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•	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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(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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•	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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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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•	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.

•	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.

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•	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.”

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(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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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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(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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•	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.

•	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.

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(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.

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(a)

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

(b)

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

(c)	We acquired three ethanol plants in the first quarter of 2010 and seven ethanol plants in the second quarter of 2009. The information presented includes the results of operations of 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.

(d)

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

(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, and Port Arthur Refineries; the U.S. Mid-Continent region includes the McKee, Ardmore, and Memphis Refineries; the North Atlantic region includes the Quebec City Refinery; and the U.S. West Coast region includes the Benicia and Wilmington Refineries.

(h)

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

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Changes in the margin we receive for our products have a material impact on our results of operations. For example, the WTI-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $11.14 per barrel for the year ended December 31, 2010 compared to $8.02 per barrel for the year ended December 31, 2009, representing a favorable increase of $3.12 per barrel. Similar increases in distillate margins were experienced in other regions. We estimate that the increase in margin for distillates had an $820 million positive impact on our overall refining margin, year over year, as we produced 712,000 BPD of distillates during the year ended December 31, 2010. Similarly, the WTI-based benchmark reference margin for U.S. Gulf Coast propylene was $7.92 per barrel for the year ended December 31, 2010 compared to a negative margin of $1.31 for the year ended December 31, 2009, representing a favorable increase of $9.23 per barrel. We estimate that the increase in margin for petrochemicals (primarily propylene) had a $199 million positive impact on our refining margin, year over year. Distillate and propylene margins were higher in 2010 as compared to 2009 due to an increase in the industrial demand for these products resulting from the ongoing recovery of the U.S. and worldwide economies and exports.

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

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

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•	fund $3.0 billion of capital expenditures and deferred turnaround and catalyst costs;

•	purchase the Pembroke Refinery and the related marketing and logistics business for $1.7 billion;

•	purchase the Meraux Refinery for $547 million;

•	redeem our Series 1997B 5.4% and Series 1997C 5.4% industrial revenue bonds for $56 million;

•	make scheduled long-term note repayments of $418 million;

•	acquire the Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds) for $300 million;

•	purchase our common stock for $349 million; and

•	pay common stock dividends of $169 million.

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

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

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

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

•	pay common stock dividends of $114 million;

•	purchase additional ethanol facilities for $260 million; and

•	increase available cash on hand by $2.5 billion.

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•	in December 2011, we redeemed our Series 1997B 5.4% and Series 1997C 5.4% industrial revenue bonds for $56 million, or 100% of their stated values;

•	in May 2011, we made a scheduled debt repayment of $200 million related to our 6.125% senior notes;

•	in April 2011, we made scheduled debt repayments of $8 million related to our Series 1997A 5.45%, Series 1997B 5.4%, and Series 1997C 5.4% industrial revenue bonds;

•	in February 2011, we made a scheduled debt repayment of $210 million related to our 6.75% senior notes; and

•	in February 2011, we paid $300 million to acquire the GO Zone Bonds, which were subject to mandatory tender.

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•	inventories and firm commitments to purchase inventories generally for amounts by which our current year inventory levels (determined on a last-in, first-out (LIFO) basis) differ from our previous year-end LIFO inventory levels and

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

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1.	BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

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

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

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

•	investments in entities that we do not control; and

•	other noncurrent assets such as convenience store dealer incentive programs, investments of certain benefit plans, debt issuance costs, and various other costs.

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2.	ACQUISITIONS

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3.	SALES OF ASSETS

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4.	IMPAIRMENT ANALYSIS

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5.	RECEIVABLES

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6.	INVENTORIES

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7.	PROPERTY, PLANT AND EQUIPMENT

8.	INTANGIBLE ASSETS

9.	DEFERRED CHARGES AND OTHER ASSETS

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10.	ACCRUED EXPENSES AND OTHER LONG-TERM LIABILITIES

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11.	DEBT AND CAPITAL LEASE OBLIGATIONS

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•	in December 2011, we redeemed our Series 1997B 5.4% and Series 1997C 5.4% industrial revenue bonds for $56 million, or 100% of their stated values;

•	in May 2011, we made a scheduled debt repayment of $200 million related to our 6.125% senior notes;

•	in April 2011, we made scheduled debt repayments of $8 million related to our Series 1997A 5.45%, Series 1997B 5.4%, and Series 1997C 5.4% industrial revenue bonds;

•	in February 2011, we made a scheduled debt repayment of $210 million related to our 6.75% senior

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•	in February 2011, we paid $300 million to acquire the Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds), which were subject to mandatory tender. We expect to hold the GO Zone Bonds for our own account until conditions permit the remarketing of these bonds at an interest rate acceptable to us.

