10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2009

OR

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

For the transition period from                                          to                                           

Commission file number 1-13175

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization) 74-1828067
(I.R.S. Employer
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 þ 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 þ 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 þ 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 þ

The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of July 31, 2009 was 562,761,441.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

INDEX

	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008		3
Consolidated Statements of Income for the Three and Six Months Ended June 30, 2009 and 2008		4
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008		5
Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2009 and 2008		6
Condensed Notes to Consolidated Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		42
Item 3. Quantitative and Qualitative Disclosures About Market Risk		65
Item 4. Controls and Procedures		70
PART II – OTHER INFORMATION
Item 1. Legal Proceedings		71
Item 1A. Risk Factors		72
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		72
Item 4. Submission of Matters to a Vote of Security Holders		73
Item 6. Exhibits		75
SIGNATURE		76
EX-12.01
EX-31.01
EX-31.02
EX-32.01
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

2

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)

	June 30,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	1,623		$	940
Restricted cash		141			131
Receivables, net		4,217			2,897
Inventories		4,561			4,637
Income taxes receivable		27			197
Deferred income taxes		132			98
Prepaid expenses and other		472			550
Total current assets		11,173			9,450
Property, plant and equipment, at cost		29,688			28,103
Accumulated depreciation		(5,404	)		(4,890	)
Property, plant and equipment, net		24,284			23,213
Intangible assets, net		221			224
Deferred charges and other assets, net		1,543			1,530
Total assets	$	37,221		$	34,417
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	137		$	312
Accounts payable		5,840			4,446
Accrued expenses		350			374
Taxes other than income taxes		557			592
Income taxes payable		36			–
Deferred income taxes		404			485
Total current liabilities		7,324			6,209
Debt and capital lease obligations, less current portion		7,231			6,264
Deferred income taxes		4,105			4,163
Other long-term liabilities		2,154			2,161
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 673,501,593 and 627,501,593 shares issued		7			6
Additional paid-in capital		7,987			7,190
Treasury stock, at cost; 110,853,320 and 111,290,436 common shares		(6,856	)		(6,884	)
Retained earnings		15,384			15,484
Accumulated other comprehensive loss		(115	)		(176	)
Total stockholders’ equity		16,407			15,620
Total liabilities and stockholders’ equity	$	37,221		$	34,417

See Condensed Notes to Consolidated Financial Statements.

3

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, Except per Share Amounts)
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Operating revenues (1)	$	17,925		$	36,640		$	31,749		$	64,585
Costs and expenses:
Cost of sales		16,543			33,673			28,171			59,342
Operating expenses		1,015			1,133			2,012			2,247
Retail selling expenses		171			190			340			378
General and administrative expenses		124			117			269			252
Depreciation and amortization expense		389			369			767			736
Total costs and expenses		18,242			35,482			31,559			62,955
Operating income (loss)		(317	)		1,158			190			1,630
Other income (expense), net		(24	)		15			(25	)		35
Interest and debt expense:
Incurred		(118	)		(107	)		(237	)		(223	)
Capitalized		36			24			76			43
Income (loss) before income tax expense (benefit)		(423	)		1,090			4			1,485
Income tax expense (benefit)		(169	)		356			(51	)		490
Net income (loss)	$	(254	)	$	734		$	55		$	995
Earnings (loss) per common share	$	(0.48	)	$	1.39		$	0.11		$	1.88
Weighted-average common shares outstanding (in millions)		525			526			520			529
Earnings (loss) per common share – assuming dilution	$	(0.48	)	$	1.37		$	0.11		$	1.85
Weighted-average common shares outstanding – assuming dilution (in millions)		525			534			525			537
Dividends per common share	$	0.15		$	0.15		$	0.30		$	0.27
Supplemental information:
(1) Includes excise taxes on sales by our U.S. retail system	$	229		$	204		$	433		$	398

See Condensed Notes to Consolidated Financial Statements.

4

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)

	Six Months Ended June 30,
	2009			2008
Cash flows from operating activities:
Net income	$	55		$	995
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		767			736
Stock-based compensation expense		23			24
Deferred income tax benefit		(125	)		(93	)
Changes in current assets and current liabilities		557			189
Changes in deferred charges and credits and other operating activities, net		130			(49	)
Net cash provided by operating activities		1,407			1,802
Cash flows from investing activities:
Capital expenditures		(1,351	)		(1,178	)
Deferred turnaround and catalyst costs		(249	)		(203	)
Purchase of certain VeraSun Energy Corporation facilities		(556	)		–
Return of investment in Cameron Highway Oil Pipeline Company		8			12
Advance proceeds related to sale of assets		–			17
Contingent payment in connection with acquisition		–			(25	)
Minor acquisitions		(29	)		(57	)
Other investing activities, net		3			14
Net cash used in investing activities		(2,174	)		(1,420	)
Cash flows from financing activities:
Proceeds from the sale of common stock, net of issuance costs		799			–
Non-bank debt:
Borrowings		998			–
Repayments		(209	)		(374	)
Bank credit agreements:
Borrowings		–			296
Repayments		–			(296	)
Accounts receivable sales program:
Proceeds from sale of receivables		500			–
Repayments		(500	)		–
Purchase of common stock for treasury		–			(700	)
Issuance of common stock in connection with employee benefit plans		4			11
Benefit from tax deduction in excess of recognized stock-based compensation cost		1			13
Common stock dividends		(155	)		(143	)
Debt issuance costs		(8	)		–
Other financing activities		(2	)		(2	)
Net cash provided by (used in) financing activities		1,428			(1,195	)
Effect of foreign exchange rate changes on cash		22			(7	)
Net increase (decrease) in cash and temporary cash investments		683			(820	)
Cash and temporary cash investments at beginning of period		940			2,464
Cash and temporary cash investments at end of period	$	1,623		$	1,644

See Condensed Notes to Consolidated Financial Statements.

5

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of Dollars)
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Net income (loss)	$	(254	)	$	734		$	55		$	995
Other comprehensive income (loss):
Foreign currency translation adjustment		191			15			110			(62	)
Pension and other postretirement benefits net (gain) loss reclassified into income, net of income tax expense of $-, $1, $-, and $1		–			(1	)		–			(1	)
Net gain (loss) on derivative instruments designated and qualifying as cash flow hedges:
Net gain (loss) arising during the period, net of income tax (expense) benefit of $(2), $27, $(34), and $54		3			(51	)		63			(100	)
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $39, $(17), $60, and $(9)		(72	)		32			(112	)		17
Net loss on cash flow hedges		(69	)		(19	)		(49	)		(83	)
Other comprehensive income (loss)		122			(5	)		61			(146	)
Comprehensive income (loss)	$	(132	)	$	729		$	116		$	849

See Condensed Notes to Consolidated Financial Statements.

6

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION, PRINCIPLES OF CONSOLIDATION, AND SIGNIFICANT ACCOUNTING POLICIES

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

These unaudited consolidated financial statements have been prepared in accordance with United States 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 GAAP for complete consolidated 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 and six months ended June 30, 2009 and 2008 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited consolidated financial statements. Operating results for the three and six months ended June 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009.

The consolidated balance sheet as of December 31, 2008 has been derived from the audited financial statements as of that date. For further information, refer to the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2008.

We have evaluated subsequent events that occurred after June 30, 2009 through the filing of this Form 10-Q on August 7, 2009. Any material subsequent events that occurred during this time have been properly recognized or disclosed in our financial statements.

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

Reclassifications
Certain amounts previously reported for the three and six months ended June 30, 2008 have been reclassified to conform to the 2009 presentation.

2. ACCOUNTING PRONOUNCEMENTS

FSP No. FAS 157-2
In February 2008, the Financial Accounting Standards Board (FASB) issued Staff Position No. FAS 157-2 (FSP No. 157-2), which delayed the effective date of Statement No. 157, “Fair Value Measurements,” for nonfinancial assets and nonfinancial liabilities, except for items that are recognized

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. The exceptions apply to the following: nonfinancial assets and nonfinancial liabilities measured at fair value in a business combination; impaired property, plant and equipment; goodwill; and the initial recognition of the fair value of asset retirement obligations and restructuring costs. The implementation of Statement No. 157 for these assets and liabilities effective January 1, 2009 did not affect our financial position or results of operations but did result in additional disclosures, which are provided in Note 9.

FASB Statement No. 141 (revised 2007)
In December 2007, the FASB issued Statement No. 141 (revised 2007), “Business Combinations” (Statement No. 141(R)). This statement improves the financial reporting of business combinations and clarifies the accounting for these transactions. The provisions of Statement No. 141(R) are to be applied prospectively to business combinations with acquisition dates on or after the beginning of an entity’s fiscal year that begins on or after December 15, 2008, with early adoption prohibited. Due to the adoption of Statement No. 141(R) effective January 1, 2009, the provisions of this statement were applied to the acquisition of certain ethanol plants from VeraSun Energy Corporation (VeraSun) in the second quarter of 2009, which is discussed in Note 3.

FASB Statement No. 160
In December 2007, the FASB issued Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.” Statement No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. This statement provides guidance for the accounting and reporting of noncontrolling interests, changes in controlling interests, and the deconsolidation of subsidiaries. In addition, Statement No. 160 amends FASB Statement No. 128, “Earnings per Share,” to specify the computation, presentation, and disclosure requirements for earnings per share if an entity has one or more noncontrolling interests. The adoption of Statement No. 160 effective January 1, 2009 has not affected our financial position or results of operations.

FASB Statement No. 161
In March 2008, the FASB issued Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” Statement No. 161 establishes, among other things, the disclosure requirements for derivative instruments and for hedging activities. This statement requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about contingent features related to credit risk in derivative agreements. Statement No. 161 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after November 15, 2008. The adoption of Statement No. 161 effective January 1, 2009 did not affect our financial position or results of operations but did result in additional disclosures, which are provided in Note 10.

FSP No. EITF 03-6-1
In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP No. EITF 03-6-1). FSP No. EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method described in Statement No. 128. FSP No. EITF 03-6-1 is effective for fiscal years, and interim periods within those fiscal years, beginning

8

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

after December 15, 2008; early adoption is not permitted. Shares of restricted stock granted under certain of our stock-based compensation plans represent participating securities covered by FSP No. EITF 03-6-1. The adoption of FSP No. EITF 03-6-1 effective January 1, 2009 did not have any effect on the calculation of basic earnings per common share for the three months ended June 30, 2009 and the six months ended June 30, 2009 and 2008, but did reduce basic earnings per common share from the $1.40 amount originally reported for the three months ended June 30, 2008 to $1.39. The calculation is provided in Note 7.

EITF Issue No. 08-6
In November 2008, the FASB ratified its consensus on EITF Issue No. 08-6, “Equity Method Investment Accounting Considerations” (EITF No. 08-6). EITF No. 08-6 applies to all investments accounted for under the equity method and provides guidance regarding (i) initial measurement of an equity investment, (ii) recognition of an other-than-temporary impairment of an equity method investment, including any impairment charge taken by the investee, and (iii) accounting for a change in ownership level or degree of influence on an investee. The consensus is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. EITF No. 08-6 is to be applied prospectively and earlier application is not permitted. Due to its application to future equity method investments, the adoption of EITF No. 08-6 effective January 1, 2009 has not had any immediate effect on our financial position or results of operations.

FSP No. FAS 132(R)-1
In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP No. FAS 132(R)-1). FSP No. FAS 132(R)-1 amends FASB Statement No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The additional requirements of FSP No. FAS 132(R)-1 are designed to enhance disclosures regarding (i) investment policies and strategies, (ii) categories of plan assets, (iii) fair value measurements of plan assets, and (iv) significant concentrations of risk. FSP No. FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009, with earlier application permitted. Since FSP No. FAS 132(R)-1 only affects disclosure requirements, the adoption of FSP No. FAS 132(R)-1 will not affect our financial position or results of operations.

FSP No. FAS 141(R)-1
In April 2009, the FASB issued Staff Position No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (FSP No. FAS 141(R)-1). FSP No. FAS 141(R)-1 amends and clarifies FASB Statement No. 141(R) to address application issues raised related to (i) initial recognition and measurement, (ii) subsequent measurement and accounting, and (iii) disclosure of assets and liabilities arising from contingencies in a business combination. The provisions of FSP No. FAS 141(R)-1 are to be applied to contingent assets or contingent liabilities acquired in business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after December 15, 2008. The adoption of FSP No. FAS 141(R)-1 effective January 1, 2009 has not had a material effect on our financial position or results of operations.

FSP No. FAS 107-1 and APB 28-1, FSP No. FAS 157-4, and FSP No. FAS 115-2 and FAS 124-2
In April 2009, the FASB issued Staff Position No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP No. FAS 107-1 and APB 28-1). FSP No. FAS 107-1 and

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

APB 28-1 amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments,” to require a publicly traded company to include disclosures about the fair value of its financial instruments for interim reporting periods as well as in annual financial statements. FSP No. FAS 107-1 and APB 28-1 is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The early adoption provision of FSP No. FAS 107-1 and APB 28-1 is available only if an entity also elects to apply the early adoption provisions of FASB Staff Position No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP No. FAS 157-4), and FASB Staff Position No. FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP No. FAS 115-2 and FAS 124-2). We adopted these three FASB Staff Positions in the first quarter of 2009, none of which has affected our financial position or results of operations. However, the adoption of FSP No. FAS 107-1 and APB 28-1 resulted in additional interim disclosures discussed below.

