Edgar Filing: VALERO ENERGY CORP/TX

VLO 3.31.12 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended March 31, 2012



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

Commission file number 1-13175

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)



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

One Valero Way

San Antonio, Texas

(Address of principal executive offices)

78249

(Zip Code)

(210) 345-2000

(Registrant’s telephone number, including area code)

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 shorter period that the registrant was required to submit and post such files). Yes R No o

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 Rule 12b-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 number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of April 30, 2012 was 552,872,012.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

INDEX




	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011	3
Consolidated Statements of Income for the Three Months Ended March 31, 2012 and 2011	4
Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2012 and 2011	5
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011	6
Condensed Notes to Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3. Quantitative and Qualitative Disclosures About Market Risk	50
Item 4. Controls and Procedures	52
PART II – OTHER INFORMATION
Item 1. Legal Proceedings	53
Item 1A. Risk Factors	53
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 6. Exhibits	54
SIGNATURE	55

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Par Value)



	March 31, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	1,559		$	1,024
Receivables, net	7,418			8,706
Inventories	6,145			5,623
Income taxes receivable	226			212
Deferred income taxes	358			283
Prepaid expenses and other	118			124
Total current assets	15,824			15,972
Property, plant and equipment, at cost	32,253			32,253
Accumulated depreciation	(7,098		)	(7,076		)
Property, plant and equipment, net	25,155			25,177
Intangible assets, net	227			227
Deferred charges and other assets, net	1,428			1,407
Total assets	$	42,634		$	42,783
LIABILITIES AND EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	1,143		$	1,009
Accounts payable	9,941			9,472
Accrued expenses	483			595
Taxes other than income taxes	1,294			1,264
Income taxes payable	26			119
Deferred income taxes	189			249
Total current liabilities	13,076			12,708
Debt and capital lease obligations, less current portion	6,460			6,732
Deferred income taxes	5,210			5,017
Other long-term liabilities	1,896			1,881
Commitments and contingencies
Equity:
Valero Energy Corporation stockholders’ equity:
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 673,501,593 and 673,501,593 shares issued	7			7
Additional paid-in capital	7,479			7,486
Treasury stock, at cost; 120,526,015 and 116,689,450 common shares	(6,542		)	(6,475		)
Retained earnings	14,794			15,309
Accumulated other comprehensive income	221			96
Total Valero Energy Corporation stockholders’ equity	15,959			16,423
Noncontrolling interest	33			22
Total equity	15,992			16,445
Total liabilities and equity	$	42,634		$	42,783

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Millions of Dollars, Except Per Share Amounts)

(Unaudited)



	Three Months Ended March 31,
	2012			2011
Operating revenues (a)	$	35,167		$	26,308
Costs and expenses:
Cost of sales	33,035			24,568
Operating expenses:
Refining	964			744
Retail	166			162
Ethanol	87			95
General and administrative expenses	164			130
Depreciation and amortization expense	384			365
Asset impairment loss	611			—
Total costs and expenses	35,411			26,064
Operating income (loss)	(244		)	244
Other income, net	6			17
Interest and debt expense, net of capitalized interest	(99		)	(117		)
Income (loss) from continuing operations before income tax expense	(337		)	144
Income tax expense	95			40
Income (loss) from continuing operations	(432		)	104
Loss from discontinued operations, net of income taxes	—			(6		)
Net income (loss)	(432		)	98
Less: Net loss attributable to noncontrolling interests	—			—
Net income (loss) attributable to Valero Energy Corporation stockholders	$	(432	)	$	98
Net income (loss) attributable to Valero Energy Corporation stockholders:
Continuing operations	$	(432	)	$	104
Discontinued operations	—			(6		)
Total	$	(432	)	$	98
Earnings per common share:
Continuing operations	$	(0.78	)	$	0.18
Discontinued operations	—			(0.01		)
Total	$	(0.78	)	$	0.17
Weighted-average common shares outstanding (in millions)	551			566
Earnings per common share – assuming dilution:
Continuing operations	$	(0.78	)	$	0.18
Discontinued operations	—			(0.01		)
Total	$	(0.78	)	$	0.17
Weighted-average common shares outstanding – assuming dilution (in millions)	551			573
Dividends per common share	$	0.15		$	0.05



Supplemental information:
(a) Includes excise taxes on sales by our U.S. retail system	$	234	$	214

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)



	Three Months Ended March 31,
	2012			2011
Comprehensive income (loss)	$	(307	)	$	189

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

(Unaudited)



	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities:
Net income (loss)	$	(432	)	$	98
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	384			365
Asset impairment loss	611			—
Noncash interest expense and other income, net	7			7
Stock-based compensation expense	10			12
Deferred income tax expense (benefit)	61			(44		)
Changes in current assets and current liabilities	1,063			1,603
Changes in deferred charges and credits and other operating activities, net	—			17
Net cash provided by operating activities	1,704			2,058
Cash flows from investing activities:
Capital expenditures	(726		)	(438		)
Deferred turnaround and catalyst costs	(158		)	(299		)
Advance payment related to acquisition of Pembroke Refinery	—			(37		)
Other investing activities, net	10			(9		)
Net cash used in investing activities	(874		)	(783		)
Cash flows from financing activities:
Non-bank debt:
Repayments	—			(510		)
Accounts receivable sales program:
Repayments	(150		)	—
Purchase of common stock for treasury	(106		)	—
Proceeds from the exercise of stock options	9			21
Common stock dividends	(83		)	(28		)
Contributions from noncontrolling interest	11			—
Other financing activities, net	—			5
Net cash used in financing activities	(319		)	(512		)
Effect of foreign exchange rate changes on cash	24			36
Net increase in cash and temporary cash investments	535			799
Cash and temporary cash investments at beginning of period	1,024			3,334
Cash and temporary cash investments at end of period	$	1,559		$	4,133

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

General

As used in this report, the terms “Valero,” “we,” “us,” or “our” may refer to Valero Energy Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole.

These unaudited financial statements have been prepared in accordance with United States (U.S.) generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the three months ended March 31, 2012 and 2011 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited financial statements. Operating results for the three months ended March 31, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012.

The balance sheet as of December 31, 2011 has been derived from our audited financial statements as of that date. For further information, refer to our financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2011.

Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, we review our estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

Comprehensive Income

Effective January 1, 2012, we adopted the provisions of Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” and have elected to present the total for comprehensive income in a statement that is separate from the statement of income but placed directly after the statement of income.

Comprehensive income (loss) for the three months ended March 31, 2012 and 2011 of $(307) million and $189 million, respectively, differs from net income (loss) of $(432) million and $98 million, respectively, primarily due to the foreign currency translation adjustments recorded in the respective quarter related to our investments in subsidiaries in Canada and the United Kingdom (U.K.).

Fair Value Measurements

Effective January 1, 2012, we adopted the provisions of ASC Topic 820, “Fair Value Measurement,” which clarified the application of existing fair value measurement requirements and changed certain fair value measurement and disclosure requirements. The adoption of these provisions did not affect our financial position or results of operations as these requirements only affected disclosures as reflected in Note 12.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

New Accounting Pronouncements

In December 2011, the provisions of ASC Topic 210, “Balance Sheet,” were amended to require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of these arrangements on its financial position. The guidance requires entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the balance sheet and instruments and transactions subject to an agreement similar to a master netting arrangement. These provisions are effective for interim and annual reporting periods beginning on January 1, 2013. The adoption of this guidance effective January 1, 2013 will not affect our financial position or results of operations, but may result in additional disclosures.


2.	ACQUISITIONS

The acquired refining and marketing businesses discussed below involve the production and marketing of refined petroleum products. These acquisitions are consistent with our general business strategy and complement our existing refining and marketing network.

Meraux Acquisition

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 assets acquired and liabilities assumed in this acquisition were recognized at their acquisition-date estimated fair values, as disclosed in Note 2 of Notes to Consolidated Financial Statements included in our annual report on Form 10-K for the year ended December 31, 2011, and no adjustments to those estimated amounts have been made during the three months ended March 31, 2012. We are, however, awaiting the completion of an independent appraisal and other evaluations of the fair values of the assets acquired and liabilities assumed.

Pembroke Acquisition

On August 1, 2011, we acquired 100 percent of the outstanding shares of Chevron Limited from a subsidiary of Chevron Corporation (Chevron), and we subsequently changed the name of Chevron Limited to Valero Energy Ltd. On the acquisition date, we initially paid $1.8 billion from available cash, of which $1.1 billion was for working capital. In the fourth quarter of 2011, we recorded adjustments to working capital (primarily inventory), resulting in an adjusted purchase price of $1.7 billion. The assets acquired and liabilities assumed in this acquisition were recognized at their acquisition-date estimated fair values, as disclosed in Note 2 of Notes to Consolidated Financial Statements included in our annual report on Form 10-K for the year ended December 31, 2011, and no adjustments to those estimated amounts have been made during the three months ended March 31, 2012. We are, however, awaiting the completion of an independent appraisal and other evaluations of the fair values of the assets acquired and liabilities assumed. This acquisition is referred to as the Pembroke Acquisition.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


3.	IMPAIRMENT

In March 2012, we decided to suspend the operations of the Aruba Refinery by the end of March. Our decision was based on the refinery’s inability to generate positive cash flows on a sustained basis subsequent to its restart in January 2011 and the sensitivity of its profitability to sour crude oil differentials, which narrowed significantly in the fourth quarter of 2011. We considered the use of alternative feedstocks or configuration changes that might improve the refinery’s cash flows and we also considered a temporary or permanent shutdown of the refinery facilities. We ultimately decided to shut down the refinery and to maintain it in a state that would allow for operations to be resumed.

On March 28, 2012, we received a non-binding indication of interest from an unrelated interested party to purchase the Aruba Refinery for $350 million, plus working capital as of the closing date, subject to completion of due diligence and further negotiations. The due diligence process is currently ongoing and no final agreement has been reached to sell the refinery. We have accepted this offer, subject to the finalization of the purchase and sale agreement. The Aruba Refinery is classified as “held and used” because all of the accounting criteria required for “held for sale” classification have not been met.