•

in December 2010, the Parish of St. Charles, State of Louisiana (Issuer) issued GO Zone Bonds totaling $300 million, with a maturity date of December 1, 2040. The GO Zone Bonds initially bore interest at a weekly rate with interest payable monthly, commencing January 5, 2011. Pursuant to a financing agreement, the Issuer lent the proceeds of the sale of the GO Zone Bonds to us to finance a portion of the construction costs of a hydrocracker project at our St. Charles Refinery. We received proceeds of $300 million. Under the financing agreement, we were obligated to pay the Issuer amounts sufficient for the Issuer to pay principal and interest on the GO Zone Bonds;

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

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

•	in April 2010, we made scheduled debt repayments of $8 million related to our Series 1997A 5.45%, Series 1997B 5.4%, and Series 1997C 5.4% industrial revenue bonds;

•	in March 2010, we redeemed our 7.5% senior notes with a maturity date of June 15, 2015 for $294 million, or 102.5% of stated value, and

•	in February 2010, we issued $400 million of 4.5% notes due February 1, 2015 and $850 million of 6.125% notes due in February 1, 2020 for total net proceeds of $1.2 billion.

•	in October 2009, we redeemed $76 million of our 6.75% senior notes with a maturity date of October 15, 2037 at 100% of stated value;

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

•	in March 2009, we issued $750 million of 9.375% notes due March 15, 2019 and $250 million of 10.5% notes due March 15, 2039. Proceeds from the issuance of these notes totaled $998 million.

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12.	COMMITMENTS AND CONTINGENCIES

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The LCFS was scheduled to become effective in 2011, but recent rulings by the U.S. District Court have stayed enforcement of the LCFS until certain legal challenges to the LCFS have been resolved. Most notably, the court determined that the LCFS violates the Commerce Clause of the U.S. Constitution to the extent that the standard discriminates against out-of-state crude oils and corn ethanol. CARB has appealed the lower court’s ruling to the U.S. Court of Appeals for the Ninth Circuit.

▪	As initially designed, the LCFS called for initially small reductions in the carbon intensity of transportation fuels sold in California. The mandated reductions in carbon intensity were thereafter scheduled to increase through 2020, after which another step-change in reductions is anticipated.

▪	CARB designed the LCFS to encourage substitution of traditional petroleum fuels, and, over time, lead to greater use of electric cars and alternative fuels, such as E85, as companies seek to generate more credits to offset petroleum fuels.

•	A California statewide cap-and-trade program will begin in 2013. Initially, the program will apply only to stationary sources of greenhouse gases (e.g., refinery and power plant greenhouse gas

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Complying with AB 32, including the LCFS and the cap-and-trade program, could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce. To the degree we are unable to recover these increased costs, these matters could have a material adverse effect on our financial position, results of operations, and liquidity.

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13.	EQUITY

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14.	EMPLOYEE BENEFIT PLANS

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

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

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15.	STOCK-BASED COMPENSATION

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The 2011 Omnibus Stock Incentive Plan (the OSIP) authorizes the grant of various stock and stock-based awards to our employees and our non-employee directors. Awards available under the OSIP include options to purchase shares of common stock, performance awards that vest upon the achievement of an objective performance goal, stock appreciation rights, and restricted stock that vests over a period determined by our compensation committee. The OSIP was approved by our stockholders on April 28, 2011. As of December 31, 2011, 18,498,630 shares of our common stock remained available to be awarded under the OSIP.

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Prior to the approval of the OSIP by our stockholders, most of the equity awards granted to our employees and non-employee directors were made under our 2005 Omnibus Stock Incentive Plan. Prior awards granted under this plan included options to purchase shares of common stock, performance awards that vest upon the achievement of an objective performance goal, and restricted stock that vests over a period determined by our compensation committee. No additional grants may be awarded under this plan.

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The Restricted Stock Plan for Non-Employee Directors authorizes an annual grant of our common stock valued at $160,000 to each non-employee director. Vesting generally will occur based on the number of grants received as follows: (i) initial grants will vest in three equal annual installments, (ii) second grants will vest one-third on the first anniversary of the grant date and the remaining two-thirds on the second anniversary of the grant date, and (iii) all grants thereafter will vest 100 percent on the first anniversary of the grant date. As of December 31, 2011, 8,289 shares of our common stock remained available to be awarded under this plan.