Our financial instruments include cash and temporary cash investments, restricted cash, receivables, payables, debt, capital lease obligations, commodity derivative contracts, and foreign currency derivative contracts. The estimated fair values of these financial instruments approximate their carrying amounts as reflected in the consolidated balance sheets, except for certain debt as discussed in Note 5. The fair values of our debt, commodity derivative contracts, and foreign currency derivative contracts were estimated primarily based on quoted market prices and inputs other than quoted prices that are observable for the asset or liability.

FASB Statement No. 165
In May 2009, the FASB issued Statement No. 165, “Subsequent Events.” Statement No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In particular, Statement No. 165 provides guidance regarding (i) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (ii) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and (iii) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The provisions of Statement No. 165 are to be applied prospectively and are effective for interim or annual financial periods ending after June 15, 2009. The adoption of Statement No. 165 in the second quarter of 2009 did not affect our financial position or results of operations but did result in additional disclosures, which are provided in Note 1.

FASB Statement No. 166
In June 2009, the FASB issued Statement No. 166, “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140.” Statement No. 166 amends and clarifies the provisions of Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” in order to address application and disclosure issues. In general, Statement No. 166 clarifies the requirements for derecognizing transferred financial assets, removes the concept of a qualifying special-purpose entity and related exceptions, and requires additional disclosures related to transfers of financial assets. Statement No. 166 is effective for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2009, and earlier application is prohibited. The adoption of Statement No. 166 effective January 1, 2010 is not expected to materially affect our financial position or results of operations.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FASB Statement No. 167
In June 2009, the FASB issued Statement No. 167, “Amendments to FASB Interpretation No. 46(R).” Statement No. 167 amends the provisions of FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities,” to include entities previously considered qualifying special-purpose entities, as the concept of these entities was eliminated by Statement No. 166. This statement also clarifies consolidation requirements and expands disclosure requirements related to variable interest entities. Statement No. 167 is effective for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2009, and earlier application is prohibited. The adoption of Statement No. 167 effective January 1, 2010 is not expected to materially affect our financial position or results of operations.

FASB Statement No. 168
In June 2009, the FASB issued Statement No. 168, “The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162” (Codification). Statement No. 168 replaces Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” and establishes the Codification as the source of authoritative GAAP recognized by the FASB, to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of Statement No. 168, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. Statement No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of Statement No. 168 in the third quarter of 2009 is not expected to materially affect our financial position or results of operations. Commencing with the Form 10-Q for the third quarter of 2009, future filings with the SEC will reference the Codification rather than prior accounting and reporting standards.

3. ACQUISITION

In the second quarter of 2009, we acquired seven ethanol plants and a site under development from VeraSun. Because VeraSun was subject to bankruptcy proceedings and different lenders were involved with various plants, three separate closings were required to consummate the acquisition of these ethanol plants. On April 1, 2009, we closed on the acquisition of ethanol plants located in Charles City, Fort Dodge, and Hartley, Iowa; Aurora, South Dakota; and Welcome, Minnesota, and a site under development located in Reynolds, Indiana for consideration of $350 million. Through subsequent closings on April 9, 2009 and May 8, 2009, we acquired VeraSun’s ethanol plant in Albert City, Iowa, for consideration of $72 million and VeraSun’s ethanol plant in Albion, Nebraska, for consideration of $55 million, respectively. In conjunction with the acquisition of the seven ethanol plants, we also paid $79 million primarily for inventory and certain other working capital. We have elected to use the LIFO method of accounting for the commodity inventories related to the acquired ethanol business. The acquisition of these ethanol plants is referred to as the VeraSun Acquisition. We incurred approximately $10 million of acquisition-related costs that were recognized as expense in “general and administrative expenses” in the consolidated statements of income for the three and six months ended June 30, 2009.

The acquired ethanol business involves the production and marketing of ethanol and its co-products, including distillers grains. The ethanol operations are being reported as a new operating segment in Note 11, the operations of which will complement our existing clean motor fuels business. The

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

acquisition cost was funded with part of the proceeds from a $1 billion issuance of notes in March 2009, which is discussed in Note 5.

An independent appraisal of the assets acquired in the VeraSun Acquisition has been substantially completed, and the assets acquired and the liabilities assumed have been recognized at their acquisition-date fair values as determined by the appraisal and other evaluations as follows (in millions):

Current assets, primarily inventory	$	77
Property, plant and equipment		491
Identifiable intangible assets		1
Current liabilities		(10	)
Other long-term liabilities		(3	)
Total consideration	$	556

Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the VeraSun Acquisition, and no significant contingent assets or liabilities were acquired or assumed in the acquisition.

The consolidated statements of income include the results of operations of the various ethanol plants commencing on their respective closing dates. The operating revenues and net income associated with the acquired ethanol plants included in our consolidated statements of income for the three and six months ended June 30, 2009, and the consolidated pro forma operating revenues, net income (loss), and earnings (loss) per common share – assuming dilution of the combined entity had the VeraSun Acquisition occurred on January 1, 2009 and 2008, are shown in the table below (in millions, except per share amounts). The pro forma information assumes that the purchase price was funded with proceeds from the issuance of $556 million of debt on January 1 of each respective year. The pro forma amounts for the three months ended June 30, 2009 are the same as actual consolidated results for that period because the two acquired plants with closing dates subsequent to April 1, 2009 were not operating during the second quarter prior to our acquisition of those facilities. The pro forma financial information is not necessarily indicative of the results of future operations.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2009			2008		2009		2008
Actual amounts from acquired business from April 1 – June 30, 2009:
Operating revenues	$	263			N/A	$	263		N/A
Net income		13			N/A		13		N/A
Consolidated pro forma:
Operating revenues		17,925		$	37,059		31,972	$	65,327
Net income (loss)		(254	)		734		49		1,004
Earnings (loss) per common share – assuming dilution		(0.48	)		1.37		0.09		1.87

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. INVENTORIES

Inventories consisted of the following (in millions):

	June 30,		December 31,
	2009		2008
Refinery feedstocks	$	2,065	$	2,140
Refined products and blendstocks		2,105		2,224
Ethanol feedstocks and products		100		–
Convenience store merchandise		93		90
Materials and supplies		198		183
Inventories	$	4,561	$	4,637

As of June 30, 2009 and December 31, 2008, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $3.0 billion and $686 million, respectively.

5. DEBT

Non-Bank Debt
On April 1, 2009, we made scheduled debt repayments of $200 million related to our 3.5% notes and $9 million related to our 5.125% Series 1997D industrial revenue bonds.

In March 2009, we issued $750 million of 9.375% notes due March 15, 2019 and $250 million of 10.5% notes due March 15, 2039. Proceeds from the issuance of these notes totaled approximately $998 million, before deducting underwriting discounts and other issuance costs of $8 million.

On February 1, 2008, we redeemed our 9.50% senior notes for $367 million, or 104.75% of stated value. These notes had a carrying amount of $381 million on the date of redemption, resulting in a gain of $14 million that was included in “other income (expense), net” in the consolidated statement of income. In addition, in March 2008, we made a scheduled debt repayment of $7 million related to certain of our other debt.

Under the indenture related to our $100 million of 6.75% senior notes with a maturity date of October 15, 2037, on July 31, 2009, we notified the holders of such notes of our obligation to purchase any of those notes for which a written notice of purchase (purchase notice) is received from the holders prior to September 15, 2009. Any notes for which a purchase notice is received will be purchased at 100% of their principal amount plus accrued and unpaid interest to October 15, 2009, the date of payment of the purchase price.

Bank Credit Facilities
During the six months ended June 30, 2009, we had no borrowings or repayments under our revolving bank credit facilities. As of June 30, 2009, we had no borrowings outstanding under our revolving bank credit facilities.

As of June 30, 2009, we had $247 million of letters of credit outstanding under our uncommitted short-term bank credit facilities and $249 million of letters of credit outstanding under our U.S. committed

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

revolving credit facilities. Under our Canadian committed revolving credit facility, we had Cdn. $19 million of letters of credit outstanding as of June 30, 2009.

In June 2008, we entered into a one-year committed revolving letter of credit facility under which we could obtain letters of credit of up to $300 million to support certain of our crude oil purchases. In June 2009, we amended this agreement to extend the maturity date to June 2010. We are being charged letter of credit issuance fees in connection with the letter of credit facility.

During the six months ended June 30, 2008, we borrowed and repaid $296 million under our revolving bank credit facility.

In July 2008, we entered into a one-year committed revolving letter of credit facility under which we could obtain letters of credit of up to $275 million. This credit facility expired in July 2009.

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. We amended our agreement in June 2009 to extend the maturity date to June 2010.

As of December 31, 2008, the amount of eligible receivables sold to the third-party entities and financial institutions was $100 million, which was repaid in February 2009. In March 2009, we sold $100 million of eligible receivables to the third-party entities and financial institutions. In April 2009, we sold an additional $400 million of eligible receivables under this program, which we repaid in June 2009. As of June 30, 2009, the amount of eligible receivables sold to the third-party entities and financial institutions was $100 million. Proceeds from the sale of receivables under this facility are reflected as debt in our consolidated balance sheets.

Other Disclosures
The estimated fair value of our debt, including current portion, was as follows (in millions):

	June 30,		December 31,
	2009		2008
Carrying amount	$	7,330	$	6,537
Fair value		7,305		6,462

6. STOCKHOLDERS’ EQUITY

Common Stock Offering
On June 3, 2009, we sold in a public offering 46 million shares of our common stock, which included 6 million shares related to an overallotment option exercised by the underwriters, at a price of $18.00 per share and received proceeds, net of underwriting discounts and commissions and other issuance costs, of $799 million.

Treasury Stock
No significant purchases of our common stock were made during the six months ended June 30, 2009. During the six months ended June 30, 2008, we purchased 12.6 million shares of our common stock at a cost of $700 million in connection with the administration of our employee benefit plans and common

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

stock purchase programs authorized by our board of directors. During the six months ended June 30, 2009 and 2008, we issued 0.5 million shares and 0.9 million shares, respectively, from treasury for our employee benefit plans.

Common Stock Dividends
On July 30, 2009, our board of directors declared a regular quarterly cash dividend of $0.15 per common share payable on September 16, 2009 to holders of record at the close of business on August 12, 2009.

7. EARNINGS (LOSS) PER COMMON SHARE

Earnings (loss) per common share amounts were computed as follows (dollars and shares in millions, except per share amounts):

	Three Months Ended June 30,
	2009					2008
	Restricted		Common			Restricted		Common
	Stock		Stock			Stock		Stock
Earnings (loss) per common share:
Net income (loss)			$	(254	)			$	734
Less dividends paid:
Common stock				77					79
Nonvested restricted stock				1					–
Undistributed earnings (loss)			$	(332	)			$	655
Weighted-average common shares outstanding		2		525			1		526
Earnings (loss) per common share:
Distributed earnings	$	0.15	$	0.15		$	0.15	$	0.15
Undistributed earnings (loss)		–		(0.63	)		1.24		1.24
Total earnings (loss) per common share (1)	$	0.15	$	(0.48	)	$	1.39	$	1.39
Earnings (loss) per common share – assuming dilution:
Net income (loss)			$	(254	)			$	734
Weighted-average common shares outstanding				525					526
Common equivalent shares (2):
Stock options				–					8
Performance awards and other benefit plans				–					–
Weighted-average common shares outstanding – assuming dilution				525					534
Earnings (loss) per common share – assuming dilution			$	(0.48	)			$	1.37

(1)	The basic earnings per common share amount originally reported for the three months ended June 30, 2008 changed from $1.40 as a result of the adoption of FSP No. EITF 03-6-1 effective January 1, 2009, as discussed in Note 2.
(2)	Common equivalent shares were excluded from the computation of diluted earnings per share for the three months ended June 30, 2009 because the effect of including such shares would be anti-dilutive.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Six Months Ended June 30,
	2009					2008
	Restricted		Common			Restricted		Common
	Stock		Stock			Stock		Stock
Earnings per common share:
Net income			$	55				$	995
Less dividends paid:
Common stock				154					143
Nonvested restricted stock				1					–
Undistributed earnings (loss)			$	(100	)			$	852
Weighted-average common shares outstanding		2		520			1		529
Earnings per common share:
Distributed earnings	$	0.30	$	0.30		$	0.26	$	0.27
Undistributed earnings (loss)		–		(0.19	)		1.61		1.61
Total earnings per common share	$	0.30	$	0.11		$	1.87	$	1.88
Earnings per common share – assuming dilution:
Net income			$	55				$	995
Weighted-average common shares outstanding				520					529
Common equivalent shares:
Stock options				4					8
Performance awards and other benefit plans				1					–
Weighted-average common shares outstanding – assuming dilution				525					537
Earnings per common share – assuming dilution			$	0.11				$	1.85

The following table reflects potentially dilutive securities that were excluded from the calculation of “earnings (loss) per common share – assuming dilution” as the effect of including such securities would have been anti-dilutive (in millions). As indicated above, for the three months ended June 30, 2009, common equivalent shares, which represent primarily stock options, were excluded as a result of the net loss reported for the second quarter of 2009. In addition, for all periods, certain stock option amounts presented below were excluded, representing outstanding stock options for which the exercise prices were greater than the average market price of the common shares during each respective reporting period.