Because of our decision to suspend the operations of the Aruba Refinery and the possibility that we may sell the refinery, we evaluated the refinery for potential impairment and concluded that the Aruba Refinery was impaired as of March 31, 2012. As a result, we were required to determine the fair value of the Aruba Refinery and to write down its carrying value to that amount. We determined that the best measure of the refinery’s fair value as of March 31, 2012 was the $350 million offer described above, which was based on the interested party’s specific knowledge of the refinery, experience in the refining and marketing industry, and extensive knowledge of the current economic factors of our business. The carrying value of the Aruba Refinery’s long-lived assets as of March 31, 2012 was $945 million; therefore, we recognized an asset impairment loss of $595 million.

There is no certainty that we will sell the refinery to the interested party, or to any other party, and if we ultimately sell the refinery, there is no certainty that we will sell it for $350 million. In addition, should we be unable to sell the refinery, we may have to recognize an additional asset impairment loss.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


4.	INVENTORIES

Inventories consisted of the following (in millions):



	March 31, 2012		December 31, 2011
Refinery feedstocks	$	2,730	$	2,474
Refined products and blendstocks	2,862		2,633
Ethanol feedstocks and products	236		195
Convenience store merchandise	98		103
Materials and supplies	219		218
Inventories	$	6,145	$	5,623

As of March 31, 2012 and December 31, 2011, the replacement cost (market value) of last in, first out (LIFO) inventories exceeded their LIFO carrying amounts by approximately $8.7 billion and $6.8 billion, respectively.


5.	DEBT

Non-Bank Debt

In March 2012, we exercised the call provisions on our Series 1997 5.6%, Series 1998 5.6%, Series 1999 5.7%, Series 2001 6.65%, and Series 1997A 5.45% industrial revenue bonds, which were redeemed on May 3, 2012 for $108 million, or 100 percent of their outstanding stated values.

In April 2012, we made scheduled debt repayments of $4 million related to our Series 1997A 5.45% industrial revenue bonds and $750 million related to our 6.875% notes.

During the three months ended March 31, 2011, the following activity occurred:


•	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 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.

Bank Debt and Credit Facilities

We have a $3 billion revolving credit facility (the Revolver) that has a maturity date of December 2016. The Revolver has certain restrictive covenants, including a maximum debt-to-capitalization ratio of 60 percent. As of March 31, 2012 and December 31, 2011, our debt-to-capitalization ratios, calculated in accordance with the terms of the Revolver, were 27 percent and 29 percent, respectively. We believe that we will remain in compliance with this covenant.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In addition to the Revolver, one of our Canadian subsidiaries has a committed revolving credit facility under which it may borrow and obtain letters of credit up to C$115 million.

During the three months ended March 31, 2012 and 2011, we had no borrowings or repayments under our Revolver or the Canadian revolving credit facility. As of March 31, 2012 and December 31, 2011, we had no borrowings outstanding under the Revolver or the Canadian revolving credit facility.

We had outstanding letters of credit under our committed lines of credit as follows (in millions):



				Amounts Outstanding
	Borrowing Capacity		Expiration	March 31, 2012		December 31, 2011
Letter of credit facilities	$	500	June 2012	$	500	$	300
Revolver	$	3,000	December 2016	$	153	$	119
Canadian revolving credit facility	C$	115	December 2012	C$	20	C$	20

As of March 31, 2012 and December 31, 2011, we had $456 million and $391 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities.

Accounts Receivable Sales Facility

We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables. The facility matures in June 2012. Proceeds from the sale of receivables under this facility are reflected as debt. Changes in the amounts outstanding under our accounts receivable sales facility were as follows (in millions):



	Three Months Ended March 31,
	2012			2011
Balance as of beginning of period	$	250		$	100
Proceeds from the sale of receivables	—			—
Repayments	(150		)	—
Balance as of end of period	$	100		$	100

In late April 2012, we sold $850 million of eligible receivables to the third-party entities and financial institutions under this facility, and we repaid $500 million on May 4, 2012.

Capitalized Interest

For the three months ended March 31, 2012 and 2011, capitalized interest was $52 million and $27 million, respectively.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


6.	COMMITMENTS AND CONTINGENCIES

Environmental Matters

The U.S. Environmental Protection Agency (EPA) began regulating greenhouse gases on January 2, 2011, under the Clean Air Act Amendments of 1990 (Clean Air Act). Any new construction or material expansions will require that, among other things, a greenhouse gas permit be issued at either or both the state or federal level in accordance with the Clean Air Act and regulations, and we will be required to undertake a technology review to determine appropriate controls to be implemented with the project in order to reduce greenhouse gas emissions. The determination would be on a case by case basis, and the EPA has provided only general guidance on which controls will be required.

Furthermore, the EPA is currently developing refinery-specific greenhouse gas regulations and performance standards that are expected to impose, on new and existing operations, greenhouse gas emission limits and/or technology requirements. These control requirements may affect a wide range of refinery operations but have not yet been delineated. Any such controls, however, could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

Certain states and foreign governments have pursued regulation of greenhouse gases independent of the EPA. For example, the California Global Warming Solutions Act, also known as AB 32, directs the California Air Resources Board (CARB) to develop and issue regulations to reduce greenhouse gas emissions in California to 1990 levels by 2020. The CARB has issued a variety of regulations aimed at reaching this goal, including a Low Carbon Fuel Standard (LCFS) as well as a statewide cap-and-trade program.

•

The LCFS was scheduled to become effective in 2011, but rulings by the U.S. District Court stayed enforcement of the LCFS until certain legal challenges to the LCFS were 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 appealed the lower court’s ruling to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit Court).

The Ninth Circuit Court lifted the stay on April 23, 2012. We anticipate that the Ninth Circuit Court will hear arguments on the merits of the appeal this year, with a final ruling sometime thereafter.

•

A California statewide cap-and-trade program will begin in late 2012. Initially, the program will apply only to stationary sources of greenhouse gases (e.g., refinery and power plant greenhouse gas emissions). Greenhouse gas emissions from fuels that we sell in California will be covered by the program beginning in 2015. We anticipate that free allocations of credits will be available in the early years of the program to cover most of our stationary emissions, but we expect that compliance costs will increase significantly beginning in 2015, when transportation fuels are included in the program.

•

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

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In the first quarter of 2012, CARB adopted amendments to its Clean Fuels Outlet (CFO) Regulation. CARB states that the CFO Regulation is intended to provide outlets of clean fuel to meet the needs of alternative fuel vehicles. We understand that CARB is preparing to submit the CFO Regulation to the State Office of Administrative Law for approval. The regulation would require major refiners and importers of gasoline, including Valero, to install clean fuel outlets at five percent of California’s retail stations for hydrogen fueling and electric vehicle charging. We expect this regulation to be challenged, but we could be required to make significant capital expenditures if the regulation is implemented as presently adopted.

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

Tax Matters

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.

As of March 31, 2012, the Internal Revenue Service (IRS) has ongoing tax audits related to our U.S. federal tax returns from 2002 through 2009. We have received Revenue Agent Reports on our tax years for 2002 through 2007 and we are vigorously contesting the tax positions and assertions from the IRS. Although we believe our tax liabilities are fairly stated and properly reflected in our financial statements, should the IRS eventually prevail, it could result in a material amount of our deferred tax liabilities being reclassified to current liabilities which could have a material adverse effect on our liquidity.

Litigation Matters

We are party to claims and legal proceedings arising in the ordinary course of business. We have not recorded a loss contingency liability with respect to some of these matters because we have determined that it is remote that a loss has been incurred. For other matters, we have recorded a loss contingency liability where we have determined that it is probable that a loss has been incurred and that the loss is reasonably estimable. These loss contingency liabilities are not material to our financial position. We re-evaluate and update our loss contingency liabilities as matters progress over time, and we believe that any changes to the recorded

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

liabilities will not be material to our financial position or results of operations.


7.	EQUITY

The following is a reconciliation of the beginning and ending balances (in millions) of equity attributable to our stockholders, equity attributable to the noncontrolling interest, and total equity for the three months ended March 31, 2012 and 2011:



	2012								2011
	Valero Stockholders’ Equity			Non- controlling Interest		Total Equity			Valero Stockholders’ Equity			Non- controlling Interest		Total Equity
Balance at beginning of period	$	16,423		$	22	$	16,445		$	15,025		$	—	$	15,025
Net income (loss)	(432		)	—		(432		)	98			—		98
Dividends	(83		)	—		(83		)	(28		)	—		(28		)
Stock-based compensation expense	10			—		10			12			—		12
Tax deduction in excess of stock-based compensation expense	2			—		2			5			—		5
Transactions in connection with stock-based compensation plans:
Stock issuances	9			—		9			21			—		21
Stock repurchases	(95		)	—		(95		)	—			—		—
Contributions from noncontrolling interest	—			11		11			—			—		—
Other comprehensive income	125			—		125			91			—		91
Balance at end of period	$	15,959		$	33	$	15,992		$	15,224		$	—	$	15,224

The noncontrolling interest relates to the ownership interest in Diamond Green Diesel Holdings LLC that is owned by a party unrelated to us.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Share Activity

Activity in the number of shares of common stock and treasury stock was as follows (in millions) for the three months ended March 31, 2012 and 2011:



	2012			2011
	Common Stock	Treasury Stock		Common Stock	Treasury Stock
Balance as of beginning of period	673	(117	)	673	(105	)
Transactions in connection with stock-based compensation plans:
Stock issuances	—	1		—	2
Stock purchases	—	(5	)	—	—
Balance as of end of period	673	(121	)	673	(103	)

Common Stock Dividends

On May 3, 2012, our board of directors declared a quarterly cash dividend of $0.15 per common share payable on June 20, 2012 to holders of record at the close of business on May 23, 2012.


