs per gallon of production: | |||||||||||
Operating expenses | 0.33 | 0.33 | — | ||||||||
Depreciation and amortization expense | 0.03 | 0.03 | — | ||||||||
Total operating costs per gallon of production | 0.36 | 0.36 | — | ||||||||
Operating income per gallon of production | $ | 0.32 | $ | 0.19 | $ | 0.13 | |||||
__________
See note references on page 33.
32
The following notes relate to references on pages 28 through 32.
(a) | The financial highlights and operating highlights for the refining segment and U.S. Gulf Coast region include the results of operations of our Meraux Refinery, including related logistics assets, from the date of its acquisition on October 1, 2011 through December 31, 2011. |
(b) | The financial highlights and operating highlights for the refining segment and North Atlantic region include 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 through December 31, 2011. |
(c) | In 2010, we sold our Paulsboro Refinery and our shutdown Delaware City refinery assets and associated terminal and pipeline assets. The results of operations of these refineries have been presented as discontinued operations for the year ended December 31, 2010. In addition, the operating highlights for the refining segment and North Atlantic region exclude these refineries for the year ended December 31, 2010. |
(d) | We acquired three ethanol plants in the first quarter of 2010. The information presented includes the results of operations of these plants commencing on their respective acquisition dates. Ethanol production volumes are based on total production during each year divided by actual calendar days per year. |
(e) | 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. |
(f) | Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, and asphalt. |
(g) | 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 (formerly known as Northeast) region includes the Pembroke and Quebec City Refineries; and the U.S. West Coast region includes the Benicia and Wilmington Refineries. |
(h) | Average market reference prices for LLS crude oil, along with price differentials between the price of LLS crude oil and other types of crude oil, have been included in the table of Average Market Reference Prices and Differentials. The table also includes price differentials by region between the prices of certain products and the benchmark crude oil that provides the best indicator of product margins for each region. Prior to the first quarter of 2011, feedstock and product differentials were based on the price of WTI crude oil. However, the price of WTI crude oil no longer provides a reasonable benchmark price of crude oil for all regions. Beginning in late 2010, WTI crude oil began to price at a discount to benchmark sweet crude oils, such as LLS and Brent, because of increased WTI supplies resulting from greater U.S. production and increased deliveries of crude oil from Canada into the U.S. Mid-Continent region. Therefore, the use of the price of WTI crude oil as a benchmark price for regions that do not process WTI crude oil is no longer reasonable. |
General
Operating revenues increased 53 percent (or $43.8 billion) for the year ended December 31, 2011 compared to the year ended December 31, 2010 primarily as a result of higher average refined product prices and higher throughput volumes between the two years related to our refining segment operations. The higher throughput volumes resulted primarily from the incremental throughput of 33,000 BPD1 ($1.3 billion of revenue) from the Meraux Refinery, which was acquired on October 1, 2011, incremental throughput of 109,000 BPD1 ($7.5 billion of revenue) from the Pembroke Refinery, which was acquired on August 1, 2011, and incremental throughput of 145,000 BPD ($4.9 billion of revenue) from the Aruba Refinery, which restarted operations in January 2011. Operating income increased $1.8 billion and income from continuing operations before taxes also increased $1.8 billion for the year ended December 31, 2011 compared to the amounts reported for the year ended December 31, 2010 primarily due to a $1.6 billion increase in refining segment operating income discussed below.
_______________
1Calculated based on throughput volumes of the Meraux Refinery and the Pembroke Refinery from the date of their respective acquisitions (October 1, 2011 and August 1, 2011), divided by the number of days during the year ended December 31, 2011.
33
Refining
Refining segment operating income nearly doubled from $1.9 billion for the year ended December 31, 2010 to $3.5 billion for the year ended December 31, 2011. The $1.6 billion improvement in operating income was due to a $2.2 billion increase in refining margin, partially offset by a $462 million increase in operating expenses.