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Common equivalent shares		5		–		–		–
Stock options		11		4		10		4

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. STATEMENTS OF CASH FLOWS

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):

	Six Months Ended June 30,
	2009			2008
Decrease (increase) in current assets:
Restricted cash	$	(10	)	$	(69	)
Receivables, net		(1,286	)		(54	)
Inventories		172			(865	)
Income taxes receivable		181			–
Prepaid expenses and other		11			4
Increase (decrease) in current liabilities:
Accounts payable		1,592			1,466
Accrued expenses		(97	)		(144	)
Taxes other than income taxes		(41	)		(61	)
Income taxes payable		35			(88	)
Changes in current assets and current liabilities	$	557		$	189

The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable consolidated 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;

• the amounts shown above exclude the current assets and current liabilities acquired in connection with the VeraSun Acquisition;

• previously accrued capital expenditures, deferred turnaround and catalyst costs, and contingent earn-out payments, as well as advance proceeds related to the sale of assets, are reflected in investing activities in the consolidated statements of cash flows;

• 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 in the consolidated statements of cash flows when the purchases are settled and paid;

• changes in assets held for sale and liabilities related to assets held for sale pertaining to the operations of the Krotz Springs Refinery prior to its sale to Alon Refining Krotz Springs, Inc. (Alon), a subsidiary of Alon USA Energy, Inc., in July 2008 are reflected in the line items to which the changes relate in the table above; and

• certain differences between consolidated balance sheet changes and consolidated statement of cash flow changes reflected above result from translating foreign currency denominated amounts at different exchange rates.

There were no significant noncash investing or financing activities for the six months ended June 30, 2009 and 2008.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Cash flows related to interest and income taxes were as follows (in millions):

	Six Months Ended June 30,
	2009			2008
Interest paid in excess of amount capitalized	$	152		$	199
Income taxes paid (net of tax refunds received)		(144	)		659

9. FAIR VALUE MEASUREMENTS

Statement No. 157 establishes a fair value hierarchy (Level 1, Level 2, or Level 3) based on the quality of inputs used to measure fair value. Pursuant to the provisions of Statement No. 157, fair values determined by Level 1 inputs utilize quoted prices in active markets for identical assets or liabilities. Fair values determined by Level 2 inputs are based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. We use appropriate valuation techniques based on the available inputs to measure the fair values of our applicable assets and liabilities. When available, we measure fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

The table below presents information (dollars in millions) about our financial assets and liabilities measured and recorded at fair value on a recurring basis and indicates the fair value hierarchy of the inputs utilized by us to determine the fair values as of June 30, 2009 and December 31, 2008.

	Fair Value Measurements Using
	Quoted		Significant
	Prices		Other		Significant
	in Active		Observable		Unobservable
	Markets		Inputs		Inputs		Total as of
	(Level 1)		(Level 2)		(Level 3)		June 30, 2009
Assets:
Commodity derivative contracts	$	12	$	537	$	–	$	549
Nonqualified benefit plans		99		–		–		99
Alon earn-out agreement		–		–		38		38
Liabilities:
Commodity derivative contracts		19		7		–		26
Certain nonqualified benefit plans		29		–		–		29

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	Fair Value Measurements Using
	Quoted		Significant
	Prices		Other		Significant
	in Active		Observable		Unobservable		Total as of
	Markets		Inputs		Inputs		December 31,
	(Level 1)		(Level 2)		(Level 3)		2008
Assets:
Commodity derivative contracts	$	40	$	610	$	–	$	650
Nonqualified benefit plans		98		–		–		98
Alon earn-out agreement		–		–		13		13
Liabilities:
Commodity derivative contracts		–		7		–		7
Certain nonqualified benefit plans		26		–		–		26

The valuation methods used to measure our financial instruments at fair value are as follows:

• Commodity derivative contracts, consisting primarily of exchange-traded futures and swaps, are measured at fair value using the market approach pursuant to the provisions of Statement No. 157. 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 since 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.

• Nonqualified benefit plan assets and certain nonqualified benefit plan liabilities are measured at fair value using a market approach based on quotations from national securities exchanges and are categorized in Level 1 of the fair value hierarchy.

• The Alon earn-out agreement, which we received as partial consideration for the sale of our Krotz Springs Refinery in July 2008, is measured at fair value using a discounted cash flow model and is categorized in Level 3 of the fair value hierarchy. Significant inputs to the model include expected payments and discount rates that consider the effects of both credit risk and the time value of money.

Deposits of $104 million in broker accounts covered by master netting arrangements are included in the fair value of the commodity derivatives reflected in Level 1. Certain of our commodity derivative contracts under master netting arrangements include both asset and liability positions. Under the guidance of FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39,” 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.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following is a reconciliation of the beginning and ending balances (in millions) for fair value measurements developed using significant unobservable inputs for the three and six months ended June 30, 2009. We did not have any fair value measurements using significant unobservable inputs for the six months ended June 30, 2008.

	Three Months		Six Months
	Ended June 30,		Ended June 30,
	2009		2009
Balance at beginning of period	$	24	$	13
Net unrealized gains included in earnings		14		25
Transfers in and/or out of Level 3		–		–
Balance as of June 30, 2009	$	38	$	38

Unrealized gains for the three and six months ended June 30, 2009, which are reported in “other income (expense), net” in the consolidated statements of income, relate to the Alon earn-out agreement that was still held at the reporting date. These unrealized gains were offset by the recognition in “other income (expense), net” of losses on derivative instruments entered into to hedge the risk of changes in the fair value of the Alon earn-out agreement. The derivative instruments used to hedge the Alon earn-out agreement are included in the “commodity derivative contracts” amounts reflected in the fair value table above.

The table below presents information (dollars in millions) about our nonfinancial liabilities measured and recorded at fair value on a nonrecurring basis that arose on or after January 1, 2009 (the date of adoption of FSP No. FAS 157-2), and indicates the fair value hierarchy of the inputs utilized by us to determine the fair values as of June 30, 2009.

	Fair Value Measurements Using
	Quoted		Significant
	Prices		Other		Significant
	in Active		Observable		Unobservable
	Markets		Inputs		Inputs		Total as of
	(Level 1)		(Level 2)		(Level 3)		June 30, 2009
Liabilities:
Asset retirement obligations	$	–	$	–		$ 9		$ 9

Asset retirement obligations in the table above are calculated based on the present value of estimated removal and other closure costs using our internal risk-free rate of return or appropriate equivalent.

10. PRICE RISK MANAGEMENT ACTIVITIES

We enter into derivative instruments to manage our exposure to commodity price risk, interest rate risk, and foreign currency risk, and to hedge price risk on other contractual derivatives that we have entered into. In addition, we use derivative instruments for trading purposes based on our fundamental and technical analysis of market conditions. All derivative instruments are recorded on our balance sheet as either assets or liabilities measured at their fair values. 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 activity. 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, are recognized currently in income in the

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 hedging relationships (hedges 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.

Commodity Price Risk
We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refining operations. To reduce the impact of this price volatility on our results of operations and cash flows, we use derivative commodity instruments, including swaps, futures, and options, to manage our exposure to commodity price risks. For such 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 derivative commodity instruments for trading purposes. Our objectives for entering into each of these types of derivative instruments and the level of activity of each as of June 30, 2009 are described below.

Fair Value Hedges
Fair value hedges are used to hedge 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 normally represents the amount by which our inventories differ from our previous year-end LIFO inventory levels.

As of June 30, 2009, we had the following outstanding derivative commodity instruments that were entered into to hedge crude oil and refined product inventories. The information presents the volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).

Derivative Instrument / Maturity	Contract Volumes
Futures – short (2009)		5,178

Cash Flow Hedges
Cash flow hedges are used to hedge certain forecasted feedstock and product purchases, refined product sales, and natural gas purchases. The purpose of our cash flow hedges is to lock in the price of forecasted feedstock or natural gas purchases or refined product sales at existing market prices that are deemed favorable by management.

As of June 30, 2009, we had the following outstanding derivative commodity instruments that were entered into to hedge forecasted purchases or sales of crude oil and refined products. The information presents the volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Derivative Instrument / Maturity	Contract Volumes
Swaps – long:
2009		14,157
2010		15,900
Swaps – short:
2009		14,157
2010		15,900
Futures – long (2009)		1,211

Economic Hedges
Economic hedges are hedges not designated as fair value or cash flow hedges that are used to (i) manage price volatility in certain refinery feedstock, refined product, and grain inventories, (ii) manage price volatility in certain forecasted refinery feedstock, product, and grain purchases, refined product sales, and natural gas purchases; and (iii) manage price volatility in the referenced product margins associated with the Alon earn-out agreement, which is a separate contractual derivative that we entered into with the sale of our Krotz Springs Refinery, as further discussed in Note 9. Our objective in 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 June 30, 2009, we had the following outstanding derivative commodity instruments that were entered into as economic hedges. The information presents the volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as grain contracts that are presented in thousands of bushels).

Derivative Instrument / Maturity	Contract Volumes
Swaps – long:
2009		52,625
2010		51,514
2011		11,750
Swaps – short:
2009		36,233
2010		47,878
2011		8,850
Futures – long:
2009		238,825
2010		39,618
2009 (grain)		7,605
2010 (grain)		50
Futures – short:
2009		231,332
2010		39,174
2009 (grain)		20,355
2010 (grain)		3,405

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Trading Activities
These represent derivative commodity instruments held or issued for trading purposes. Our objective in entering into derivative commodity instruments for trading purposes is to take advantage of existing market conditions related to crude oil and refined products that management perceives as opportunities to benefit our results of operations and cash flows, but for which there are no related physical transactions. As of June 30, 2009, we had the following outstanding derivative commodity instruments that were entered into for trading purposes. The information presents the 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).

Derivative Instrument / Maturity	Contract Volumes
Swaps – long:
2009		10,413
2010		18,780
2011		3,000
Swaps – short:
2009		12,455
2010		22,008
2011		3,900
Futures – long:
2009		30,122
2010		2,321
2009 (natural gas)		5,350
2010 (natural gas)		100
Futures – short:
2009		30,214
2010		2,346
2009 (natural gas)		5,100
2010 (natural gas)		100

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, we have at times used interest rate swap agreements to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt. These interest rate swap agreements are generally accounted for as fair value hedges. However, we have not had any outstanding interest rate swap agreements since 2006.

Foreign Currency Risk
We are exposed to exchange rate fluctuations on transactions related to our Canadian 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 June 30, 2009, we had commitments to purchase $301 million of U.S. dollars. These commitments matured on or before July 20, 2009, resulting in a $7 million loss in the third quarter of 2009.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Fair Values of Derivative Instruments
The following tables provide information about the fair values of our derivative instruments as of June 30, 2009 (in millions) and the line items in the balance sheet in which the fair values are reflected. See Note 9 for additional information related to the fair values of our derivative instruments. As indicated in Note 9, we net fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty under master netting arrangements. The table below, however, is presented on a gross asset and gross liability basis as required by Statement No. 161, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts. In addition, in Note 9 we included cash collateral of $104 million in the fair value of the commodity derivatives; the cash collateral is not reflected in the table below.

	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	3	Receivables, net	$	1
Futures	Accrued expenses		31	Accrued expenses		49
Swaps	Receivables, net		425	Receivables, net		385
Swaps	Prepaid expenses and other current assets		1,409	Prepaid expenses and other current assets		1,235
Swaps	Accrued expenses		293	Accrued expenses		293
Total derivatives designated as hedging instruments		$	2,161		$	1,963
Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	28	Receivables, net	$	15
Futures	Accrued expenses		3,560	Accrued expenses		3,668
Swaps	Receivables, net		671	Receivables, net		550
Swaps	Prepaid expenses and other current assets		1,458	Prepaid expenses and other current assets		1,256
Swaps	Accrued expenses		93	Accrued expenses		100
Alon earn-out agreement	Receivables, net		38	Accrued expenses		–
Foreign currency contracts	Receivables, net		–	Accounts payable		–
Total derivatives not designated as hedging instruments		$	5,848		$	5,589
Total derivatives		$	8,009		$	7,552

24

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 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, in that 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 June 30, 2009, we had net receivables related to derivative instruments of $32 million from counterparties in the refining industry and $343 million from counterparties in the financial services industry. These amounts represent the aggregate receivables from 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 that we enter into. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.

Effect of Derivative Instruments on Statements of 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 for the three and six months ended June 30, 2009 (in millions), and the line items in the financial statements in which such gains and losses are reflected.