8.	EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost related to our defined benefit plans were as follows (in millions) for the three months ended March 31, 2012 and 2011:



	Pension Plans						Other Postretirement Benefit Plans
	2012			2011			2012			2011
Service cost	$	35		$	23		$	3		$	3
Interest cost	23			21			5			6
Expected return on plan assets	(31		)	(28		)	—			—
Amortization of:
Prior service cost (credit)	1			1			(5		)	(6		)
Net loss	8			3			—			—
Net periodic benefit cost	$	36		$	20		$	3		$	3

Our anticipated contributions to our pension plans during 2012 have not changed from amounts previously disclosed in our financial statements for the year ended December 31, 2011. There were no significant contributions made to our pension plans during the three months ended March 31, 2012 and 2011.

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9.	EARNINGS PER COMMON SHARE

Earnings per common share from continuing operations were computed as follows (dollars and shares in millions, except per share amounts) for the three months ended March 31, 2012 and 2011:



	2012					2011
	Restricted Stock		Common Stock			Restricted Stock		Common Stock
Earnings per common share from continuing operations:
Net income (loss) attributable to Valero stockholders from continuing operations			$	(432	)			$	104
Less dividends paid:
Common stock			83					28
Nonvested restricted stock			—					—
Undistributed earnings (loss)			$	(515	)			$	76
Weighted-average common shares outstanding	3		551			3		566
Earnings per common share from continuing operations:
Distributed earnings	$	0.15	$	0.15		$	0.05	$	0.05
Undistributed earnings	—		(0.93		)	0.13		0.13
Total earnings per common share from continuing operations	$	0.15	$	(0.78	)	$	0.18	$	0.18

Earnings per common share from continuing operations – assuming dilution:
Net income (loss) attributable to Valero stockholders from continuing operations			$	(432	)			$	104
Weighted-average common shares outstanding			551					566
Common equivalent shares:
Stock options			—					5
Performance awards and unvested restricted stock			—					2
Weighted-average common shares outstanding – assuming dilution			551					573
Earnings per common share from continuing operations – assuming dilution			$	(0.78	)			$	0.18

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The following table reflects potentially dilutive securities (in millions) that were excluded from the calculation of “earnings per common share from continuing operations – assuming dilution” as the effect of including such securities would have been antidilutive. These potentially dilutive securities included common equivalent shares (primarily stock options), which were excluded due to the loss from continuing operations for three months ended March 31, 2012, and stock options for which the exercise prices were greater than the average market price of our common shares during each respective reporting period.



	2012	2011
Common equivalent shares	6	—
Stock options	6	6


10.	SEGMENT INFORMATION

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



	Refining			Retail		Ethanol		Corporate			Total
Three months ended March 31, 2012:
Operating revenues from external customers	$	31,150		$	2,935	$	1,082	$	—		$	35,167
Intersegment revenues	2,255			—		14		—			2,269
Operating income (loss)	(119		)	40		9		(174		)	(244		)

Three months ended March 31, 2011:
Operating revenues from external customers	22,562			2,684		1,062		—			26,308
Intersegment revenues	1,997			—		48		—			2,045
Operating income (loss)	276			66		44		(142		)	244

Total assets by reportable segment were as follows (in millions):



	March 31, 2012		December 31, 2011
Refining	$	37,600	$	38,164
Retail	2,049		1,999
Ethanol	982		943
Corporate	2,003		1,677
Total assets	$	42,634	$	42,783

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11.	SUPPLEMENTAL CASH FLOW INFORMATION

In order to determine net cash provided by operating activities, net income is adjusted by, among other things, changes in current assets and current liabilities as follows (in millions) for the three months ended March 31, 2012 and 2011:



	2012			2011
Decrease (increase) in current assets:
Receivables, net	$	1,319		$	(1,258	)
Inventories	(471		)	622
Income taxes receivable	(14		)	(25		)
Prepaid expenses and other	6			10
Increase (decrease) in current liabilities:
Accounts payable	410			2,143
Accrued expenses	(100		)	174
Taxes other than income taxes	9			(160		)
Income taxes payable	(96		)	97
Changes in current assets and current liabilities	$	1,063		$	1,603

The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable balance sheets for the respective periods for the following reasons:


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


•	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; and


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

There were no significant noncash investing or financing activities for the three months ended March 31, 2012 or 2011.

Cash flows related to interest and income taxes were as follows (in millions) for the three months ended March 31, 2012 and 2011:



	2012		2011
Interest paid in excess of amount capitalized	$	45	$	77
Income taxes paid, net	142		3

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12.	FAIR VALUE MEASUREMENTS

General

GAAP requires that certain financial instruments, such as derivative instruments, be recognized at their fair values in our balance sheets. However, other financial instruments, such as debt obligations, are not required to be recognized at their fair values, but GAAP provides an option to elect fair value accounting for these instruments. GAAP requires the disclosure of the fair values of all financial instruments, regardless of whether they are recognized at their fair values or carrying amounts in our balance sheets. For financial instruments recognized at fair value, GAAP requires the disclosure of their fair values by type of instrument, along with other information, including changes in the fair values of certain financial instruments recognized in income or other comprehensive income, and this information is provided below under “Recurring Fair Value Measurements.” For financial instruments not recognized at fair value, the disclosure of their fair values is provided below under “Other Financial Instruments.”

Nonfinancial assets, such as property, plant and equipment, and nonfinancial liabilities are recognized at their carrying amounts in our balance sheets. GAAP does not permit nonfinancial assets and liabilities to be remeasured at their fair values. However, GAAP requires the remeasurement of such assets and liabilities to their fair values upon the occurrence of certain events, such as the impairment of property, plant and equipment. In addition, if such an event occurs, GAAP requires the disclosure of the fair value of the asset or liability along with other information, including the gain or loss recognized in income in the period the remeasurement occurred. This information is provided below under “Nonrecurring Fair Value Measurements.”

GAAP provides a framework for measuring fair value and establishes a three-level fair value hierarchy that prioritizes inputs to valuation techniques based on the degree to which objective prices in external active markets are available to measure fair value. Following is a description of each of the levels of the fair value hierarchy.


•	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.

•

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.

The financial instruments and nonfinancial assets and liabilities included in our disclosure of recurring and nonrecurring fair value measurements are categorized according to the fair value hierarchy based on the inputs used to measure their fair values.

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Recurring Fair Value Measurements

The tables below present information (in millions) about our financial instruments recognized at their fair values in our balance sheets categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of March 31, 2012 and December 31, 2011.

Cash collateral deposits of $199 million and $136 million with brokers under master netting arrangements are included in the fair value of the commodity derivatives reflected in Level 1 as of March 31, 2012 and December 31, 2011, respectively. Certain of our commodity derivative contracts under master netting arrangements include both asset and liability positions. We have elected to offset the fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty, including any related cash collateral asset or obligation under the column “Netting Adjustments” below; however, fair value amounts by hierarchy level are presented on a gross basis in the tables below.



	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Netting Adjustments			Total Fair Value as of March 31, 2012
Assets:
Commodity derivative contracts	$	2,310	$	162		$	—	$	(2,302	)	$	170
Physical purchase contracts	—		(36		)	—		—			(36		)
Investments of certain benefit plans	89		—			11		—			100
Foreign currency contracts	1		—			—		—			1
Other investments	—		—			—		—			—
Liabilities:
Commodity derivative contracts	2,145		165			—		(2,302		)	8
Biofuels blending obligation	3		—			—		—			3
Obligations of certain benefit plans	36		—			—		—			36
Foreign currency contracts	3		—			—		—			3

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	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Netting Adjustments			Total Fair Value as of December 31, 2011
Assets:
Commodity derivative contracts	$	2,038	$	78		$	—	$	(1,940	)	$	176
Physical purchase contracts	—		(2		)	—		—			(2		)
Investments of certain benefit plans	84		—			11		—			95
Other investments	—		—			—		—			—
Liabilities:
Commodity derivative contracts	1,864		101			—		(1,940		)	25
Obligations of certain benefit plans	34		—			—		—			34
Foreign currency contracts	3		—			—		—			3

A description of our financial instruments and the valuation methods used to measure those instruments at fair value are as follows:

•

Commodity derivative contracts consist primarily of exchange-traded futures and swaps, and as disclosed in Note 13, 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.

•

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 13, 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.

•

Investments of certain benefit plans 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 quoted prices 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.


•	Foreign currency contracts consist of foreign currency exchange and purchase contracts entered into by our international operations to manage our exposure to exchange rate fluctuations on transactions

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denominated in currencies other than the local (functional) currencies of those operations. These contracts are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy.

•

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 and (ii) debt securities of a private company whose financial statements are not consolidated into our financial statements. We have elected to account for these investments at their fair values. These investments are categorized in Level 3 of the fair value hierarchy as the fair values of these investments are determined using the income approach based on internally developed analyses.

•

Our biofuels blending obligation represents a liability for the purchase of RINs and RTFCs, as defined and described in Note 13 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.

The following is a reconciliation of the beginning and ending balances (in millions) for fair value measurements developed using significant unobservable inputs (Level 3) for the three months ended March 31, 2012 and 2011.



	2012				2011
	Investments of Certain Benefit Plans		Other Investments		Investments of Certain Benefit Plans		Other Investments
Balance as of beginning of period	$	11	$	—	$	10	$	—
Purchases	—		—		—		6
Total gains (losses) included in income	—		—		1		(6		)
Transfers in and/or out of Level 3	—		—		—		—
Balance as of end of period	$	11	$	—	$	11	$	—
The amount of total gains (losses) included in income attributable to the change in unrealized gains (losses) relating to assets still held at end of period	$	—	$	—	$	1	$	(6	)

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Nonrecurring Fair Value Measurements

The table below presents the fair value (in millions) of our nonfinancial assets measured on a nonrecurring basis during the three months ended March 31, 2012 and categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of March 31, 2012.