The $2.2 billion increase in refining margin was primarily due to a 19 percent increase in throughput margin per barrel (a $1.50 per barrel increase between the years). This increase in refining margin was largely driven by an improvement in the U.S. Mid-Continent region, which experienced an increase in its throughput margin per barrel of $7.77. The U.S. Mid-Continent throughput margin per barrel of $15.10 for the year ended December 31, 2011 was more than double the throughput margin per barrel of $7.33 for the year ended December 31, 2010. This increase was due to the substantial discount in the price of WTI-type crude oil, the primary type of crude oil processed by our U.S. Mid-Continent refineries, versus the price of LLS and Brent crude oils. Historically, the price of WTI-type crude oil has closely approximated LLS and Brent crude oils, 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-type crude oil resulted in WTI-type crude oil being priced at a significant discount to LLS and Brent crude oils during 2011. For example, the WTI-based benchmark reference margin for U.S. Mid-Continent conventional 87 gasoline was $22.37 per barrel for the year ended December 31, 2011 compared to $8.20 per barrel for the year ended December 31, 2010, representing a favorable increase of $14.17 per barrel. In addition, the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low sulfur diesel (a type of distillate) was $31.06 per barrel for the year ended December 31, 2011 compared to $11.91 per barrel for the year ended December 31, 2010, representing a favorable increase of $19.15 per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $1.1 billion and $1.0 billion, respectively, year over year.
The increase of $462 million in operating expenses discussed above was partially due to $42 million in operating expenses of the Meraux Refinery, which was acquired on October 1, 2011, and $141 million in operating expenses of the Pembroke Refinery, which was acquired on August 1, 2011. The remaining increase of $279 million was due to a $107 million increase in chemicals and catalyst costs, an $86 million increase in employee-related expenses, and a $75 million increase in reliability expenses.
Retail
Retail operating income was $381 million for the year ended December 31, 2011 compared to $346 million for the year ended December 31, 2010. This 10 percent (or $35 million) increase was primarily due to increases in fuel margins of $43 million primarily from our Canadian operations, including a favorable impact from the strengthening of the Canadian dollar relative to the U.S. dollar, and an increase in merchandise margins of $15 million, offset by increased operating expenses of $24 million.
Ethanol
Ethanol segment operating income was $396 million for the year ended December 31, 2011 compared to $209 million for the year ended December 31, 2010. This increase of $187 million was primarily due to a $226 million increase in gross margin, partially offset by a $36 million increase in operating expenses.
Gross margin increased from the year ended December 31, 2010 to the year ended December 31, 2011 due to an increase in ethanol production (a 331,000 gallon per day increase between the years) primarily resulting from the full operation of three additional plants acquired in the first quarter of 2010 and higher utilization rates and increased yields during 2011 combined with a $0.13 per gallon increase in the ethanol gross margin.
34
The increase in operating expenses was primarily due to $27 million of additional expenses related to the three ethanol plants acquired in the first quarter of 2010. We operated these plants for all of 2011 compared to part of 2010.
Corporate Expenses and Other
General and administrative expenses increased $40 million for the year ended December 31, 2011 compared to the year ended December 31, 2010 due to a $25 million increase in variable compensation expense, $27 million in costs incurred in connection with the Pembroke Acquisition, and a favorable settlement with an insurance company for $40 million recorded in 2010, which reduced general and administrative expenses in 2010. These increases in general and administrative expenses were partially offset by favorable legal settlements of $47 million in 2011.
“Other income, net” for the year ended December 31, 2011 decreased $63 million from the year ended December 31, 2010 due to a pre-tax gain of $55 million related to the sale of our 50 percent interest in Cameron Highway Oil Pipeline Company (CHOPS) recognized in November 2010 and the $16 million effect of earnings on our interest in CHOPS recognized in 2010.