Location

Location

Amount

of Gain or

of Gain or

Amount

of Gain or

(Loss)

Amount of

(Loss)

of Gain or

(Loss)

Derivatives in

Recognized

Gain or (Loss)

Recognized

(Loss)

Recognized

Fair Value

in Income

Recognized in

in Income

Recognized

in Income for

Hedging

on

Income

on

in Income

Ineffective Portion

Relationships

Derivatives

on Derivatives

Hedged Item

on Hedged Item

of Derivative (1)

Three

Six

Three

Six

Three

Six

Months

Months

Months

Months

Months

Months

Ended

Ended

Ended

Ended

Ended

Ended

June 30,

June 30,

June 30,

June 30,

June 30,

June 30,

2009

2009

2009

2009

2009

2009

Commodity contracts

Cost of sales

$

(74

)

$

(89

)

Cost of sales

$

75

$

90

$

1

$

1

Total

$

(74

)

$

(89

)

$

75

$

90

$

1

$

1

(1) For fair value hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness. No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges.

25

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Amount of

Location of

Amount of

Location of

Amount of

Gain or (Loss)

Gain or (Loss)

Gain or (Loss)

Gain or (Loss)

Gain or (Loss)

Derivatives in

Recognized in

Reclassified from

Reclassified from

Recognized in

Recognized in

Cash Flow

OCI on

Accumulated OCI

Accumulated OCI

Income on

Income on

Hedging

Derivatives

into Income

into Income

Derivatives

Derivatives

Relationships

(Effective Portion)

(Effective Portion)

(Effective Portion)

(Ineffective Portion)

(Ineffective Portion) (1)

Three

Six

Three

Six

Three

Six

Months

Months

Months

Months

Months

Months

Ended

Ended

Ended

Ended

Ended

Ended

June 30,

June 30,

June 30,

June 30,

June 30,

June 30,

2009

2009

2009

2009

2009

2009

Commodity contracts (2)

$

5

$

97

Cost of sales

$

111

$

172

Cost of sales

$

(1

)

$

(1

)

Total

$

5

$

97

$

111

$

172

$

(1

)

$

(1

)

(1)

No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.

(2)

For the three and six months ended June 30, 2009, cash flow hedges primarily related to forward sales of distillates and associated forward purchases of crude oil, with $120 million of cumulative after-tax gains on cash flow hedges remaining in “accumulated other comprehensive loss” as of June 30, 2009. We expect that a significant amount of the deferred gains at June 30, 2009 will be reclassified into “cost of sales” over the next 12 months as a result of hedged transactions that are forecasted to occur. The amount ultimately realized in income, however, will differ as commodity prices change. For the three and six months ended June 30, 2009, there were no amounts reclassified from “accumulated other comprehensive loss” into income as a result of the discontinuance of cash flow hedge accounting.

	Location of	Amount of
Derivatives Designated as	Gain or (Loss)	Gain or (Loss)
Economic Hedges	Recognized in	Recognized in
and Other	Income on	Income on
Derivative Instruments	Derivatives	Derivatives
		Three Months Ended			Six Months Ended
		June 30, 2009			June 30, 2009
Commodity contracts	Cost of sales	$	(58	)	$	38
Foreign currency contracts	Cost of sales		(22	)		(16	)
			(80	)		22
Alon earn-out agreement	Other income (expense)		14			25
Alon earn-out hedge (commodity contracts)	Other income (expense)		(48	)		(63	)
			(34	)		(38	)
Total		$	(114	)	$	(16	)

	Location of	Amount of
	Gain or (Loss)	Gain or (Loss)
	Recognized in	Recognized in
Derivatives Designated as	Income on	Income on
Trading Activities	Derivatives	Derivatives
		Three Months Ended		Six Months Ended
		June 30, 2009		June 30, 2009
Commodity contracts	Cost of sales	$	25	$	116
Total		$	25	$	116

26

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. SEGMENT INFORMATION

Prior to the second quarter of 2009, we had two reportable segments, which were refining and retail. As a result of our acquisition of seven ethanol plants from VeraSun during the second quarter of 2009 (as discussed in Note 3), ethanol is now being presented as a third reportable segment. Segment information for our three reportable segments was as follows (in millions):

	Refining			Retail		Ethanol		Corporate			Total
Three months ended June 30, 2009:
Operating revenues from external customers	$	15,693		$	1,969	$	263	$	–		$	17,925
Intersegment revenues		1,281			–		29		–			1,310
Operating income (loss)		(268	)		65		22		(136	)		(317	)
Three months ended June 30, 2008:
Operating revenues from external customers		33,625			3,015		–		–			36,640
Intersegment revenues		2,367			–		–		–			2,367
Operating income (loss)		1,235			49		–		(126	)		1,158
Six months ended June 30, 2009:
Operating revenues from external customers		27,885			3,601		263		–			31,749
Intersegment revenues		2,288			–		29		–			2,317
Operating income (loss)		339			121		22		(292	)		190
Six months ended June 30, 2008:
Operating revenues from external customers		59,055			5,530		–		–			64,585
Intersegment revenues		4,267			–		–		–			4,267
Operating income (loss)		1,803			99		–		(272	)		1,630

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

	June 30,		December 31,
	2009		2008
Refining	$	32,464	$	30,801
Retail		1,843		1,818
Ethanol		597		–
Corporate		2,317		1,798
Total consolidated assets	$	37,221	$	34,417

27

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost related to our defined benefit plans were as follows for the three and six months ended June 30, 2009 and 2008 (in millions):

							Other Postretirement
	Pension Plans						Benefit Plans
	2009			2008			2009			2008
Three months ended June 30:
Components of net periodic benefit cost:
Service cost	$	26		$	24		$	3		$	4
Interest cost		20			19			7			7
Expected return on plan assets		(27	)		(26	)		–			–
Amortization of:
Prior service cost (credit)		1			–			(5	)		(3	)
Net loss		2			1			1			1
Net periodic benefit cost	$	22		$	18		$	6		$	9
Six months ended June 30:
Components of net periodic benefit cost:
Service cost	$	52		$	47		$	6		$	7
Interest cost		40			38			13			14
Expected return on plan assets		(54	)		(52	)		–			–
Amortization of:
Prior service cost (credit)		1			1			(9	)		(5	)
Net loss		5			1			3			2
Net periodic benefit cost	$	44		$	35		$	13		$	18

We expect to contribute a total of approximately $70 million to our qualified pension plans during 2009. In January 2009, we contributed $50 million of this amount to our main qualified pension plan. There were no significant additional contributions made during the six months ended June 30, 2009.

13. COMMITMENTS AND CONTINGENCIES

Contingent Earn-Out Agreements
In January 2008, we made a previously accrued earn-out payment of $25 million related to the acquisition of the St. Charles Refinery, which was the final payment under that agreement. As of June 30, 2009, we have no further commitments with respect to contingent earn-out agreements. However, see Note 9 for a discussion of a contingent receivable from Alon related to a three-year earn-out agreement received in July 2008 as partial consideration for the sale of our Krotz Springs Refinery. Based on our calculations under the provisions of the agreement, we determined that $28 million was earned for the first year of this three-year agreement. Alon has calculated a different amount, and we are in the process of reconciling the different amounts. The resolution of this matter is not expected to result in a material difference.

Insurance Recoveries
During the first quarter of 2007, our McKee Refinery was shut down due to a fire originating in its propane deasphalting unit, resulting in business interruption losses for which we submitted claims to our

28

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

insurance carriers under our insurance policies. We reached a settlement with the insurance carriers on our claims, resulting in pre-tax income of approximately $100 million in the first quarter of 2008 that was recorded as a reduction to “cost of sales.”

TRN Refinery Commitment
On May 20, 2009, we entered into a Business Sale Agreement (Agreement) with Dow Chemical Company and certain of its affiliates (Dow) under which we agreed to purchase Dow’s 45% equity interest in Total Raffinaderij Nederland N.V. (TRN), which owns a refinery in the Netherlands, along with related businesses of TRN owned by Dow. The Agreement extends through December 31, 2009 and provides for a purchase price of $600 million plus an amount for related inventories. The closing of the transaction was conditioned upon, among other things, the expiration of a right of first refusal held by Total S.A. (Total) to purchase Dow’s equity interest in TRN or a waiver by Total of such right of first refusal. In June 2009, Total exercised its right of first refusal. To our knowledge, Total’s acquisition of Dow’s equity interest in TRN has not closed, and we and Dow have not executed a formal termination of the Agreement.

Tax Matters
We are subject to extensive tax liabilities, including federal, state, and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise, withholding, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. 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.

Effective January 1, 2007, the Government of Aruba (GOA) enacted a turnover tax on revenues from the sale of goods produced and services rendered in Aruba. The turnover tax, which is 3% for on-island sales and services and 1% on export sales, is being assessed by the GOA on sales by our Aruba Refinery. However, due to a previous tax holiday that was granted to our Aruba Refinery by the GOA through December 31, 2010 as well as other reasons, we believe that exports by our Aruba Refinery should not be subject to this turnover tax. We commenced arbitration proceedings with the Netherlands Arbitration Institute pursuant to which we are seeking to enforce our rights under the tax holiday and other agreements related to the refinery. The arbitration hearing was held on February 3-4, 2009. We anticipate a decision sometime later this year. We have also filed protests of these assessments through proceedings in Aruba. In April 2008, we entered into an escrow agreement with the GOA and Caribbean Mercantile Bank NV (CMB), pursuant to which we agreed to deposit an amount equal to the disputed turnover tax on exports into an escrow account with CMB, pending resolution of the tax protest proceedings in Aruba. Under this escrow agreement, we are required to continue to deposit an amount equal to the disputed tax on a monthly basis until the tax dispute is resolved through the Aruba proceedings. On April 20, 2009, we were notified that the Aruban tax court overruled our protests with respect to the turnover tax assessed in January and February 2007, totaling $8 million. Under the escrow agreement, we expensed and paid $8 million, plus $1 million of interest, to the GOA in the second quarter of 2009. The tax protests for the remaining periods remain outstanding, and no expense or liability has been recognized in our consolidated financial statements with respect to these remaining periods. Amounts deposited under the escrow agreement, which totaled $111 million and $102 million as of June 30, 2009 and December 31, 2008, respectively, are reflected as “restricted cash” in our consolidated balance sheets.

29

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In addition to the turnover tax described above, the GOA has also asserted other tax amounts aggregating approximately $25 million related to dividends and other tax items. The GOA, through the arbitration, is also now questioning the validity of the tax holiday generally, although the GOA has not issued any formal assessment for profit tax at any time during the tax holiday period. We believe that the provisions of our tax holiday agreement exempt us from all of these taxes and, accordingly, no expense or liability has been recognized in our consolidated financial statements. We are also challenging approximately $30 million in foreign exchange payments made to the Central Bank of Aruba as payments exempted under our tax holiday, as well as other reasons. These taxes and assessments are also being addressed in the arbitration proceedings discussed above.

American Clean Energy and Security Act of 2009
On June 26, 2009, the U.S. House of Representatives narrowly approved the American Clean Energy and Security Act of 2009 (ACESA), also known as the Waxman-Markey Bill. The ACESA, if passed by the U.S. Senate, would establish a national “cap-and-trade” program beginning in 2012 to address greenhouse gas emissions and climate change. The ACESA proposes to reduce carbon dioxide and other greenhouse gas emissions by 3% below 2005 levels by 2012, 20% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050. The cap-and-trade program would require businesses that emit greenhouse gases to acquire emission credits from the government, other businesses, or through an auction process. In addition, refiners would be obligated to purchase emission credits associated with the transportation fuels (gasoline, diesel, and jet fuel) sold and consumed in the United States. As a result of such a program, we could be required to purchase emission credits for greenhouse gas emissions resulting from our operations and from the fuels we sell. Although it is not possible at this time to predict the final form of the ACESA (or whether it will be passed by the U.S. Senate), any new federal restrictions on greenhouse gas emissions – including a cap-and-trade program – could result in increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have an adverse effect on our financial position, results of operations, and liquidity.

Litigation
MTBE Litigation
As of August 1, 2009, we were named as a defendant in 33 active cases alleging liability related to MTBE contamination in groundwater. The plaintiffs are generally water providers, governmental authorities, and private water companies alleging that refiners and marketers of MTBE and gasoline containing MTBE are liable for manufacturing or distributing a defective product. We have been named in these lawsuits together with many other refining industry companies. We are being sued primarily as a refiner and marketer of MTBE and gasoline containing MTBE. We do not own or operate gasoline station facilities in most of the geographic locations in which damage is alleged to have occurred. The lawsuits generally seek individual, unquantified compensatory and punitive damages, injunctive relief, and attorneys’ fees. Many of the cases are pending in federal court and are consolidated for pre-trial proceedings in the U.S. District Court for the Southern District of New York (Multi-District Litigation Docket No. 1358, In re: Methyl-Tertiary Butyl Ether Products Liability Litigation). Thirteen cases are pending in state court. We recently settled the City of New York case, which had been set for trial in June 2009. We expect that the Village of Hempstead and West Hempstead Water District cases will be set for trial in February 2010. Discovery is open in all cases. We believe that we have strong defenses to all claims and are vigorously defending the lawsuits.