	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value as of March 31, 2012		Total Loss Recognized During the Three Months Ended March 31, 2012
Assets:
Long-lived assets of the Aruba Refinery	$	—	$	—	$	350	$	350	$	595
Cancelled capital project	—		—		2		2		16

As discussed in Note 3, we concluded that the Aruba Refinery was impaired as of March 31, 2012. As a result, we were required to determine the fair value of the Aruba Refinery and to write down its carrying value to that amount. We determined that the best measure of the refinery’s fair value as of March 31, 2012 was the $350 million offer received and accepted, subject to the finalization of the purchase and sale agreement. We believe this offer represents what a market participant would pay us for the assets in their highest and best use, as more fully discussed in Note 3. The fair value of the Aruba Refinery was measured using the market approach and is categorized in Level 3 within the fair value hierarchy. The carrying value of the Aruba Refinery’s long-lived assets as of March 31, 2012 was $945 million; therefore, we recognized an asset impairment loss of $595 million during the three months ended March 31, 2012.

We recognized an asset impairment loss of $16 million during the three months ended March 31, 2012 related to equipment associated with a capital project that was cancelled permanently in 2009. We had written down the carrying value of this equipment to fair value in 2009, but we have been unable to sell the equipment. As a result, we wrote down the carrying amount of the equipment to scrap value.

There were no liabilities that were measured at fair value on a nonrecurring basis during the three months ended March 31, 2012. There were no assets or liabilities that were measured at fair value on a nonrecurring basis during the three months ended March 31, 2011.

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Other Financial Instruments

Financial instruments that we recognize in our balance sheets at their carrying amounts include cash and temporary cash investments, receivables, payables, debt and capital lease obligations. The fair values of these financial instruments approximate their carrying amounts, except for debt as shown in the table below (in millions):



	March 31, 2012		December 31, 2011
Carrying amount (excluding capital leases)	$	7,554	$	7,690
Fair value	8,653		9,298

The fair value of our debt is determined primarily using the market approach based on quoted prices in active markets (Level 1).


13.	PRICE RISK MANAGEMENT ACTIVITIES

We are exposed to market risks related to the volatility in the price of commodities, the price of financial instruments associated with governmental and regulatory compliance programs, interest rates, and foreign currency exchange rates, and we enter into derivative instruments to manage some of these risks. We also enter into derivative instruments to manage the price risk on other contractual derivatives into which we have entered. The only types of derivative instruments we enter into are those related to the various commodities we purchase or produce, financial instruments we must purchase to maintain compliance with various governmental and regulatory programs, interest rate swaps, and foreign currency exchange and purchase contracts, as described below. All derivative instruments are recorded as either assets or liabilities measured at their fair values (see Note 12).

When we enter into a derivative instrument, it is designated as a fair value hedge, a cash flow hedge, an economic hedge, or a trading derivative. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting loss or gain on the hedged item attributable to the hedged risk, is recognized currently in income in the same period. The effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is initially reported as a component of other comprehensive income and is then recorded in income in the period or periods during which the hedged forecasted transaction affects income. The ineffective portion of the gain or loss on the cash flow derivative instrument, if any, is recognized in income as incurred. For our economic hedges (derivative instruments not designated as fair value or cash flow hedges) and for derivative instruments entered into by us for trading purposes, the derivative instrument is recorded at fair value and changes in the fair value of the derivative instrument are recognized currently in income. The cash flow effects of all of our derivative instruments are reflected in operating activities in our statements of cash flows for all periods presented.

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Commodity Price Risk

We are exposed to market risks related to the volatility in the price of crude oil, refined products (primarily gasoline and distillate), grain (primarily corn), and natural gas used in our operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, including futures, swaps, and options. We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations. We use swaps primarily to manage our price exposure. Our positions in commodity derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.

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

Fair Value Hedges

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

As of March 31, 2012, we had the following outstanding commodity derivative instruments that were entered into to hedge crude oil and refined product inventories and commodity derivative instruments related to the physical purchase of crude oil and refined products at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).



		Notional Contract Volumes by Year of Maturity
Derivative Instrument		2012
Crude oil and refined products:
Futures – long		10,670
Futures – short		33,088
Physical contracts - long		22,418

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Cash Flow Hedges

Cash flow hedges are used to hedge price volatility in certain forecasted feedstock and refined product purchases, refined product sales, and natural gas purchases. The objective of our cash flow hedges is to lock in the price of forecasted feedstock, product or natural gas purchases or refined product sales at existing market prices that we deem favorable.

As of March 31, 2012, we had the following outstanding commodity derivative instruments that were entered into to hedge forecasted purchases or sales of crude oil and refined products. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).



		Notional Contract Volumes by Year of Maturity
Derivative Instrument		2012
Crude oil and refined products:
Swaps – long		5,961
Swaps – short		5,961
Futures – long		34,601
Futures – short		32,112
Physical contracts – short		2,489

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Economic Hedges

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

As of March 31, 2012, we had the following outstanding commodity derivative instruments that were entered into as economic hedges and commodity derivative instruments related to the physical purchase of corn at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as corn contracts that are presented in thousands of bushels).



	Notional Contract Volumes by Year of Maturity
Derivative Instrument	2012	2013
Crude oil and refined products:
Swaps – long	51,124	—
Swaps – short	48,424	—
Futures – long	55,939	—
Futures – short	56,511	—
Options – long	2	—
Corn:
Futures – long	14,670	50
Futures – short	40,330	2,180
Physical contracts – long	16,759	2,121

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Trading Derivatives

Our objective in entering into commodity derivative instruments for trading purposes is to take advantage of existing market conditions related to future results of operations and cash flows.

As of March 31, 2012, we had the following outstanding commodity derivative instruments that were entered into for trading purposes. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes represent thousands of barrels, except those identified as natural gas contracts that are presented in billions of British thermal units and corn contracts that are presented in thousands of bushels).



	Notional Contract Volumes by Year of Maturity
Derivative Instrument	2012	2013
Crude oil and refined products:
Swaps – long	14,799	13,070
Swaps – short	14,659	13,190
Futures – long	72,215	8,050
Futures – short	74,651	5,550
Options – long	2,615	—
Options – short	2,500	—
Natural gas:
Futures – short	650	—
Corn:
Swaps - long	8,795	—
Swaps - short	9,085	—
Futures – long	7,720	—
Futures – short	7,720	—

Compliance Program Price Risk

We are exposed to market risks related to the volatility in the price of financial instruments associated with various governmental and regulatory compliance programs that we must purchase in the open market to comply with these programs. These programs are described below.

Obligation to Blend Biofuels

We are obligated to blend biofuels into the products we produce in most of the countries in which we operate, and these countries set annual quotas for the percentage of biofuels that must be blended into the motor fuels consumed in these countries. As a producer of motor fuels from petroleum, we are obligated to blend biofuels into the products we produce at a rate that is at least equal to the applicable quota. To the degree we are unable to blend at the applicable rate in the U.S. and the U.K., we must purchase Renewable Identification Numbers (RINs) in the U.S. and Renewable Transport Fuel Obligation certificates (RTFCs) in the U.K., and as such, we are exposed to the volatility in the market price of these financial instruments. We have not entered into derivative instruments to manage this risk, but we purchase RINs and RTFCs when the price of

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these instruments is deemed favorable. For the three months ended March 31, 2012 and 2011, the cost of meeting our obligations under these compliance programs was $67 million and $56 million, respectively, and these amounts are reflected in cost of sales.

Maintaining Minimum Inventory Quantities

In the U.K., we are required to maintain a minimum quantity of crude oil and refined products as a reserve against shortages or interruptions in the supply of these products. To the degree we decide not to physically hold the minimum quantity of crude oil and refined products, we must purchase Compulsory Stock Obligation (CSO) tickets from other suppliers of refined products in the U.K. or other European Union (EU) member countries, and we make economic decisions as to the cost of maintaining certain quantities of crude oil and refined products versus the cost of purchasing CSO tickets. We have not entered into derivative instruments to manage the price volatility of CSO tickets. For the three months ended March 31, 2012, the cost of purchasing CSO tickets to help meet our obligations under this compliance program was $2 million, and this amount was reflected in cost of sales. We had no obligations under this compliance program prior to completing the Pembroke Acquisition in 2011.

Emission Allowances

Our Pembroke Refinery is subject to a maximum amount of carbon dioxide that it can emit each year under the EU Emissions Trading Scheme. Under this cap-and-trade program, we purchase emission allowances on the open market for the difference between the amount of carbon dioxide emitted and the maximum amount allowed under the program. Therefore, we are exposed to the volatility in the market price of these allowances. For the three months ended March 31, 2012, the cost of meeting our obligation under this compliance program was $1 million, and this amount is reflected in refining operating expenses. We had no obligations under this compliance program prior to completing the Pembroke Acquisition in 2011.

We enter into derivative instruments (futures) to reduce the impact of this risk on our results of operations and cash flows. Our positions in these derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors. As of March 31, 2012, we had purchased futures contracts – long for 55,000 metric tons of EU emission allowances that were entered into as economic hedges. As of March 31, 2012, the fair value of these futures contracts was immaterial and therefore not separately presented in the table below under “Fair Values of Derivative Instruments.” For the three months ended March 31, 2012, the loss recognized in income on these derivative instruments designated as economic hedges was also immaterial and therefore not separately presented in the table below under “Effect of Derivative Instruments on Income and Other Comprehensive Income.”

Interest Rate Risk

Our primary market risk exposure for changes in interest rates relates to our debt obligations. We manage our exposure to changing interest rates through the use of a combination of fixed-rate and floating-rate debt. In addition, at times we have used interest rate swap agreements to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt. We had no interest rate derivative instruments outstanding as of March 31, 2012 or December 31, 2011, or during the three months ended March 31, 2012 and 2011.

Foreign Currency Risk

We are exposed to exchange rate fluctuations on transactions entered into by our international operations

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

that are denominated in currencies other than the local (functional) currencies of those operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of March 31, 2012, we had commitments to purchase $565 million of U.S. dollars and C$65 million of Canadian dollars. The majority of these commitments matured on or before April 30, 2012.