“Interest and debt expense, net of capitalized interest” for the year ended December 31, 2011 decreased $83 million from the year ended December 31, 2010. This decrease is primarily due to an increase of $62 million in capitalized interest related to an increase in capital expenditures between the years and the resumption of construction activity on previously suspended projects combined with a $19 million favorable impact from the decrease in average borrowings.
Income tax expense for the year ended December 31, 2011 increased $651 million from the year ended December 31, 2010 mainly as a result of higher operating income in 2011 and a one-time $20 million income tax benefit recognized in 2010 related to a tax settlement with the Government of Aruba (GOA).
The loss from discontinued operations of $7 million for the year ended December 31, 2011 is primarily due to adjustments to the working capital settlement related to the sale of our Paulsboro Refinery in December 2010. The loss from discontinued operations of $599 million for the year ended December 31, 2010 represents a $47 million after-tax loss from the discontinued operations of the Delaware City and Paulsboro Refineries and a $610 million after-tax loss on the sale of the Paulsboro Refinery, partially offset by a $58 million after-tax gain on the sale of the shutdown refinery assets at Delaware City.
35
2010 Compared to 2009
Financial Highlights (a) (b) (c)
(millions of dollars, except per share amounts)
Year Ended December 31, | |||||||||||
2010 | 2009 | Change | |||||||||
Operating revenues | $ | 82,233 | $ | 64,599 | $ | 17,634 | |||||
Costs and expenses: | |||||||||||
Cost of sales | 74,458 | 58,686 | 15,772 | ||||||||
Operating expenses: | |||||||||||
Refining | 2,944 | 2,880 | 64 | ||||||||
Retail | 654 | 626 | 28 | ||||||||
Ethanol | 363 | 169 | 194 | ||||||||
General and administrative expenses | 531 | 572 | (41 | ) | |||||||
Depreciation and amortization expense: | |||||||||||
Refining | 1,210 | 1,194 | 16 | ||||||||
Retail | 108 | 101 | 7 | ||||||||
Ethanol | 36 | 18 | 18 | ||||||||
Corporate | 51 | 48 | 3 | ||||||||
Asset impairment loss (d) | 2 | 222 | (220 | ) | |||||||
Total costs and expenses | 80,357 | 64,516 | 15,841 | ||||||||
Operating income | 1,876 | 83 | 1,793 | ||||||||
Other income, net | 106 | 17 | 89 | ||||||||
Interest and debt expense, net of capitalized interest | (484 | ) | (416 | ) | (68 | ) | |||||
Income (loss) from continuing operations before income tax expense (benefit) | 1,498 | (316 | ) | 1,814 | |||||||
Income tax expense (benefit) | 575 | (43 | ) | 618 | |||||||
Income (loss) from continuing operations | 923 | (273 | ) | 1,196 | |||||||
Loss from discontinued operations, net of income taxes | (599 | ) | (1,709 | ) | 1,110 | ||||||
Net income (loss) | 324 | (1,982 | ) | 2,306 | |||||||
Less: Net loss attributable to noncontrolling interests | — | — | — | ||||||||
Net income (loss) attributable to Valero stockholders | $ | 324 | $ | (1,982 | ) | $ | 2,306 | ||||
Net income (loss) attributable to Valero stockholders: | |||||||||||
Continuing operations | $ | 923 | $ | (273 | ) | $ | 1,196 | ||||
Discontinued operations | (599 | ) | (1,709 | ) | 1,110 | ||||||
Total | $ | 324 | $ | (1,982 | ) | $ | 2,306 | ||||
Earnings per common share – assuming dilution: | |||||||||||
Continuing operations | $ | 1.62 | $ | (0.50 | ) | $ | 2.12 | ||||
Discontinued operations | (1.05 | ) | (3.17 | ) | 2.12 | ||||||
Total | $ | 0.57 | $ | (3.67 | ) | $ | 4.24 | ||||
__________
See note references on page 41.