30

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We have recorded a loss contingency liability with respect to our MTBE litigation portfolio in accordance with FASB Statement No. 5, “Accounting for Contingencies.” However, due to the inherent uncertainty of litigation, we believe that it is reasonably possible (as defined in Statement No. 5) that we may suffer a loss with respect to one or more of the lawsuits in excess of the amount accrued. We believe that such an outcome in any one of these lawsuits would not have a material adverse effect on our results of operations or financial position. However, we believe that an adverse result in all or a substantial number of these cases could have a material effect on our results of operations and financial position. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.

Retail Fuel Temperature Litigation
As of August 1, 2009, we were named in 21 consumer class action lawsuits relating to fuel temperature. We have been named in these lawsuits together with several other defendants in the retail petroleum marketing business. The complaints, filed in federal courts in several states, allege that because fuel volume increases with fuel temperature, the defendants have violated state consumer protection laws by failing to adjust the volume of fuel when the fuel temperature exceeded 60 degrees Fahrenheit. The complaints seek to certify classes of retail consumers who purchased fuel in various locations. The complaints seek an order compelling the installation of temperature correction devices as well as monetary relief. The federal lawsuits are consolidated into a multi-district litigation case in the U.S. District Court for the District of Kansas (Multi-District Litigation Docket No. 1840, In re: Motor Fuel Temperature Sales Practices Litigation). Discovery has commenced. The court is expected to rule on certain class certification issues in 2009. We believe that we have several strong defenses to these lawsuits and intend to contest them. We have not recorded a loss contingency liability with respect to this matter, but due to the inherent uncertainty of litigation, we believe that it is reasonably possible (as defined in Statement No. 5) that we may suffer a loss with respect to one or more of the lawsuits. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.

Rosolowski
Rosolowski v. Clark Refining & Marketing, Inc., et al., Judicial Circuit Court, Cook County, Illinois (Case No. 95-L 014703). We assumed this lawsuit in our acquisition of Premcor Inc. The lawsuit relates in part to a 1994 release to the atmosphere of spent catalyst from the now-closed Blue Island, Illinois refinery. The case was certified as a class action in 2000 with three classes, two of which received nominal or no damages, and one of which received a sizeable jury verdict. That class consisted of local residents who claimed property damage or loss of use and enjoyment of their property over a period of several years. In 2005, the jury returned a verdict for the plaintiffs of $80 million in compensatory damages and $40 million in punitive damages. However, following our motions for new trial and judgment notwithstanding the verdict (citing, among other things, misconduct by plaintiffs’ counsel and improper class certification), the trial judge in 2006 vacated the jury’s award and decertified the class. Plaintiffs appealed, and in June 2008 the state appeals court reversed the trial judge’s decision to decertify the class and set aside the judgment. Thereafter, the Illinois Supreme Court refused to hear the case and returned it to the trial court. We have submitted renewed motions for judgment notwithstanding the verdict or, alternatively, a new trial. While we do not believe that the ultimate resolution of this matter will have a material effect on our financial position or results of operations, we have recorded a loss contingency liability with respect to this matter in accordance with Statement No. 5.

31

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Other Litigation
We are also a party to additional claims and legal proceedings arising in the ordinary course of business. We believe that there is only a remote likelihood that future costs related to known contingent liabilities related to these legal proceedings would have a material adverse impact on our consolidated results of operations or financial position.

Asset Impairments
Under FASB Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” long-lived assets must be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the long-lived assets may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its fair value, with fair value determined under Statement No. 157, generally based on discounted estimated net cash flows.

In order to test long-lived assets for recoverability, management must make estimates of projected cash flows related to the asset being evaluated, which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment.

During the fourth quarter of 2008, there were severe disruptions in the capital and commodities markets that contributed to a significant decline in our common stock price, thus causing our market capitalization to decline to a level substantially below our net book value. Due to these adverse changes in market conditions during the fourth quarter of 2008, we evaluated our significant operating assets for potential impairment as of December 31, 2008, and we determined that the carrying amount of each of these assets was recoverable. The economic slowdown that began in 2008 continued throughout the first six months of 2009, thereby further reducing demand for refined products and putting significant pressure on refined product margins. Due to these economic conditions, in June 2009, we announced our plan to temporarily shut down the Aruba Refinery, which had a net book value of approximately $1.0 billion as of June 30, 2009, for at least two months as narrow heavy sour crude oil differentials currently make the refinery uneconomical to operate. The Aruba Refinery was shut down in July 2009. We are continuing to pursue potential transactions for this refinery, which may include the sale of the refinery. In June 2009, the coker unit at the Corpus Christi East Refinery was also temporarily shut down, partly due to economic reasons. As a result of these factors, we readdressed the potential impairment of all of our significant operating assets as of June 30, 2009, incorporating updated 2009 price assumptions into our estimated cash flows. Based on this analysis, we determined that the carrying amount of each of our significant operating assets continued to be recoverable as of June 30, 2009.

Also in the second quarter of 2009, due to the impact of the continuing economic slowdown on refining industry fundamentals and in an effort to conserve cash, we evaluated all of our capital projects currently in progress. As a result of this assessment, certain capital projects were permanently cancelled, resulting in the write-off of $122 million of project costs in the second quarter of 2009. We have also suspended continued construction activity on various other projects. For example, our two hydrocracker projects on the Gulf Coast, one at the St. Charles Refinery and the other at the Port Arthur Refinery, have been

32

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

suspended pending a reassessment of the demand for the additional refined product supply that would result from these projects. As of June 30, 2009, approximately $915 million of costs had been incurred on these two projects. In addition, various other projects with a total cost of approximately $430 million as of June 30, 2009 have also been suspended.

Due to the effect of the current unfavorable economic conditions on the refining industry, and our expectations of a continuation of such conditions for the near term, we will continue to monitor both our operating assets and our capital projects for potential asset impairments or project write-offs until conditions improve. Our current evaluations are focused on our Delaware City Refinery, which had a net book value of approximately $2.0 billion as of June 30, 2009. Additional assessments will be performed in conjunction with our annual strategic plan process in the third quarter of 2009. Changes in market conditions, as well as changes in assumptions used to test for recoverability and to determine fair value, could result in significant impairment charges or project write-offs in the future, thus affecting our earnings.

14. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

In conjunction with the acquisition of Premcor Inc. on September 1, 2005, Valero Energy Corporation has fully and unconditionally guaranteed the following debt of The Premcor Refining Group Inc. (PRG), a wholly owned subsidiary of Valero Energy Corporation, that was outstanding as of June 30, 2009:

• 6.75% senior notes due February 2011,

• 6.125% senior notes due May 2011,

• 6.75% senior notes due May 2014, and

• 7.5% senior notes due June 2015.

In addition, PRG has fully and unconditionally guaranteed all of the outstanding debt issued by Valero Energy Corporation.

The following condensed consolidating financial information is provided for Valero and PRG as an alternative to providing separate financial statements for PRG. The accounts for all companies reflected herein are presented using the equity method of accounting for investments in subsidiaries.

33

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet as of June 30, 2009
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	443		$	–		$	1,180		$	–		$	1,623
Restricted cash		22			2			117			–			141
Receivables, net		–			60			4,157			–			4,217
Inventories		–			447			4,114			–			4,561
Income taxes receivable		5			–			27			(5	)		27
Deferred income taxes		–			–			132			–			132
Prepaid expenses and other		–			6			466			–			472
Total current assets		470			515			10,193			(5	)		11,173
Property, plant and equipment, at cost		–			6,129			23,559			–			29,688
Accumulated depreciation		–			(575	)		(4,829	)		–			(5,404	)
Property, plant and equipment, net		–			5,554			18,730			–			24,284
Intangible assets, net		–			–			221			–			221
Investment in Valero Energy affiliates		6,194			3,052			(296	)		(8,950	)		–
Long-term notes receivable from affiliates		16,659			–			–			(16,659	)		–
Deferred income tax receivable		1,085			–			–			(1,085	)		–
Deferred charges and other assets, net		127			123			1,293			–			1,543
Total assets	$	24,535		$	9,244		$	30,141		$	(26,699	)	$	37,221
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	33		$	–		$	104		$	–		$	137
Accounts payable		31			190			5,619			–			5,840
Accrued expenses		110			33			207			–			350
Taxes other than income taxes		–			18			539			–			557
Income taxes payable		–			–			41			(5	)		36
Deferred income taxes		404			–			–			–			404
Total current liabilities		578			241			6,510			(5	)		7,324
Debt and capital lease obligations, less current portion		6,299			897			35			–			7,231
Long-term notes payable to affiliates		–			7,004			9,655			(16,659	)		–
Deferred income taxes		–			1,207			3,983			(1,085	)		4,105
Other long-term liabilities		1,251			191			712			–			2,154
Stockholders’ equity:
Common stock		7			–			1			(1	)		7
Additional paid-in capital		7,987			1,598			4,367			(5,965	)		7,987
Treasury stock		(6,856	)		–			–			–			(6,856	)
Retained earnings		15,384			(1,884	)		4,767			(2,883	)		15,384
Accumulated other comprehensive income (loss)		(115	)		(10	)		111			(101	)		(115	)
Total stockholders’ equity		16,407			(296	)		9,246			(8,950	)		16,407
Total liabilities and stockholders’ equity	$	24,535		$	9,244		$	30,141		$	(26,699	)	$	37,221

34

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet as of December 31, 2008
(in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	215		$	–		$	725		$	–		$	940
Restricted cash		23			2			106			–			131
Receivables, net		–			36			2,861			–			2,897
Inventories		–			360			4,277			–			4,637
Income taxes receivable		76			–			197			(76	)		197
Deferred income taxes		–			–			98			–			98
Prepaid expenses and other		–			8			542			–			550
Total current assets		314			406			8,806			(76	)		9,450
Property, plant and equipment, at cost		–			6,025			22,078			–			28,103
Accumulated depreciation		–			(483	)		(4,407	)		–			(4,890	)
Property, plant and equipment, net		–			5,542			17,671			–			23,213
Intangible assets, net		–			–			224			–			224
Investment in Valero Energy affiliates		6,300			2,718			65			(9,083	)		–
Long-term notes receivable from affiliates		15,354			–			–			(15,354	)		–
Deferred income tax receivable		883			–			–			(883	)		–
Deferred charges and other assets, net		121			136			1,273			–			1,530
Total assets	$	22,972		$	8,802		$	28,039		$	(25,396	)	$	34,417
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	209		$	–		$	103		$	–		$	312
Accounts payable		43			414			3,989			–			4,446
Accrued expenses		82			34			258			–			374
Taxes other than income taxes		–			23			569			–			592
Income taxes payable		–			6			70			(76	)		–
Deferred income taxes		485			–			–			–			485
Total current liabilities		819			477			4,989			(76	)		6,209
Debt and capital lease obligations, less current portion		5,329			899			36			–			6,264
Long-term notes payable to affiliates		–			5,966			9,388			(15,354	)		–
Deferred income taxes		–			1,200			3,846			(883	)		4,163
Other long-term liabilities		1,204			195			762			–			2,161
Stockholders’ equity:
Common stock		6			–			1			(1	)		6
Additional paid-in capital		7,190			1,598			4,349			(5,947	)		7,190
Treasury stock		(6,884	)		–			–			–			(6,884	)
Retained earnings		15,484			(1,523	)		4,507			(2,984	)		15,484
Accumulated other comprehensive income (loss)		(176	)		(10	)		161			(151	)		(176	)
Total stockholders’ equity		15,620			65			9,018			(9,083	)		15,620
Total liabilities and stockholders’ equity	$	22,972		$	8,802		$	28,039		$	(25,396	)	$	34,417

35

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income for the Three Months Ended June 30, 2009
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	3,457		$	17,766		$	(3,298	)	$	17,925
Costs and expenses:
Cost of sales		–			3,726			16,115			(3,298	)		16,543
Operating expenses		–			246			769			–			1,015
Retail selling expenses		–			–			171			–			171
General and administrative expenses		3			1			120			–			124
Depreciation and amortization expense		–			59			330			–			389
Total costs and expenses		3			4,032			17,505			(3,298	)		18,242
Operating income (loss)		(3	)		(575	)		261			–			(317	)
Equity in earnings (losses) of subsidiaries		(326	)		214			(255	)		367			–
Other income (expense), net		289			(28	)		152			(437	)		(24	)
Interest and debt expense:
Incurred		(162	)		(127	)		(266	)		437			(118	)
Capitalized		–			7			29			–			36
Loss before income tax expense (benefit)		(202	)		(509	)		(79	)		367			(423	)
Income tax expense (benefit) (1)		52			(254	)		33			–			(169	)
Net loss	$	(254	)	$	(255	)	$	(112	)	$	367		$	(254	)

(1) The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.