Fair Values of Derivative Instruments

The following tables provide information about the fair values of our derivative instruments as of March 31, 2012 and December 31, 2011 (in millions) and the line items in the balance sheets in which the fair values are reflected. See Note 12 for additional information related to the fair values of our derivative instruments.

As indicated in Note 12, we net fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty under master netting arrangements. The tables below, however, are presented on a gross asset and gross liability basis, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts. In addition, in Note 12, we included cash collateral on deposit with or received from brokers in the fair value of the commodity derivatives; these cash amounts are not reflected in the tables below.



	Balance Sheet Location	March 31, 2012
	Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	161	$	188
Swaps	Receivables, net	89		83
Swaps	Accrued expenses	4		3
Total		$	254	$	274

Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	1,949	$	1,957
Swaps	Receivables, net	46		48
Swaps	Prepaid expenses and other	1		—
Swaps	Accrued expenses	22		31
Options	Receivables, net	1		—
Physical purchase contracts	Inventories	—		36
Foreign currency contracts	Receivables, net	1		—
Foreign currency contracts	Accrued expenses	—		3
Total		$	2,020	$	2,075
Total derivatives		$	2,274	$	2,349

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Balance Sheet Location	December 31, 2011
	Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	264	$	240
Swaps	Accrued expenses	36		46
Total		$	300	$	286

Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	1,636	$	1,624
Swaps	Prepaid expenses and other	4		2
Swaps	Accrued expenses	38		51
Options	Receivables, net	2		—
Options	Accrued expenses	—		2
Physical purchase contracts	Inventories	—		2
Foreign currency contracts	Accrued expenses	—		3
Total		$	1,680	$	1,684
Total derivatives		$	1,980	$	1,970

Market and Counterparty Risk

Our price risk management activities involve the receipt or payment of fixed price commitments into the future. These transactions give rise to market risk, which is the risk that future changes in market conditions may make an instrument less valuable. We closely monitor and manage our exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Market risks are monitored by a risk control group to ensure compliance with our stated risk management policy. Concentrations of customers in the refining industry may impact our overall exposure to counterparty risk because these customers may be similarly affected by changes in economic or other conditions. In addition, financial services companies are the counterparties in certain of our price risk management activities, and such financial services companies may be adversely affected by periods of uncertainty and illiquidity in the credit and capital markets.

As of March 31, 2012, we had net receivables related to derivative instruments of $1 million from counterparties in the refining industry and no amounts from counterparties in the financial services industry. As of December 31, 2011, we had net receivables related to derivative instruments of $2 million from counterparties in the refining industry and no amounts from counterparties in the financial services industry. These amounts represent the aggregate amount payable to us by companies in those industries, reduced by payables from us to those companies under master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party. We do not require any collateral or other security to support derivative instruments into which we enter. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments on Income and Other Comprehensive Income

The following tables provide information about the gain or loss recognized in income and other comprehensive income on our derivative instruments and the line items in the financial statements in which such gains and losses are reflected (in millions).



Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,
Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2012			2011
Commodity contracts:
Loss recognized in income on derivatives	Cost of sales	$	(267	)	$	(91	)
Gain recognized in income on hedged item	Cost of sales	228			86
Loss recognized in income on derivatives (ineffective portion)	Cost of sales	(39		)	(5		)

For fair value hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for three months ended March 31, 2012 and 2011. No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges for the three months ended March 31, 2012 and 2011.



Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,
Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2012			2011
Commodity contracts:
Gain recognized in OCI on derivatives (effective portion)		$	47		$	—
Gain reclassified from accumulated OCI into income (effective portion)	Cost of sales	48			—
Loss recognized in income on derivatives (ineffective portion)	Cost of sales	(5		)	—

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For cash flow hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three months ended March 31, 2012 and 2011. For the three months ended March 31, 2012, cash flow hedges primarily related to forward sales of gasoline and distillates, and associated forward purchases of crude oil, with $19 million of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive income. We estimate that $19 million of the deferred gains as of March 31, 2012 will be reclassified into cost of sales over the next nine months as a result of hedged transactions that are forecasted to occur. For the three months ended March 31, 2012 and 2011, there were no amounts reclassified from accumulated other comprehensive income into income as a result of the discontinuance of cash flow hedge accounting.



Derivatives Designated as Economic Hedges and Other Derivative Instruments	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,
	Location of Gain (Loss) Recognized in Income on Derivatives	2012			2011
Commodity contracts	Cost of sales	$	(151	)	$	(299	)
Foreign currency contracts	Cost of sales	(23		)	(14		)
Total		$	(174	)	$	(313	)

The loss of $299 million on commodity contracts for the three months ended March 31, 2011 includes a $542 million loss related to forward sales of refined product.



Trading Derivatives	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,
Trading Derivatives	Location of Gain (Loss) Recognized in Income on Derivatives	2012			2011
Commodity contracts	Cost of sales	$	(4	)	$	6

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Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

This Form 10-Q, including without limitation our discussion 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 those capital investments on our results of operations;


•	anticipated trends in the supply of and demand for crude oil and other feedstocks and refined products 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;


•	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;

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


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


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


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


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


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


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


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

•

legislative or regulatory action, including the introduction or enactment of legislation or rulemakings by governmental authorities, including tax and environmental regulations, such as those to be implemented under the California Global Warming Solutions Act (also known as AB 32) and the U.S. Environmental Protection Agency’s (EPA) 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 United States (U.S.) dollar; and


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

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

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

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OVERVIEW AND OUTLOOK

Overview

For the first quarter of 2012, we reported a net loss attributable to Valero stockholders from continuing operations of $432 million, or $0.78 per share, compared to net income attributable to Valero stockholders from continuing operations of $104 million, or $0.18 per share, for the first quarter of 2011.

The results for the first quarter of 2012, however, were significantly impacted by a $611 million asset impairment loss ($605 million after taxes, or $1.09 per share), primarily related to our Aruba Refinery, which is discussed below. In addition, the results for the first quarter of 2011 were significantly impacted by a $542 million loss ($352 million after taxes, or $0.62 per share) on commodity derivative contracts related to the forward sales of refined product. These contracts were closed and realized in the first quarter of 2011. Excluding these significant items, net income attributable to Valero stockholders from continuing operations was $173 million ($0.31 per share) for the first quarter of 2012 compared to $456 million ($0.80 per share) for the first quarter of 2011.

The decline in net income attributable to Valero stockholders from continuing operations in the first quarter of 2012 as compared to the first quarter of 2011 was primarily due to a decrease in operating income attributable to the refining business segment as outlined in the following table (in millions):



	Three Months Ended March 31,
	2012			2011			Change
Operating income (loss) by business segment:
Refining	$	(119	)	$	276		$	(395	)
Retail	40			66			(26		)
Ethanol	9			44			(35		)
Corporate	(174		)	(142		)	(32		)
Total	$	(244	)	$	244		$	(488	)

Excluding the impacts of the $611 million asset impairment loss in the first quarter of 2012 and the $542 million loss on commodity derivative contracts in the first quarter of 2011 described above, total company operating income for the first quarter of 2012 and the first quarter of 2011 would have been $367 million and $786 million, respectively, and our refining segment operating income would have been $492 million and $818 million, respectively, for the same periods.

Refining segment operating income declined primarily due to lower sour crude oil differentials (which is the difference between the price of sweet crude oil and the price of sour crude oil) and lower margins for other products such as petrochemical feedstocks and petroleum coke, partially offset by improved gasoline and distillate margins for most of our refining regions. In addition, we continued to benefit from 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 Louisiana Light Sweet (LLS) and Brent crude oils. 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 during the first quarter of 2012 and 2011. This discount was wider in the first quarter of 2012 compared to the first quarter of 2011, which contributed to the improved gasoline and distillate margins described above.

In March 2012, we decided to suspend the operations of the Aruba Refinery by the end of March. Our decision

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was based on the refinery’s inability to generate positive cash flows on a sustained basis subsequent to its restart in January 2011 and the sensitivity of its profitability to sour crude oil differentials, which narrowed significantly in the fourth quarter of 2011. On March 28, 2012, we received a non-binding indication of interest from an unrelated interested party to purchase the Aruba Refinery for $350 million, plus working capital as of the closing date, subject to completion of due diligence and further negotiations. We have accepted this offer, subject to the finalization of the purchase and sale agreement. Because of our decision to suspend the operations of the Aruba Refinery and the possibility that we may sell the refinery, we evaluated the refinery for potential impairment as of March 31, 2012 and recognized an asset impairment loss of $595 million, which is discussed in Note 3 of Notes to Condensed Consolidated Financial Statements.

Outlook

The benefit we experienced in our refining business throughout 2011 and the first quarter of 2012 from processing discounted WTI-type crude oils may decline as various crude oil pipeline and logistics projects are completed in coming months. These projects will allow sweet crude oils from the inland U.S. to be transported to the U.S. Gulf Coast region, which is expected to result in a narrowing of the price differential of WTI-priced crude oils relative to Brent-priced crude oil. As a result, the margins for refined products for refiners that process WTI-priced crude oils may decline. In addition, 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. Refineries in those regions have closed, such as the Aruba Refinery discussed above, and others may close in coming months. However, some of these refineries may continue to be operated for political and other reasons, which could have a negative impact on refined product margins. As a result of these matters, we expect energy markets and margins to be volatile in the near to mid-term.