36
Operating Highlights
(millions of dollars, except per barrel amounts)
Year Ended December 31, | |||||||||||
2010 | 2009 | Change | |||||||||
Refining (a) (b): | |||||||||||
Operating income (d) | $ | 1,903 | $ | 247 | $ | 1,656 | |||||
Throughput margin per barrel (e) | $ | 7.80 | $ | 6.00 | $ | 1.80 | |||||
Operating costs per barrel (d): | |||||||||||
Operating expenses | 3.79 | 3.71 | 0.08 | ||||||||
Depreciation and amortization expense | 1.56 | 1.55 | 0.01 | ||||||||
Total operating costs per barrel | 5.35 | 5.26 | 0.09 | ||||||||
Operating income per barrel | $ | 2.45 | $ | 0.74 | $ | 1.71 | |||||
Throughput volumes (thousand BPD): | |||||||||||
Feedstocks: | |||||||||||
Heavy sour crude | 458 | 457 | 1 | ||||||||
Medium/light sour crude | 386 | 417 | (31 | ) | |||||||
Acidic sweet crude | 60 | 64 | (4 | ) | |||||||
Sweet crude | 668 | 616 | 52 | ||||||||
Residuals | 204 | 170 | 34 | ||||||||
Other feedstocks | 110 | 136 | (26 | ) | |||||||
Total feedstocks | 1,886 | 1,860 | 26 | ||||||||
Blendstocks and other | 243 | 264 | (21 | ) | |||||||
Total throughput volumes | 2,129 | 2,124 | 5 | ||||||||
Yields (thousand BPD): | |||||||||||
Gasolines and blendstocks | 1,048 | 1,040 | 8 | ||||||||
Distillates | 712 | 692 | 20 | ||||||||
Other products (f) | 395 | 402 | (7 | ) | |||||||
Total yields | 2,155 | 2,134 | 21 | ||||||||
__________
See note references on page 41.
37
Refining Operating Highlights by Region (d) (g)
(millions of dollars, except per barrel amounts)
Year Ended December 31, | |||||||||||
2010 | 2009 | Change | |||||||||
U.S. Gulf Coast: | |||||||||||
Operating income (loss) | $ | 1,349 | $ | (56 | ) | $ | 1,405 | ||||
Throughput volumes (thousand BPD) | 1,280 | 1,274 | 6 | ||||||||
Throughput margin per barrel (e) | $ | 8.20 | $ | 5.13 | $ | 3.07 | |||||
Operating costs per barrel: | |||||||||||
Operating expenses | 3.71 | 3.71 | — | ||||||||
Depreciation and amortization expense | 1.60 | 1.54 | 0.06 | ||||||||
Total operating costs per barrel | 5.31 | 5.25 | 0.06 | ||||||||
Operating income (loss) per barrel | $ | 2.89 | $ | (0.12 | ) | $ | 3.01 | ||||
U.S. Mid-Continent: | |||||||||||
Operating income | $ | 339 | $ | 189 | $ | 150 | |||||
Throughput volumes (thousand BPD) | 398 | 387 | 11 | ||||||||
Throughput margin per barrel (e) | $ | 7.33 | $ | 6.52 | $ | 0.81 | |||||
Operating costs per barrel: | |||||||||||
Operating expenses | 3.60 | 3.66 | (0.06 | ) | |||||||
Depreciation and amortization expense | 1.40 | 1.53 | (0.13 | ) | |||||||
Total operating costs per barrel | 5.00 | 5.19 | (0.19 | ) | |||||||
Operating income per barrel | $ | 2.33 | $ | 1.33 | $ | 1.00 | |||||
North Atlantic (a) (b): | |||||||||||
Operating income | $ | 129 | $ | 196 | $ | (67 | ) | ||||
Throughput volumes (thousand BPD) | 195 | 196 | (1 | ) | |||||||
Throughput margin per barrel (e) | $ | 6.18 | |||||||||