36

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income for the Three Months Ended June 30, 2008
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	8,065		$	36,073		$	(7,498	)	$	36,640
Costs and expenses:
Cost of sales		–			7,849			33,322			(7,498	)		33,673
Operating expenses		–			207			926			–			1,133
Retail selling expenses		–			–			190			–			190
General and administrative expenses		(2	)		1			118			–			117
Depreciation and amortization expense		–			60			309			–			369
Total costs and expenses		(2	)		8,117			34,865			(7,498	)		35,482
Operating income (loss)		2			(52	)		1,208			–			1,158
Equity in earnings of subsidiaries		651			137			29			(817	)		–
Other income (expense), net		281			(18	)		190			(438	)		15
Interest and debt expense:
Incurred		(135	)		(132	)		(278	)		438			(107	)
Capitalized		–			5			19			–			24
Income (loss) before income tax expense (benefit)		799			(60	)		1,168			(817	)		1,090
Income tax expense (benefit) (1)		65			(89	)		380			–			356
Net income	$	734		$	29		$	788		$	(817	)	$	734

(1) The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings of subsidiaries.

37

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income for the Six Months Ended June 30, 2009
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	6,191		$	31,470		$	(5,912	)	$	31,749
Costs and expenses:
Cost of sales		–			6,432			27,651			(5,912	)		28,171
Operating expenses		–			485			1,527			–			2,012
Retail selling expenses		–			–			340			–			340
General and administrative expenses		1			2			266			–			269
Depreciation and amortization expense		–			123			644			–			767
Total costs and expenses		1			7,042			30,428			(5,912	)		31,559
Operating income (loss)		(1	)		(851	)		1,042			–			190
Equity in earnings (losses) of subsidiaries		(78	)		334			(360	)		104			–
Other income (expense), net		544			(42	)		313			(840	)		(25	)
Interest and debt expense:
Incurred		(305	)		(242	)		(530	)		840			(237	)
Capitalized		–			14			62			–			76
Income (loss) before income tax expense (benefit)		160			(787	)		527			104			4
Income tax expense (benefit) (1)		105			(427	)		271			–			(51	)
Net income (loss)	$	55		$	(360	)	$	256		$	104		$	55

(1) The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.

38

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income for the Six Months Ended June 30, 2008
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	15,739		$	63,678		$	(14,832	)	$	64,585
Costs and expenses:
Cost of sales		–			15,268			58,906			(14,832	)		59,342
Operating expenses		–			441			1,806			–			2,247
Retail selling expenses		–			–			378			–			378
General and administrative expenses		(3	)		14			241			–			252
Depreciation and amortization expense		–			138			598			–			736
Total costs and expenses		(3	)		15,861			61,929			(14,832	)		62,955
Operating income (loss)		3			(122	)		1,749			–			1,630
Equity in earnings (losses) of subsidiaries		787			176			(92	)		(871	)		–
Other income (expense), net		573			(26	)		382			(894	)		35
Interest and debt expense:
Incurred		(272	)		(280	)		(565	)		894			(223	)
Capitalized		–			9			34			–			43
Income (loss) before income tax expense (benefit)		1,091			(243	)		1,508			(871	)		1,485
Income tax expense (benefit) (1)		96			(151	)		545			–			490
Net income (loss)	$	995		$	(92	)	$	963		$	(871	)	$	995

(1) The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.

39

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2009
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(8	)	$	(819	)	$	2,234		$	–		$	1,407
Cash flows from investing activities:
Capital expenditures		–			(197	)		(1,154	)		–			(1,351	)
Deferred turnaround and catalyst costs		–			(20	)		(229	)		–			(249	)
Acquisition of certain VeraSun Energy Corporation facilities		–			–			(556	)		–			(556	)
Return of investment in Cameron Highway Oil Pipeline Company		–			–			8			–			8
Minor acquisitions		–			–			(29	)		–			(29	)
Net intercompany loans		(1,194	)		–			–			1,194			–
Other investing activities, net		–			–			3			–			3
Net cash used in investing activities		(1,194	)		(217	)		(1,957	)		1,194			(2,174	)
Cash flows from financing activities:
Proceeds from the sale of common stock, net of issuance costs		799			–			–			–			799
Non-bank debt:
Borrowings		998			–			–			–			998
Repayments		(209	)		–			–			–			(209	)
Accounts receivable sales program:
Proceeds from sale of receivables		–			–			500			–			500
Repayments		–			–			(500	)		–			(500	)
Common stock dividends		(155	)		–			–			–			(155	)
Net intercompany borrowings		–			1,036			158			(1,194	)		–
Other financing activities, net		(3	)		–			(2	)		–			(5	)
Net cash provided by financing activities		1,430			1,036			156			(1,194	)		1,428
Effect of foreign exchange rate changes on cash		–			–			22			–			22
Net increase in cash and temporary cash investments		228			–			455			–			683
Cash and temporary cash investments at beginning of period		215			–			725			–			940
Cash and temporary cash investments at end of period	$	443		$	–		$	1,180		$	–		$	1,623

40

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2008
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG (1)			Subsidiaries (1)			Eliminations			Consolidated
Net cash provided by operating activities	$	274		$	65		$	1,463		$	–		$	1,802
Cash flows from investing activities:
Capital expenditures		–			(247	)		(931	)		–			(1,178	)
Deferred turnaround and catalyst costs		–			(50	)		(153	)		–			(203	)
Return of investment in Cameron Highway Oil Pipeline Company		–			–			12			–			12
Advance proceeds related to sale of assets		–			–			17			–			17
Contingent payment in connection with acquisition		–			–			(25	)		–			(25	)
Investments in subsidiaries		(215	)		–			–			215			–
Net intercompany loans		210			–			–			(210	)		–
Minor acquisition		–			–			(57	)		–			(57	)
Other investing activities, net		–			–			14			–			14
Net cash used in investing activities		(5	)		(297	)		(1,123	)		5			(1,420	)
Cash flows from financing activities:
Non-bank debt repayments		(6	)		(368	)		–			–			(374	)
Bank credit agreements:
Borrowings		296			–			–			–			296
Repayments		(296	)		–			–			–			(296	)
Purchase of common stock for treasury		(700	)		–			–			–			(700	)
Common stock dividends		(143	)		–			–			–			(143	)
Net intercompany borrowings (repayments)		–			600			(810	)		210			–
Capital contributions from parent		–			–			215			(215	)		–
Other financing activities		24			–			(2	)		–			22
Net cash provided by (used in) financing activities		(825	)		232			(597	)		(5	)		(1,195	)
Effect of foreign exchange rate changes on cash		–			–			(7	)		–			(7	)
Net decrease in cash and temporary cash investments		(556	)		–			(264	)		–			(820	)
Cash and temporary cash investments at beginning of period		1,414			–			1,050			–			2,464
Cash and temporary cash investments at end of period	$	858		$	–		$	786		$	–		$	1,644

(1) The information presented herein excludes a $918 million noncash capital contribution of property and other assets, net of certain liabilities, from PRG to Valero Refining Company–Tennessee, L.L.C. (included in “Other Non-Guarantor Subsidiaries”) on April 1, 2008.

41

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 “Results of Operations – Outlook,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “believe,” “expect,” “plan,” “intend,” “estimate,” “project,” “projection,” “predict,” “budget,” “forecast,” “goal,” “guidance,” “target,” “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 and the effect of the acquisition from VeraSun Energy Corporation (VeraSun) of certain ethanol plants (the VeraSun Acquisition) on our results of operations;

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

• anticipated levels of crude oil and refined product inventories;

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

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

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

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

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

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

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

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

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

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

• the level of consumer demand, including seasonal fluctuations;

• refinery overcapacity or undercapacity;

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

42

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

• the level of foreign imports of refined products;

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

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

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

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

• ethanol margins following the VeraSun Acquisition may be lower than expected;

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

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

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

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

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

• overall economic conditions, 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 the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

43

OVERVIEW

In this overview, we describe some of the primary factors that we believe affected our results of operations in the second quarter and first six months of 2009. We reported a net loss of $254 million, or $0.48 per share, for the second quarter of 2009, compared to net income of $734 million, or $1.37 per share, for the second quarter of 2008. Net income was $55 million, or $0.11 per share, for the first six months of 2009, compared to $995 million, or $1.85 per share, for the first six months of 2008. The results of operations for the first six months of 2008 included a pre-tax benefit of approximately $100 million for a business interruption insurance settlement related to a 2007 fire at our McKee Refinery.

Our profitability is substantially determined by the spread between the price of refined products and the price of crude oil, referred to as the “refined product margin.” The current economic recession has caused a decline in demand for refined products, which put pressure on refined product margins during the second quarter and first six months of 2009. This reduced demand, combined with increased inventory levels attributable in large part to new worldwide refining capacity coming online, caused a significant decline in diesel and jet fuel margins in the second quarter and first six months of 2009 compared to the corresponding periods of 2008. However, margins on other refined products were favorable in 2009 compared to 2008. Gasoline margins were strong and improved significantly in the second quarter and first six months of 2009 compared to the same periods of 2008 due to a better balance of supply and demand. In addition, lower costs of crude oil and other feedstocks significantly improved margins on certain secondary products, such as asphalt, fuel oils, and petroleum coke, during the second quarter and first six months of 2009.

Because more than 65% of our total crude oil throughput generally consists of sour crude oil and acidic sweet crude oil feedstocks that historically have been purchased at prices less than sweet crude oil, our profitability is also significantly affected by the spread between sweet crude oil and sour crude oil prices, referred to as the “sour crude oil differential.” Sour crude oil differentials for the second quarter and first six months of 2009 decreased significantly and were substantially lower than the 2008 differentials for the corresponding periods. We believe that this decline in sour crude oil differentials was partially caused by a reduction in sour crude oil production by OPEC and other producers, which reduced the supply of sour crude oil and increased the price of sour crude oils relative to sweet crude oils.

In March 2009, we issued $750 million of 10-year notes and $250 million of 30-year notes. Proceeds from these notes have been used to make $209 million of scheduled debt payments in April 2009, fund our acquisition of certain ethanol plants from VeraSun, and maintain our capital investment program.

In April and May of 2009, we acquired seven ethanol plants and a site under development from VeraSun for $477 million, plus $79 million primarily for inventory and certain other working capital. The new ethanol business reported $22 million of operating income in the second quarter of 2009, which represented only a partial quarter of operations for several of these plants.

In June 2009, we sold in a public offering 46 million shares of our common stock at a price of $18.00 per share and received proceeds, net of underwriting discounts and commissions and other issuance costs, of $799 million.

44

RESULTS OF OPERATIONS

Second Quarter 2009 Compared to Second Quarter 2008

Financial Highlights
(millions of dollars, except per share amounts)

	Three Months Ended June 30,
	2009 (a)			2008 (b)			Change
Operating revenues	$	17,925		$	36,640		$	(18,715	)
Costs and expenses:
Cost of sales		16,543			33,673			(17,130	)
Operating expenses		1,015			1,133			(118	)
Retail selling expenses		171			190			(19	)
General and administrative expenses		124			117			7
Depreciation and amortization expense:
Refining		346			336			10
Retail		26			24			2
Ethanol		5			–			5
Corporate		12			9			3
Total costs and expenses		18,242			35,482			(17,240	)
Operating income (loss)		(317	)		1,158			(1,475	)
Other income (expense), net		(24	)		15			(39	)
Interest and debt expense:
Incurred		(118	)		(107	)		(11	)
Capitalized		36			24			12
Income (loss) before income tax expense (benefit)		(423	)		1,090			(1,513	)
Income tax expense (benefit)		(169	)		356			(525	)
Net income (loss)	$	(254	)	$	734		$	(988	)
Earnings (loss) per common share – assuming dilution	$	(0.48	)	$	1.37		$	(1.85	)

See the footnote references on page 49.

45

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

	Three Months Ended June 30,
	2009			2008			Change
Refining (b):
Operating income (loss)	$	(268	)	$	1,235		$	(1,503	)
Throughput margin per barrel (c)	$	4.64		$	10.82		$	(6.18	)
Operating costs per barrel:
Refining operating expenses	$	4.30		$	4.53		$	(0.23	)
Depreciation and amortization		1.53			1.35			0.18
Total operating costs per barrel	$	5.83		$	5.88		$	(0.05	)
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		451			593			(142	)
Medium/light sour crude		582			715			(133	)
Acidic sweet crude		104			80			24
Sweet crude		616			658			(42	)
Residuals		248			253			(5	)
Other feedstocks		186			128			58
Total feedstocks		2,187			2,427			(240	)
Blendstocks and other		302			319			(17	)
Total throughput volumes		2,489			2,746			(257	)
Yields (thousand barrels per day):
Gasolines and blendstocks		1,196			1,232			(36	)
Distillates		793			982			(189	)
Petrochemicals		70			77			(7	)
Other products (d)		426			446			(20	)
Total yields		2,485			2,737			(252	)
Retail – U.S.:
Operating income	$	36		$	25		$	11
Company-operated fuel sites (average)		1,001			949			52
Fuel volumes (gallons per day per site)		5,119			5,104			15
Fuel margin per gallon	$	0.125		$	0.129		$	(0.004	)
Merchandise sales	$	307		$	282		$	25
Merchandise margin (percentage of sales)		28.6	%		29.8	%		(1.2	)%
Margin on miscellaneous sales	$	21		$	22		$	(1	)
Retail selling expenses	$	115		$	121		$	(6	)
Depreciation and amortization expense	$	18		$	16		$	2
Retail – Canada:
Operating income	$	29		$	24		$	5
Fuel volumes (thousand gallons per day)		3,093			3,103			(10	)
Fuel margin per gallon	$	0.253		$	0.270		$	(0.017	)
Merchandise sales	$	49		$	54		$	(5	)
Merchandise margin (percentage of sales)		29.2	%		28.6	%		0.6	%
Margin on miscellaneous sales	$	7		$	10		$	(3	)
Retail selling expenses	$	56		$	69		$	(13	)
Depreciation and amortization expense	$	8		$	8		$	–

See the footnote references on page 49.