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The 2003 Employee Stock Incentive Plan authorizes the grant of various stock and stock-related awards to employees and prospective employees. Awards include options to purchase shares of common stock, performance awards that vest upon the achievement of an objective performance goal, stock appreciation rights, and restricted stock that vests over a period determined by our compensation committee. As of December 31, 2011, 536,141 shares of our common stock remained available to be awarded under this plan.

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

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16.	INCOME TAXES

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17.	EARNINGS PER COMMON SHARE

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18.	SEGMENT INFORMATION

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19.	SUPPLEMENTAL CASH FLOW INFORMATION

•	the amounts shown above exclude changes in cash and temporary cash investments, deferred income taxes, and current portion of debt and capital lease obligations, as well as the effect of certain noncash investing and financing activities discussed below;

•	the amounts shown above exclude the current assets and current liabilities acquired in connection with the Meraux Acquisition in October 2011, the Pembroke Acquisition in August 2011, and the acquisitions of ethanol plants in 2010 and 2009;

•	amounts accrued for capital expenditures and deferred turnaround and catalyst costs are reflected in investing activities when such amounts are paid;

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

•	changes in assets held for sale and liabilities related to assets held for sale pertaining to the operations of the Paulsboro and Delaware City Refineries prior to their sale are reflected in the line items to which the changes relate in the table above; and

•	certain differences between balance sheet changes and the changes reflected above result from translating foreign currency denominated amounts at the applicable exchange rates as of each balance sheet date.

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20.	FAIR VALUE MEASUREMENTS

•	Level 1 - Observable inputs, such as unadjusted quoted prices in active markets for identical assets or liabilities.

•	Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.

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Level 3 - Unobservable inputs for the asset or liability for which there is little, if any, market activity at the measurement date. Unobservable inputs reflect our own assumptions about what market participants would use to price the asset or liability. The inputs are developed based on the best information available in the circumstances, which might include occasional market quotes or sales of similar instruments or our own financial data such as internally developed pricing models, discounted cash flow methodologies, as well as instruments for which the fair value determination requires significant judgment.

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Commodity derivative contracts consist primarily of exchange-traded futures and swaps, and as disclosed in Note 21, some of these contracts are designated as hedging instruments. These contracts are measured at fair value using the market approach. Exchange-traded futures are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy. Swaps are priced using third-party broker quotes, industry pricing services, and exchange-traded curves, with appropriate consideration of counterparty credit risk, but because they have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, these financial instruments are categorized in Level 2 of the fair value hierarchy.

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Physical purchase contracts to purchase inventories represent the fair value of firm commitments to purchase crude oil feedstocks and the fair value of fixed-price corn purchase contracts, and as disclosed in Note 21, some of these contracts are designated as hedging instruments. The fair values of these firm commitments and purchase contracts are measured using a market approach based on quoted prices from the commodity exchange, but because these commitments have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, they are categorized in Level 2 of the fair value hierarchy.

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Investments of certain benefit plan assets consist of investment securities held by trusts for the purpose of satisfying a portion of our obligations under certain U.S. nonqualified benefit plans. The assets categorized in Level 1 of the fair value hierarchy are measured at fair value using a market approach based on quotations from national securities exchanges. The assets categorized in Level 3 of the fair value hierarchy represent insurance contracts, the fair value of which is provided by the insurer. Obligations of certain benefit plans relate to certain U.S. nonqualified defined contribution plans under which our obligations to eligible employees are equal to the fair value of the assets held by those plans.

•	Other investments consist of (i) equity securities of private companies over which we do not exercise significant influence nor whose financial statements are consolidated into our financial statements

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Our biofuels blending obligation represents a liability for the purchase of RINs and RTFCs, as defined and described in Note 21 under “Compliance Program Price Risk,” to satisfy our obligation to blend biofuels into the products we produce. Our obligation is based on our deficiency in RINs and RTFCs and the price of these instruments as of the balance sheet date. Our obligation is categorized in Level 1 of the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.

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21.	PRICE RISK MANAGEMENT ACTIVITIES

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22.	QUARTERLY FINANCIAL DATA (Unaudited)

(a)	Includes the operations related to the Pembroke Acquisition beginning August 1, 2011.

(b)	Includes the operations related to the Meraux Acquisition beginning October 1, 2011.

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

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

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*	Filed herewith.

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

**	Submitted electronically herewith.

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