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RESULTS OF OPERATIONS

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

Financial Highlights (a) (b)

(millions of dollars, except per share amounts)



	Three Months Ended March 31,
	2012			2011			Change
Operating revenues	$	35,167		$	26,308		$	8,859
Costs and expenses:
Cost of sales (c)	33,035			24,568			8,467
Operating expenses:
Refining	964			744			220
Retail	166			162			4
Ethanol	87			95			(8		)
General and administrative expenses	164			130			34
Depreciation and amortization expense:
Refining	337			316			21
Retail	27			28			(1		)
Ethanol	10			9			1
Corporate	10			12			(2		)
Asset impairment loss (d)	611			—			611
Total costs and expenses	35,411			26,064			9,347
Operating income (loss)	(244		)	244			(488		)
Other income, net	6			17			(11		)
Interest and debt expense, net of capitalized interest	(99		)	(117		)	18
Income (loss) from continuing operations before income tax expense	(337		)	144			(481		)
Income tax expense	95			40			55
Income (loss) from continuing operations	(432		)	104			(536		)
Income (loss) from discontinued operations, net of income taxes	—			(6		)	6
Net income (loss)	(432		)	98			(530		)
Less: Net loss attributable to noncontrolling interests	—			—			—
Net income (loss) attributable to Valero stockholders	$	(432	)	$	98		$	(530	)

Net income (loss) attributable to Valero stockholders:
Continuing operations	$	(432	)	$	104		$	(536	)
Discontinued operations	—			(6		)	6
Total	$	(432	)	$	98		$	(530	)

Earnings per common share – assuming dilution:
Continuing operations	$	(0.78	)	$	0.18		$	(0.96	)
Discontinued operations	—			(0.01		)	0.01
Total	$	(0.78	)	$	0.17		$	(0.95	)

________________

See note references on page 43.

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Operating Highlights

(millions of dollars, except per barrel amounts)



	Three Months Ended March 31,
	2012			2011		Change
Refining (a) (b):
Operating income (c)	$	(119	)	$	276	$	(395	)
Throughput margin per barrel (c)	$	7.71		$	9.91	$	(2.20	)
Operating costs per barrel:
Operating expenses	4.15			3.93		0.22
Depreciation and amortization expense	1.45			1.66		(0.21		)
Total operating costs per barrel (d)	5.60			5.59		0.01
Operating income per barrel (d)	$	2.11		$	4.32	$	(2.21	)

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude	451			372		79
Medium/light sour crude	555			372		183
Acidic sweet crude	73			72		1
Sweet crude	883			666		217
Residuals	169			249		(80		)
Other feedstocks	144			137		7
Total feedstocks	2,275			1,868		407
Blendstocks and other	280			238		42
Total throughput volumes	2,555			2,106		449

Yields (thousand barrels per day):
Gasolines and blendstocks	1,191			956		235
Distillates	911			695		216
Other products (f)	469			465		4
Total yields	2,571			2,116		455

_______________

See note references on page 43.

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Refining Operating Highlights by Region (g)

(millions of dollars, except per barrel amounts)



	Three Months Ended March 31,
	2012			2011			Change
U.S. Gulf Coast (a):
Operating income (c)	$	235		$	483		$	(248	)
Throughput volumes (thousand barrels per day)	1,476			1,299			177
Throughput margin per barrel (c) (e)	$	6.92		$	9.63		$	(2.71	)
Operating costs per barrel:
Operating expenses	$	3.67		$	3.86		$	(0.19	)
Depreciation and amortization expense	1.50			1.64			(0.14		)
Total operating costs per barrel (d)	5.17			5.50			(0.33		)
Operating income per barrel (d)	$	1.75		$	4.13		$	(2.38	)

U.S. Mid-Continent:
Operating income (c)	$	254		$	289		$	(35	)
Throughput volumes (thousand barrels per day)	398			403			(5		)
Throughput margin per barrel (c) (e)	$	13.80		$	13.04		$	0.76
Operating costs per barrel:
Operating expenses	5.31			3.65			1.66
Depreciation and amortization expense	1.50			1.44			0.06
Total operating costs per barrel	6.81			5.09			1.72
Operating income per barrel	$	6.99		$	7.95		$	(0.96	)

North Atlantic (b):
Operating income	$	61		$	56		$	5
Throughput volumes (thousand barrels per day)	461			209			252
Throughput margin per barrel (e)	$	5.64		$	7.02		$	(1.38	)
Operating costs per barrel:
Operating expenses	3.52			2.81			0.71
Depreciation and amortization expense	0.66			1.20			(0.54		)
Total operating costs per barrel	4.18			4.01			0.17
Operating income per barrel	$	1.46		$	3.01		$	(1.55	)

U.S. West Coast:
Operating loss (c)	$	(58	)	$	(10	)	$	(48	)
Throughput volumes (thousand barrels per day)	220			195			25
Throughput margin per barrel (c) (e)	$	6.32		$	8.33		$	(2.01	)
Operating costs per barrel:
Operating expenses	6.56			6.15			0.41
Depreciation and amortization expense	2.67			2.81			(0.14		)
Total operating costs per barrel	9.23			8.96			0.27
Operating loss per barrel	$	(2.91	)	$	(0.63	)	$	(2.28	)

Operating income for regions above	$	492		$	818		$	(326	)
Asset impairment loss (d)	(611		)	—			(611		)
Loss on derivative contracts related to the forward sales of refined product (c)	—			(542		)	542
Total refining operating income (loss)	$	(119	)	$	276		$	(395	)

_______________

See note references on page 43.

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Average Market Reference Prices and Differentials (h)

(dollars per barrel, except as noted)



	Three Months Ended March 31,
	2012			2011		Change
Feedstocks:
Brent crude oil	$	118.34		$	105.16	$	13.18
Brent less West Texas Intermediate (WTI) crude oil	15.46			11.22		4.24
Brent less Alaska North Slope (ANS) crude oil	0.65			3.92		(3.27		)
Brent less Louisiana Light Sweet (LLS) crude oil	(0.56		)	0.14		(0.70		)
Brent less Mars crude oil	3.66			3.73		(0.07		)
Brent less Maya crude oil	9.33			15.82		(6.49		)
LLS crude oil	118.90			105.02		13.88
LLS less Mars crude oil	4.22			3.59		0.63
LLS less Maya crude oil	9.89			15.68		(5.79		)
WTI crude oil	102.88			93.94		8.94

Natural gas (dollars per million British thermal units)	2.39			4.15		(1.76		)

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less Brent	7.12			3.68		3.44
Ultra-low-sulfur diesel less Brent	14.24			13.45		0.79
Propylene less Brent	(12.48		)	19.36		(31.84		)
Conventional 87 gasoline less LLS	6.56			3.82		2.74
Ultra-low-sulfur diesel less LLS	13.68			13.59		0.09
Propylene less LLS	(13.04		)	19.50		(32.54		)
U.S. Mid-Continent:
Conventional 87 gasoline less WTI	18.28			15.89		2.39
Ultra-low-sulfur diesel less WTI	27.75			25.10		2.65
North Atlantic:
Conventional 87 gasoline less Brent	7.73			4.20		3.53
Ultra-low-sulfur diesel less Brent	15.87			15.30		0.57
U.S. West Coast:
CARBOB 87 gasoline less ANS	14.24			15.36		(1.12		)
CARB diesel less ANS	18.28			20.70		(2.42		)
CARBOB 87 gasoline less WTI	29.05			22.66		6.39
CARB diesel less WTI	33.09			28.00		5.09
New York Harbor corn crush (dollars per gallon)	(0.05		)	0.08		(0.13		)

_______________

See note references on page 43.

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Operating Highlights (continued)

(millions of dollars, except per gallon amounts)



	Three Months Ended March 31,
	2012			2011			Change
Retail–U.S.:
Operating income	$	11		$	19		$	(8	)
Company-operated fuel sites (average)	997			993			4
Fuel volumes (gallons per day per site)	5,046			4,895			151
Fuel margin per gallon	$	0.050		$	0.076		$	(0.026	)
Merchandise sales	$	288		$	283		$	5
Merchandise margin (percentage of sales)	29.5		%	28.3		%	1.2		%
Margin on miscellaneous sales	$	24		$	22		$	2
Operating expenses	$	104		$	98		$	6
Depreciation and amortization expense	$	18		$	19		$	(1	)

Retail–Canada:
Operating income	$	29		$	47		$	(18	)
Fuel volumes (thousand gallons per day)	3,097			3,234			(137		)
Fuel margin per gallon	$	0.258		$	0.317		$	(0.059	)
Merchandise sales	$	58		$	57		$	1
Merchandise margin (percentage of sales)	29.3		%	29.7		%	(0.4		)%
Margin on miscellaneous sales	$	11		$	11		$	—
Operating expenses	$	62		$	64		$	(2	)
Depreciation and amortization expense	$	9		$	9		$	—

Ethanol:
Operating income	$	9		$	44		$	(35	)
Production (thousand gallons per day)	3,478			3,282			196
Gross margin per gallon of production (e)	$	0.34		$	0.50		$	(0.16	)
Operating costs per gallon of production:
Operating expenses	0.28			0.32			(0.04		)
Depreciation and amortization expense	0.03			0.03			—
Total operating costs per gallon of production	0.31			0.35			(0.04		)
Operating income per gallon of production	$	0.03		$	0.15		$	(0.12	)

_______________

See note references on page 43.

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The following notes relate to references on pages 38 through 42.


(a)	For the three months ended March 31,2012, 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


(b)	For the three months ended March 31, 2012, 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 marketing and logistics business, from the date of its acquisition on August 1, 2011.

(c)

Cost of sales for the three months ended March 31, 2011 includes a loss of $542 million ($352 million after taxes) on commodity derivative contracts related to the forward sales of refined product. These contracts were closed and realized during the first quarter of 2011. The loss is reflected in refining segment operating income for the three months ended March 31, 2011, but throughput margin per barrel for the refining segment has been restated for the amount previously presented to exclude this $542 million loss ($2.86 per barrel). In addition, operating income (loss) and throughput margin per barrel for the U.S. Gulf Coast, U.S. Mid-Continent, and U.S. West Coast regions for the three months ended March 31, 2011 have been restated from the amounts previously presented to exclude the portion of this loss that had been allocated to them of $372 million ($3.18 per barrel); $122 million ($3.36 per barrel), and $48 million ($2.71 per barrel), respectively.