46

Operating Highlights (continued)
(millions of dollars, except per gallon amounts)

	Three Months Ended June 30,
	2009		2008		Change
Ethanol (a):
Operating income	$	22		N/A	$	22
Ethanol production (thousand gallons per day)		1,547		N/A		1,547
Gross margin per gallon of ethanol production	$	0.49		N/A	$	0.49
Operating costs per gallon of ethanol production:
Ethanol operating expenses	$	0.30		N/A	$	0.30
Depreciation and amortization		0.03		N/A		0.03
Total operating costs per gallon of ethanol production	$	0.33		N/A	$	0.33

See the footnote references on page 49.

47

Refining Operating Highlights by Region (e)
(millions of dollars, except per barrel amounts)

	Three Months Ended June 30,
	2009			2008			Change
Gulf Coast (b):
Operating income (loss)	$	(176	)	$	1,043		$	(1,219	)
Throughput volumes (thousand barrels per day)		1,395			1,495			(100	)
Throughput margin per barrel (c)	$	3.94		$	13.25		$	(9.31	)
Operating costs per barrel:
Refining operating expenses	$	3.92		$	4.34		$	(0.42	)
Depreciation and amortization		1.41			1.24			0.17
Total operating costs per barrel	$	5.33		$	5.58		$	(0.25	)
Mid-Continent:
Operating income	$	18		$	103		$	(85	)
Throughput volumes (thousand barrels per day)		370			439			(69	)
Throughput margin per barrel (c)	$	6.03		$	7.85		$	(1.82	)
Operating costs per barrel:
Refining operating expenses	$	3.76		$	3.99		$	(0.23	)
Depreciation and amortization		1.72			1.27			0.45
Total operating costs per barrel	$	5.48		$	5.26		$	0.22
Northeast:
Operating loss	$	(169	)	$	(35	)	$	(134	)
Throughput volumes (thousand barrels per day)		440			527			(87	)
Throughput margin per barrel (c)	$	2.88		$	5.81		$	(2.93	)
Operating costs per barrel:
Refining operating expenses	$	5.39		$	5.06		$	0.33
Depreciation and amortization		1.71			1.49			0.22
Total operating costs per barrel	$	7.10		$	6.55		$	0.55
West Coast:
Operating income	$	59		$	124		$	(65	)
Throughput volumes (thousand barrels per day)		284			285			(1	)
Throughput margin per barrel (c)	$	9.03		$	11.92		$	(2.89	)
Operating costs per barrel:
Refining operating expenses	$	5.15		$	5.41		$	(0.26	)
Depreciation and amortization		1.61			1.73			(0.12	)
Total operating costs per barrel	$	6.76		$	7.14		$	(0.38	)

See the footnote references on page 49.

48

Average Market Reference Prices and Differentials (f)
(dollars per barrel)

	Three Months Ended June 30,
	2009			2008			Change
Feedstocks:
West Texas Intermediate (WTI) crude oil	$	59.54		$	123.98		$	(64.44	)
WTI less sour crude oil at U.S. Gulf Coast (g)		0.33			5.70			(5.37	)
WTI less Mars crude oil		2.19			6.96			(4.77	)
WTI less Maya crude oil		4.57			20.99			(16.42	)
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		10.57			6.60			3.97
No. 2 fuel oil less WTI		3.84			23.03			(19.19	)
Ultra-low-sulfur diesel less WTI		6.16			28.85			(22.69	)
Propylene less WTI		(10.89	)		(6.77	)		(4.12	)
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		10.58			5.89			4.69
Low-sulfur diesel less WTI		6.24			28.84			(22.60	)
U.S. Northeast:
Conventional 87 gasoline less WTI		9.85			4.34			5.51
No. 2 fuel oil less WTI		4.69			24.94			(20.25	)
Lube oils less WTI		25.64			33.65			(8.01	)
U.S. West Coast:
CARBOB 87 gasoline less WTI		18.07			16.08			1.99
CARB diesel less WTI		7.92			30.83			(22.91	)

The following notes relate to references on pages 45 through 49.

(a) The information presented for the three months ended June 30, 2009 includes the operations related to the acquisition of certain ethanol plants from VeraSun. Ethanol plants located in Charles City, Fort Dodge, and Hartley, Iowa; Aurora, South Dakota; and Welcome, Minnesota were purchased on April 1, 2009, and ethanol plants in Albert City, Iowa and Albion, Nebraska were purchased on April 9, 2009 and May 8, 2009, respectively. The ethanol production volumes reflected for the three months ended June 30, 2009 are based on 91 calendar days rather than the actual daily production, which varied by facility.

(b) Effective July 1, 2008, we sold our Krotz Springs Refinery to Alon Refining Krotz Springs, Inc. (Alon), a subsidiary of Alon USA Energy, Inc. The nature and significance of our post-closing participation in an offtake agreement with Alon represents a continuation of activities with the Krotz Springs Refinery for accounting purposes, and as such the results of operations related to the Krotz Springs Refinery have not been presented as discontinued operations, and all refining operating highlights, both consolidated and for the Gulf Coast region, include the Krotz Springs Refinery for the three months ended June 30, 2008.

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

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

(e) The regions reflected herein contain the following refineries: the Gulf Coast refining region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, Krotz Springs (for the three months ended June 30, 2008), St. Charles, Aruba, and Port Arthur Refineries; the Mid-Continent refining region includes the McKee, Ardmore, and Memphis Refineries; the Northeast refining region includes the Quebec City, Paulsboro, and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.

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

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

49

General

Operating revenues decreased 51% for the second quarter of 2009 compared to the second quarter of 2008 primarily as a result of lower refined product prices between the two periods. Operating income declined $1.5 billion and net income decreased $1.0 billion for the three months ended June 30, 2009 compared to amounts reported for the three months ended June 30, 2008 primarily due to a $1.5 billion decrease in refining segment operating income discussed below.

Refining

Results of operations of our refining segment decreased from operating income of $1.2 billion for the second quarter of 2008 to an operating loss of $268 million for the second quarter of 2009, resulting from a 57% decrease in throughput margin per barrel and a 9% decline in throughput volumes, partially offset by a 10% decrease in refining operating expenses (including depreciation and amortization expense).

Total refining throughput margins for the second quarter of 2009 compared to the second quarter of 2008 were impacted by the following factors:

• Distillate margins in the second quarter of 2009 decreased significantly in all of our refining regions from the high margins in the second quarter of 2008. The decrease in distillate margins was primarily due to reduced demand attributable to the global slowdown in economic activity, combined with an increase in inventory levels resulting largely from new worldwide refining capacity.

• Sour crude oil feedstock differentials to WTI crude oil during the second quarter of 2009 declined significantly compared to the differentials in the second quarter of 2008. These unfavorable sour crude oil differentials were attributable mainly to reduced production of sour crude oil by OPEC and other producers. The sour crude oil differentials were also affected by high relative prices for residual fuel oil as reduced worldwide demand for residual fuel oil was more than offset by lower production resulting from reduced refinery throughput due to lower refined product demand.

• Gasoline margins were strong in all of our refining regions in the second quarter of 2009, and improved significantly from the second quarter of 2008. The improvement in gasoline margins for the second quarter of 2009 was primarily due to a better balance of supply and demand. Although demand for gasoline decreased slightly during the period, lower production and lower imports resulted in inventories similar to historical levels.

• Margins on various secondary refined products such as asphalt, fuel oils, and petroleum coke improved significantly from the second quarter of 2008 to the second quarter of 2009 as prices for these products did not decrease in proportion to the large decrease in the costs of the feedstocks used to produce them.

• Throughput volumes decreased 257,000 barrels per day during the second quarter of 2009 compared to the second quarter of 2008 primarily due to (i) unplanned downtime at our Delaware City and St. Charles Refineries, (ii) the sale of our Krotz Springs Refinery in July 2008, and (iii) economic decisions to reduce throughput in certain of our refineries as a result of unfavorable market fundamentals.

Refining operating expenses, excluding depreciation and amortization expense, were 14% lower for the quarter ended June 30, 2009 compared to the quarter ended June 30, 2008 primarily due to a significant decrease in energy costs, a reduction in sales and use taxes, and $20 million of operating expenses in the second quarter of 2008 related to the Krotz Springs Refinery, which was sold effective July 1, 2008, partially offset by expenses related to the cancellation of certain capital projects. Refining depreciation and amortization expense increased 3% from the second quarter of 2008 to the second quarter of 2009 primarily due to the completion of new capital projects.

50

Retail

Retail operating income was $65 million for the quarter ended June 30, 2009 compared to $49 million for the quarter ended June 30, 2008. This 33% increase was primarily due to increased in-store sales and lower selling expenses in our U.S. retail operations.

Ethanol

Ethanol operating income was $22 million for the quarter ended June 30, 2009, which represents the operations of the seven ethanol plants acquired in the VeraSun Acquisition, as described in Note 3 of Condensed Notes to Consolidated Financial Statements.

Corporate Expenses and Other

General and administrative expenses, including depreciation and amortization expense, increased $10 million from the second quarter of 2008 to the second quarter of 2009 primarily due to costs associated with the VeraSun Acquisition.

“Other income (expense), net” for the second quarter of 2009 decreased from the second quarter of 2008 due mainly to a $34 million net loss resulting from fair value adjustments related to the Alon earn-out agreement and associated derivative instruments in 2009, as discussed in Notes 9 and 10 of Condensed Notes to Consolidated Financial Statements.

Income tax expense decreased $525 million from $356 million of expense in the second quarter of 2008 to a $169 million benefit in the second quarter of 2009 mainly as a result of lower operating income.

51

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Financial Highlights
(millions of dollars, except per share amounts)

	Six Months Ended June 30,
	2009 (a)			2008 (b)			Change
Operating revenues	$	31,749		$	64,585		$	(32,836	)
Costs and expenses:
Cost of sales		28,171			59,342			(31,171	)
Operating expenses		2,012			2,247			(235	)
Retail selling expenses		340			378			(38	)
General and administrative expenses		269			252			17
Depreciation and amortization expense:
Refining		690			667			23
Retail		49			49			–
Ethanol		5			–			5
Corporate		23			20			3
Total costs and expenses		31,559			62,955			(31,396	)
Operating income		190			1,630			(1,440	)
Other income (expense), net		(25	)		35			(60	)
Interest and debt expense:
Incurred		(237	)		(223	)		(14	)
Capitalized		76			43			33
Income before income tax expense (benefit)		4			1,485			(1,481	)
Income tax expense (benefit)		(51	)		490			(541	)
Net income	$	55		$	995		$	(940	)
Earnings per common share – assuming dilution	$	0.11		$	1.85		$	(1.74	)

See the footnote references on page 56.

52

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

	Six Months Ended June 30,
	2009			2008			Change
Refining (b):
Operating income	$	339		$	1,803		$	(1,464	)
Throughput margin per barrel (c)	$	6.69		$	9.68		$	(2.99	)
Operating costs per barrel:
Refining operating expenses	$	4.39		$	4.61		$	(0.22	)
Depreciation and amortization		1.54			1.37			0.17
Total operating costs per barrel	$	5.93		$	5.98		$	(0.05	)
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		511			587			(76	)
Medium/light sour crude		601			685			(84	)
Acidic sweet crude		108			77			31
Sweet crude		589			643			(54	)
Residuals		184			223			(39	)
Other feedstocks		178			144			34
Total feedstocks		2,171			2,359			(188	)
Blendstocks and other		307			318			(11	)
Total throughput volumes		2,478			2,677			(199	)
Yields (thousand barrels per day):
Gasolines and blendstocks		1,160			1,228			(68	)
Distillates		812			927			(115	)
Petrochemicals		65			77			(12	)
Other products (d)		434			442			(8	)
Total yields		2,471			2,674			(203	)
Retail – U.S.:
Operating income	$	61		$	39		$	22
Company-operated fuel sites (average)		1,003			949			54
Fuel volumes (gallons per day per site)		5,052			5,023			29
Fuel margin per gallon	$	0.121		$	0.121		$	–
Merchandise sales	$	573		$	527		$	46
Merchandise margin (percentage of sales)		29.5	%		30.1	%		(0.6	)%
Margin on miscellaneous sales	$	44		$	50		$	(6	)
Retail selling expenses	$	229		$	241		$	(12	)
Depreciation and amortization expense	$	35		$	33		$	2
Retail – Canada:
Operating income	$	60		$	60		$	–
Fuel volumes (thousand gallons per day)		3,176			3,191			(15	)
Fuel margin per gallon	$	0.252		$	0.286		$	(0.034	)
Merchandise sales	$	88		$	100		$	(12	)
Merchandise margin (percentage of sales)		29.5	%		28.5	%		1.0	%
Margin on miscellaneous sales	$	15		$	19		$	(4	)
Retail selling expenses	$	111		$	137		$	(26	)
Depreciation and amortization expense	$	14		$	16		$	(2	)

See the footnote references on page 56.