(d)

In March 2012, we concluded our evaluation of strategic alternatives for our refinery in Aruba (Aruba Refinery) and announced that we would temporarily suspend the refinery’s operations by the end of March. Because of this decision, we analyzed the Aruba Refinery for potential impairment and concluded that the refinery’s net book value (carrying amount) of $945 million was not recoverable through the future operations and disposition of the refinery. We determined that the fair value of the Aruba Refinery was $350 million; therefore, we recognized an asset impairment loss of $595 million. In addition, we recognized an asset impairment loss of $16 million related to equipment associated with a permanently cancelled capital project at another refinery. The total asset impairment loss of $611 million is reflected in refining segment operating income for the three months ended March 31, 2012, but it is excluded from operating costs per barrel and operating income per barrel for the refining segment and Gulf Coast region.


(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 Pembroke and Quebec City Refineries; and the U.S.West Coast region includes the Benicia and Wilmington Refineries.

(h)

Average market reference prices for Brent crude oil, along with price differentials between the price of Brent 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. We previously provided feedstock and product differentials 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 Brent and LLS, 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. We utilize Brent crude oil for price differentials because we believe it represents sweet crude oil prices for marginal refineries in the Atlantic Basin, and thus sets refined-product prices.

General

Operating revenues increased 34 percent (or $8.9 billion) for the first quarter of 2012 compared to the first quarter of 2011 primarily as a result of higher refined product prices and higher throughput volumes between the two periods related to our refining segment operations. The higher throughput volumes resulted primarily from the incremental throughput of 124,000 barrels per day from the Meraux Refinery, which was acquired on October 1, 2011, and incremental throughput of 246,000 barrels per day from the Pembroke Refinery, which was acquired on August 1, 2011. Operating income decreased $488 million and income from continuing operations before taxes decreased $481 million for the first quarter of 2012 compared to amounts reported for the first quarter of 2011 primarily due to a $395 million decrease in refining segment operating income discussed below.

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Refining

Refining segment operating income decreased $395 million from operating income of $276 million for the first quarter of 2011 to an operating loss of $119 million for the first quarter of 2012. This decrease was impacted by the $542 million loss on derivative contracts in the first quarter of 2011 and the $611 million asset impairment loss in the first quarter of 2012. (See Note 3 of Condensed Notes to Consolidated Financial Statements for further discussion of this asset impairment loss). Excluding these losses, refining segment operating income decreased $326 million from $818 million in the first quarter of 2011 to $492 million in the first quarter of 2012. The $326 million decrease in operating income was due primarily to an $85 million decrease in refining margin and a $220 million increase in operating expenses.

The $85 million decrease in refining margin was primarily due to a 22 percent decrease in throughput margin per barrel (a $2.20 per barrel decrease between the comparable periods), and this decrease was largely driven by narrower sour crude oil differentials, partially offset by an increase in gasoline and distillate margins in most of our refining regions, as further explained below.

•

For the first quarter of 2012, our refining segment was unfavorably impacted by the decrease in sour crude oil differentials as compared to the first quarter of 2011. For example, Maya crude oil, which is a type of sour crude oil, sold at a discount of $9.33 per barrel to Brent crude oil, which is a type of sweet crude oil, during the first quarter of 2012. This compares to a discount of $15.82 per barrel during the first quarter of 2011, representing an unfavorable decrease of $6.49 per barrel. We estimate that the decrease in the discounts for all types of sour crude oil that we process had a negative impact to our refining margin of approximately $490 million, quarter versus quarter.

•

The WTI-based benchmark reference margin for U.S. Mid-Continent conventional 87 gasoline was $18.28 per barrel for the first quarter of 2012, compared to $15.89 per barrel for the first quarter of 2011, representing a favorable increase of $2.39 per barrel. In addition, the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low sulfur diesel (a type of distillate) was $27.75 per barrel for the first quarter of 2012, compared to $25.10 per barrel for the first quarter of 2011, representing a favorable increase of $2.65 per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $50 million and $30 million, respectively, quarter versus quarter. The increases in the gasoline and distillate benchmark reference margins in the U.S. Mid-Continent region are primarily 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 has resulted in WTI-type crude oil currently being priced at a significant discount to LLS and Brent crude oils.

•

The Brent-based benchmark reference margin for U.S. Gulf Coast conventional 87 gasoline was $7.12 per barrel for the first quarter of 2012, compared to $3.68 per barrel for the first quarter of 2011, representing a favorable increase of $3.44 per barrel. In addition, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low sulfur diesel was $14.24 per barrel for the first quarter of 2012, compared to $13.45 per barrel for the first quarter of 2011, representing a favorable increase of $0.79 per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $200 million and $40 million, respectively, quarter versus quarter. The increases in the gasoline and distillate benchmark reference margins are supported by increased exports of gasoline and distillate as well as an increase in demand for distillates.

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The increase of $220 million in refining operating expenses discussed above was primarily due to $93 million in operating expenses incurred by the Pembroke Refinery, which was acquired on August 1, 2011, and $37 million in operating expenses incurred by the Meraux Refinery, which was acquired on October 1, 2011. The remaining increase in refining operating expenses of $90 million was primarily due to a $48 million increase in maintenance expenses and a $36 million increase in regulatory and insurance costs.

Retail

Retail segment operating income was $40 million for the first quarter of 2012 compared to $66 million for the first quarter of 2011. This 39 percent (or $26 million) decrease was due primarily to decreases in the fuel margins generated by both our Canadian and U.S. retail operations of $18 million and $10 million, respectively.

Ethanol

Ethanol segment operating income was $9 million for the first quarter of 2012 compared to $44 million for the first quarter of 2011. The $35 million decrease in operating income was primarily due to a $42 million decrease in gross margin, partially offset by an $8 million decrease in operating expenses.

The decrease in gross margin was due to a 32 percent decrease in the gross margin per gallon of ethanol production (a $0.16 per gallon decrease between the comparable periods) primarily due to lower ethanol prices between the first quarter of 2011 and the first quarter of 2012. The ethanol prices in 2012 were pressured by a surplus of ethanol supply in 2012 stemming from higher production in 2011, combined with reduced demand for ethanol in 2012 due to the decline in gasoline demand. The impact of lower ethanol prices on gross margin was partially offset by an increase in ethanol production (a 196,000 gallon per day increase between the comparable periods), which resulted from higher utilization rates and increased yield from the corn feedstock that we processed during the first quarter of 2012.

The reduction in operating expenses was due primarily to a $14 million decrease in energy costs due to lower natural gas prices partially offset by an increase in chemical expenses of $3 million compared to the first quarter of 2011.

Corporate Expenses and Other

General and administrative expenses increased $34 million from the first quarter of 2011 to the first quarter of 2012 primarily due to $19 million in administrative costs related to our European operations and a $12 million increase in employee-related expenses.

“Interest and debt expense, net of capitalized interest” for the first quarter of 2012 decreased $18 million from the first quarter of 2011. This decrease is primarily due to a $25 million increase in capitalized interest due to a corresponding increase in capital expenditures between the quarters.

Income tax expense increased $55 million from the first quarter of 2011 to the first quarter of 2012 even though we reported a loss from continuing operations before income tax expense, which was due to the asset impairment loss of $595 million related to the Aruba Refinery. We did not record a tax benefit related to this loss because we do not believe that we will realize a tax benefit.

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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Three Months Ended March 31, 2012 and 2011

Net cash provided by operating activities for the first three months of 2012 was $1.7 billion compared to $2.1 billion for the first three months of 2011. The decrease in cash generated from operating activities was primarily due to a $540 million unfavorable effect from changes in working capital between the periods. Changes in cash provided by or used for working capital during the first three months of 2012 and 2011 are shown in Note 11 of Condensed Notes to Consolidated Financial Statements.

The net cash provided by operating activities during the first three months of 2012 was used mainly to:


•	fund $884 million of capital expenditures and deferred turnaround and catalyst costs;


•	make a repayment under our accounts receivable sales facility of $150 million;


•	pay common stock dividends of $83 million; and


•	increase available cash on hand by $535 million.

The net cash provided by operating activities during the first three months of 2011 was used mainly to:


•	fund $737 million of capital expenditures and deferred turnaround and catalyst costs;


•	make a scheduled long-term note repayment of $210 million and acquire the Gulf Opportunity Zone Revenue Bonds Series 2010 for $300 million;


•	pay common stock dividends of $28 million; and


•	increase available cash on hand by $799 million.

Capital Investments

Our operations, especially those of our refining segment, are highly capital intensive. Each of our refineries comprises a large base of property assets, consisting of a series of interconnected, highly integrated and interdependent crude oil processing facilities and supporting logistical infrastructure (Units), and these Units are continuously improved. Improvements consist of the addition of new Units and betterments of existing Units, and the cost of these improvements is significant. We have historically acquired our refineries at amounts significantly below their replacement costs, whereas our improvements are made at full replacement value. As such, the costs for improving our refinery assets increase over time and are significant in relation to the amounts we paid to acquire our refineries. We plan for these improvements by developing a multi-year capital program that is updated and revised based on changing internal and external factors.

We make improvements to our refineries in order to maintain and enhance their operating reliability, to meet environmental obligations with respect to reducing emissions and removing prohibited elements from the products we produce, or to enhance their profitability. Reliability and environmental improvements generally do not increase the throughput capacities of our refineries. Improvements that enhance refinery profitability may increase throughput capacity, but many of these improvements allow our refineries to process higher volumes of sour crude oil, which lowers our feedstock costs, and enables us to refine crude oil into products with higher market values. Therefore, many of our improvements do not increase throughput capacity significantly.

During the three months ended March 31, 2012, we expended $726 million for capital expenditures and $158 million for deferred turnaround and catalyst costs. Capital expenditures for the three months ended March 31, 2012 included $22 million of costs related to environmental projects.

For 2012, we expect to incur approximately $3.0 billion for capital investments (approximately $135 million of which is for environmental projects) and $510 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes expenditures related to strategic business acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.

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Contractual Obligations

As of March 31, 2012, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities.

During the three months ended March 31, 2012, we had no material changes outside the ordinary course of our business with respect to our debt, capital lease obligations, operating leases, purchase obligations, or other long-term liabilities.

In April 2012, we made scheduled debt repayments of $4 million related to our Series 1997A 5.45% industrial revenue bonds and $750 million related to our 6.875% notes.

We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables. This facility matures in June 2012. During the three months ended March 31, 2012, we repaid $150 million under this facility. As of March 31, 2012, the amount of eligible receivables sold was $100 million. In late April 2012, we sold $850 million of eligible receivables to the third-party entities and financial institutions under this facility, and we repaid $500 million on May 4, 2012.

Our agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt to below investment grade ratings by Moody’s Investors Service, Standard & Poor’s Ratings Services, and Fitch Ratings, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. As of March 31, 2012, all of our ratings on our senior unsecured debt are at or above investment grade level as follows:



Rating Agency		Rating
Standard & Poor’s Ratings Services		BBB (stable outlook)
Moody’s Investors Service		Baa2 (stable outlook)
Fitch Ratings		BBB (stable outlook)

We cannot provide assurance that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell, or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction below investment grade or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing and the cost of such financings.

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Other Commercial Commitments

As of March 31, 2012, our committed lines of credit were as follows (in millions):



	Borrowing Capacity	Expiration	Outstanding Letters of Credit
Letter of credit facilities	$500	June 2012	$500
Revolving credit facility	$3,000	December 2016	$153
Canadian revolving credit facility	C$115	December 2012	C$20

As of March 31, 2012, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of March 31, 2012 expire during 2012 and 2013.

Other Matters Impacting Liquidity and Capital Resources

Pension Plan Funded Status

We have minimum required contributions of $2 million during 2012 to our pension plans that have minimum funding requirements; however, we plan to contribute approximately $100 million to our pension plans during 2012. We made no significant contributions to our pension plans in the first three months of 2012.

Stock Purchase Programs

As of March 31, 2012, we have approvals under common stock purchase programs to purchase approximately $3.5 billion of our common stock.

Environmental Matters

Our operations are subject to extensive environmental regulations by governmental authorities relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our operating facilities could require material additional expenditures to comply with environmental laws and regulations. See Note 6 of Condensed Notes to Consolidated Financial Statements for a further discussion of our environmental matters.

Tax Matters

As of March 31, 2012, the Internal Revenue Service (IRS) has ongoing tax audits related to our U.S. federal tax returns from 2002 through 2009, as discussed in Note 6 of Condensed Notes to Consolidated Financial Statements. We have received Revenue Agent Reports on our tax years for 2002 through 2007 and we are vigorously contesting the tax positions and assertions from the IRS. Although we believe our tax liabilities are fairly stated and properly reflected in our financial statements, should the IRS eventually prevail, it could

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result in a material amount of our deferred tax liabilities being reclassified to current liabilities which could have a material adverse effect on our liquidity.

Cash Held by Our International Subsidiaries

We operate in countries outside the U.S. through subsidiaries incorporated in these countries, and the earnings of these subsidiaries are taxed by the countries in which they are incorporated. We intend to reinvest these earnings indefinitely in our international operations even though we are not restricted from repatriating such earnings to the U.S. in the form of cash dividends. Should we decide to repatriate such earnings, we would incur and pay taxes on the amounts repatriated. In addition, such repatriation could cause us to record deferred tax expense that could significantly impact our results of operations. We believe, however, that a substantial portion of our international cash can be returned to the U.S. without significant tax consequences through means other than a repatriation of earnings. As of March 31, 2012, $773 million of our cash and temporary cash investments was held by our international subsidiaries.

Financial Regulatory Reform

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Wall Street Reform Act). Key provisions of the Wall Street Reform Act create new statutory requirements that require most derivative instruments to be traded on exchanges and routed through clearinghouses, as well as impose new recordkeeping and reporting responsibilities on market participants. Final rules implementing the Wall Street Reform Act are expected to become effective mid-2012; therefore, the impact to our operations is yet unknown. However, the implementation could result in higher margin environments, higher clearing costs, and more reporting requirements with respect to our derivative activities.

Concentration of Customers

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

Sources of Liquidity

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

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CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with U. S. generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported in our financial statements and accompanying notes. Actual results could differ from those estimates. Our critical accounting policies are disclosed in our annual report on Form 10-K for the year ended December 31, 2011.


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

COMMODITY PRICE RISK


•	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 those forecasted transactions at existing market prices that we deem favorable.

We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations. We use swaps primarily to manage our price exposure. We also enter into certain commodity derivative instruments for trading purposes to take advantage of existing market conditions related to future results of operations and cash flows.

Our positions in commodity derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.

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



	Derivative Instruments Held For
	Non-Trading Purposes			Trading Purposes
March 31, 2012:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	$	(255	)	$	(3	)
10% decrease in underlying commodity prices	255			7

December 31, 2011:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	(156		)	1
10% decrease in underlying commodity prices	156			2

See Note 13 of Condensed Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of March 31, 2012.

COMPLIANCE PROGRAM PRICE RISK

We are exposed to market risks related to the volatility in the price of financial instruments associated with

various governmental and regulatory compliance programs that we must purchase in the open market to comply with these programs. To reduce the impact of this risk on our results of operations and cash flows, we may enter into derivative instruments, such as futures. As of March 31, 2012, there was no significant gain or loss in the fair value of derivative instruments that would result from a 10 percent increase or decrease in the underlying price of the futures contracts. See Note 13 of Condensed Notes to Consolidated Financial Statements for a discussion about these compliance programs and notional volumes associated with these derivative contracts as of March 31, 2012.

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INTEREST RATE RISK

The following table provides information about our debt instruments, excluding capital lease obligations (dollars in millions), the fair values of which are sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented. We had no interest rate derivative instruments outstanding as of March 31, 2012 or December 31, 2011.



	March 31, 2012
	Expected Maturity Dates
	2012			2013			2014			2015			2016			There- after			Total			Fair Value
Debt:
Fixed rate	$	862		$	480		$	200		$	475		$	—		$	5,474		$	7,491		$	8,553
Average interest rate	6.7		%	5.5		%	4.8		%	5.2		%	—		%	7.3		%	6.9		%
Floating rate	$	100		$	—		$	—		$	—		$	—		$	—		$	100		$	100
Average interest rate	0.6		%	—		%	—		%	—		%	—		%	—		%	0.6		%

	December 31, 2011
	Expected Maturity Dates
	2012			2013			2014			2015			2016			There- after			Total			Fair Value
Debt:
Fixed rate	$	754		$	484		$	200		$	475		$	—		$	5,578		$	7,491		$	9,048
Average interest rate	6.9		%	5.5		%	4.8		%	5.2		%	—		%	7.3		%	6.9		%
Floating rate	$	250		$	—		$	—		$	—		$	—		$	—		$	250		$	250
Average interest rate	0.6		%	—		%	—		%	—		%	—		%	—		%	0.6		%

FOREIGN CURRENCY RISK

As of March 31, 2012, we had commitments to purchase $565 million of U.S. dollars and C$65 million of Canadian dollars. Our market risk was minimal on these contracts, as the majority of which matured on or before April 30, 2012, resulting in a loss of approximately $3 million in the second quarter of 2012.

Item 4. Controls and Procedures


(a)	Evaluation of disclosure controls and procedures.

Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of March 31, 2012.


(b)	Changes in internal control over financial reporting.

There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION


Item 1.	Legal Proceedings

The information below describes new proceedings or material developments in proceedings that we previously reported in our annual report on Form 10-K for the year ended December 31, 2011.

Litigation

We hereby incorporate by reference into this Item our disclosures made in Part I, Item 1 of this Report included in Note 6 of Condensed 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 (Port Arthur Refinery). In our annual report on Form 10-K for the year ended December 31, 2011, we disclosed that our Port Arthur Refinery expected the EPA to assess penalties for a flaring event that occurred at the refinery in 2011. Potential stipulated penalties payable to the EPA under the consent decree for this event are $4.7 million. In March 2012, the Texas Commission on Environmental Quality (TCEQ) also issued a notice of enforcement (NOE) for this and another flaring event that occurred at the refinery in 2011. The TCEQ has not stated a penalty amount in the NOE, although we reasonably believe the amount will be in excess of $100,000.

EPA (Three Rivers Refinery). In our annual report on Form 10-K for the year ended December 31, 2011, we disclosed that our Three Rivers Refinery expected the EPA to assess penalties for a flaring event that occurred at the refinery in 2011. Potential stipulated penalties payable to the EPA under the consent decree for this event are $522,500. In April 2012, the TCEQ also issued an NOE for this event. The TCEQ has not stated a penalty amount in the NOE, although we reasonably believe the amount will be in excess of $100,000.

TCEQ (Port Arthur Refinery). In March 2012, our Port Arthur Refinery received a proposed agreed order from the TCEQ that assesses a penalty of $180,911 for various alleged air emission and reporting violations. We are working with the TCEQ to settle this matter.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2011.

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Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds


(a)	Unregistered Sales of Equity Securities. Not applicable.


(b)	Use of Proceeds. Not applicable.


(c)	Issuer Purchases of Equity Securities. The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.



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)
January 2012	1,805,513	$	20.91	1,805,513	—	$3.46 billion
February 2012	2,232,661	$	25.11	2,232,661	—	$3.46 billion
March 2012	489,527	$	24.42	489,527	—	$3.46 billion
Total	4,527,701	$	23.36	4,527,701	—	$3.46 billion

(a)

The shares reported in this column represent purchases settled in the first quarter of 2011 relating to (a) our purchases of shares in open-market transactions to meet our obligations under employee stock compensation plans, and (b) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our incentive compensation plans.

(b)

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

Item 6. Exhibits



Exhibit No.	Description

12.01	Statements of Computations of Ratios of Earnings to Fixed Charges.

31.01	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer.

31.02	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer.

32.01	Section 1350 Certifications (as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).

101	Interactive Data Files

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.




	VALERO ENERGY CORPORATION (Registrant)
By:	/s/ Michael S. Ciskowski
	Michael S. Ciskowski
	Executive Vice President and
		Chief Financial Officer
	(Duly Authorized Officer and Principal
	Financial and Accounting Officer)

Date: May 8, 2012