53

Operating Highlights (continued)
(millions of dollars, except per gallon amounts)

	Six Months Ended June 30,
	2009		2008		Change
Ethanol (a):
Operating income	$	22		N/A	$	22
Ethanol production (thousand gallons per day)		778		N/A		778
Gross margin per gallon of ethanol production	$	0.49		N/A	$	0.49
Operating costs per gallon of ethanol production:
Ethanol operating expenses	$	0.30		N/A	$	0.30
Depreciation and amortization		0.03		N/A		0.03
Total operating costs per gallon of ethanol production	$	0.33		N/A	$	0.33

See the footnote references on page 56.

54

Refining Operating Highlights by Region (e)
(millions of dollars, except per barrel amounts)

	Six Months Ended June 30,
	2009			2008			Change
Gulf Coast (b):
Operating income (loss)	$	(7	)	$	1,480		$	(1,487	)
Throughput volumes (thousand barrels per day)		1,355			1,437			(82	)
Throughput margin per barrel (c)	$	5.48		$	11.46		$	(5.98	)
Operating costs per barrel:
Refining operating expenses	$	4.05		$	4.52		$	(0.47	)
Depreciation and amortization		1.46			1.28			0.18
Total operating costs per barrel	$	5.51		$	5.80		$	(0.29	)
Mid-Continent:
Operating income	$	190		$	218		$	(28	)
Throughput volumes (thousand barrels per day)		385			426			(41	)
Throughput margin per barrel (c)	$	8.07		$	8.28		$	(0.21	)
Operating costs per barrel:
Refining operating expenses	$	3.75		$	4.16		$	(0.41	)
Depreciation and amortization		1.59			1.30			0.29
Total operating costs per barrel	$	5.34		$	5.46		$	(0.12	)
Northeast:
Operating loss	$	(88	)	$	(30	)	$	(58	)
Throughput volumes (thousand barrels per day)		458			541			(83	)
Throughput margin per barrel (c)	$	6.06		$	5.91		$	0.15
Operating costs per barrel:
Refining operating expenses	$	5.48		$	4.77		$	0.71
Depreciation and amortization		1.64			1.45			0.19
Total operating costs per barrel	$	7.12		$	6.22		$	0.90
West Coast:
Operating income	$	244		$	135		$	109
Throughput volumes (thousand barrels per day)		280			273			7
Throughput margin per barrel (c)	$	11.66		$	9.99		$	1.67
Operating costs per barrel:
Refining operating expenses	$	5.12		$	5.48		$	(0.36	)
Depreciation and amortization		1.73			1.80			(0.07	)
Total operating costs per barrel	$	6.85		$	7.28		$	(0.43	)

See the footnote references on page 56.

55

Average Market Reference Prices and Differentials (f)
(dollars per barrel)

	Six Months Ended June 30,
	2009			2008			Change
Feedstocks:
WTI crude oil	$	51.26		$	110.96		$	(59.70	)
WTI less sour crude oil at U.S. Gulf Coast (g)		1.02			5.77			(4.75	)
WTI less Mars crude oil		0.70			6.97			(6.27	)
WTI less Maya crude oil		4.51			18.90			(14.39	)
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		9.36			5.42			3.94
No. 2 fuel oil less WTI		7.34			19.11			(11.77	)
Ultra-low-sulfur diesel less WTI		9.38			24.61			(15.23	)
Propylene less WTI		(8.69	)		(3.77	)		(4.92	)
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		9.58			5.43			4.15
Low-sulfur diesel less WTI		8.94			24.88			(15.94	)
U.S. Northeast:
Conventional 87 gasoline less WTI		8.99			3.70			5.29
No. 2 fuel oil less WTI		9.06			21.35			(12.29	)
Lube oils less WTI		46.37			32.97			13.40
U.S. West Coast:
CARBOB 87 gasoline less WTI		18.60			12.56			6.04
CARB diesel less WTI		10.81			25.39			(14.58	)

The following notes relate to references on pages 52 through 56.
(a)	The information presented for the six months ended June 30, 2009 includes the operations related to the acquisition of certain ethanol plants from VeraSun. Ethanol plants located in Charles City, Fort Dodge, and Hartley, Iowa; Aurora, South Dakota; and Welcome, Minnesota were purchased on April 1, 2009, and ethanol plants in Albert City, Iowa and Albion, Nebraska were purchased on April 9, 2009 and May 8, 2009, respectively. The ethanol production volumes reflected for the six months ended June 30, 2009 are based on 181 calendar days rather than the actual daily production, which varied by facility.
(b)	Effective July 1, 2008, we sold our Krotz Springs Refinery to Alon. The nature and significance of our post-closing participation in an offtake agreement with Alon represents a continuation of activities with the Krotz Springs Refinery for accounting purposes, and as such the results of operations related to the Krotz Springs Refinery have not been presented as discontinued operations, and all refining operating highlights, both consolidated and for the Gulf Coast region, include the Krotz Springs Refinery for the six months ended June 30, 2008.
(c)	Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.
(d)	Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
(e)	The regions reflected herein contain the following refineries: the Gulf Coast refining region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, Krotz Springs (for the six months ended June 30, 2008), St. Charles, Aruba, and Port Arthur Refineries; the Mid-Continent refining region includes the McKee, Ardmore, and Memphis Refineries; the Northeast refining region includes the Quebec City, Paulsboro, and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.
(f)	The average market reference prices and differentials, with the exception of the propylene and lube oil differentials, are based on posted prices from Platts Oilgram. The propylene differential is based on posted propylene prices in Chemical Market Associates, Inc. and the lube oil differential is based on Exxon Mobil Corporation postings provided by Independent Commodity Information Services – London Oil Reports. The average market reference prices and differentials are presented to provide users of the consolidated financial statements with economic indicators that significantly affect our operations and profitability.
(g)	The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.

56

General

Operating revenues decreased 51% for the first six months of 2009 compared to the first six months of 2008 primarily as a result of lower refined product prices between the two periods. Operating income of $190 million and net income of $55 million for the six months ended June 30, 2009 decreased 88% and 94%, respectively, from the corresponding amounts in the first six months of 2008 primarily due to a $1.5 billion decrease in refining segment operating income discussed below.

Refining

Operating income for our refining segment decreased from $1.8 billion for the first six months of 2008 to $339 million for the first six months of 2009, resulting from a 31% decrease in throughput margin per barrel and a 7% decline in throughput volumes, partially offset by a 9% decrease in refining operating expenses (including depreciation and amortization expense).

Total refining throughput margins for the first six months of 2009 compared to the first six months of 2008 were impacted by the following factors:

• Distillate margins in the first six months of 2009 decreased significantly in all of our refining regions from the high margins in the first six months of 2008. The decrease in distillate margins was primarily due to increased inventory levels and reduced demand attributable to the global slowdown in economic activity.

• Sour crude oil feedstock differentials to WTI crude oil during the first six months of 2009 declined significantly compared to the differentials in the first six months of 2008. These unfavorable sour crude oil differentials were attributable mainly to reduced production of sour crude oil by OPEC and other producers. The sour crude oil differentials were also affected by high relative prices for residual fuel oil as reduced worldwide demand for residual fuel oil was more than offset by lower production resulting from reduced refinery throughput due to lower refined product demand.

• Gasoline margins increased in all of our refining regions in the first six months of 2009 compared to the first six months of 2008. The improvement in gasoline margins for the first six months of 2009 was primarily due to a better balance of supply and demand. Although demand for gasoline decreased slightly during the period, lower production and lower imports resulted in inventories similar to historical levels.

• Margins on various secondary refined products such as asphalt, fuel oils, and petroleum coke improved significantly from the first six months of 2008 to the first six months of 2009 as prices for these products did not decrease in proportion to the large decrease in the costs of the feedstocks used to produce them.

• Throughput margin for the first six months of 2008 included approximately $100 million related to the McKee Refinery business interruption insurance settlement discussed in Note 13 of Condensed Notes to Consolidated Financial Statements.

• Throughput volumes decreased 199,000 barrels per day during the first six months of 2009 compared to the first six months of 2008 primarily due to (i) unplanned downtime at our Delaware City and St. Charles Refineries, (ii) planned downtime for maintenance at our Texas City, St. Charles, and Corpus Christi Refineries, (iii) the sale of our Krotz Springs Refinery in July 2008, and (iv) economic decisions to reduce throughput in certain of our refineries as a result of unfavorable market fundamentals.

Refining operating expenses, excluding depreciation and amortization expense, were 12% lower for the six months ended June 30, 2009 compared to the six months ended June 30, 2008 primarily due to a decrease in energy costs, a reduction in sales and use taxes, and $43 million of operating expenses in the

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first six months of 2008 related to the Krotz Springs Refinery, which was sold effective July 1, 2008, partially offset by expenses related to the cancellation of certain capital projects. Refining depreciation and amortization expense increased 3% from the first six months of 2008 to the first six months of 2009 primarily due to the completion of new capital projects and increased turnaround and catalyst amortization.

Retail

Retail operating income was $121 million for the six months ended June 30, 2009 compared to $99 million for the six months ended June 30, 2008. This 22% increase was primarily due to increased in-store sales and lower selling expenses in our U.S. retail operations.

Ethanol

Ethanol operating income was $22 million for the six months ended June 30, 2009, which represents the operations of the seven ethanol plants acquired in the VeraSun Acquisition subsequent to their acquisition in the second quarter of 2009, as described in Note 3 of Condensed Notes to Consolidated Financial Statements.

Corporate Expenses and Other

General and administrative expenses, including depreciation and amortization expense, increased $20 million from the first six months of 2008 to the first six months of 2009 due mainly to an increase in severance expenses and costs associated with the VeraSun Acquisition.

“Other income (expense), net” for the first six months of 2009 decreased from the first six months of 2008 primarily due to a $38 million net loss resulting from fair value adjustments related to the Alon earn-out agreement and associated derivative instruments in 2009 (as discussed in Notes 9 and 10 of Condensed Notes to Consolidated Financial Statements), reduced interest income resulting from lower cash balances and interest rates, and the nonrecurrence of a $14 million gain recognized in the first six months of 2008 on the redemption of our 9.5% senior notes as discussed in Note 5 of Condensed Notes to Consolidated Financial Statements.

Interest and debt expense decreased from the first six months of 2008 to the first six months of 2009 due mainly to an increase in capitalized interest resulting from a higher balance of capital projects under construction, partially offset by interest incurred on $1 billion of debt issued in March 2009.

Income tax expense decreased $541 million from $490 million of expense for the first six months of 2008 to a $51 million benefit for the first six months of 2009 mainly as a result of lower operating income.

OUTLOOK

The current global economic slowdown and rising unemployment are expected to continue to unfavorably impact demand for refined products in the near term. This reduced demand, combined with an increase in global refined product inventories resulting from new refineries coming online, is expected to continue to put significant pressure on refined product margins. In addition, low demand for refined products is expected to result in a continuing reduction in overall crude oil production by OPEC, which will reduce the supply of sour crude oil and continue to put pressure on the differentials between sour and sweet crude oil prices. Pressure on refined product margins and sour crude oil differentials is expected to continue until the economy begins to recover, at which time demand for refined products and sour crude oil production are expected to increase.

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Until the economy recovers, we expect that the current low refined product margins and sour crude oil differentials will result in production constraints or refinery shutdowns in the refining industry. In July, we temporarily shut down our Aruba Refinery, and in June, we temporarily shut down one of our units at our Corpus Christi East Refinery, both due to poor economics resulting from the current unfavorable industry fundamentals. We are currently monitoring, and will continue to monitor, all of our other refineries to assess whether complete or partial shutdown of certain of those facilities is appropriate until conditions improve. We expect refined product margins and sour crude oil differentials for the third quarter of 2009 to be similar to those in the second quarter, which could result in a loss in the third quarter. In addition, we believe that the fourth quarter of 2009 could continue to be challenging for the refining industry and our company in light of the current economic environment.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Six Months Ended June 30, 2009 and 2008
Net cash provided by operating activities for the six months ended June 30, 2009 was $1.4 billion compared to $1.8 billion for the six months ended June 30, 2008. The decrease in cash generated from operating activities was primarily due to the decrease in operating income discussed above under “Results of Operations,” partially offset by an approximate $800 million favorable change in the amount of income tax payments and refunds between the two periods. Changes in cash provided by or used for working capital during the first six months of 2009 and 2008 are shown in Note 8 of Condensed Notes to Consolidated Financial Statements. Both receivables and accounts payable increased for the first six months of 2009 due mainly to a significant increase in gasoline, distillate, and crude oil prices at June 30, 2009 compared to such prices at the end of 2008.

The net cash generated from operating activities during the first six months of 2009, combined with $998 million of proceeds from the issuance of $1 billion of notes in March 2009 as discussed in Note 5 of Condensed Notes to Consolidated Financial Statements and $799 million of net proceeds from the issuance of 46 million shares of common stock in June 2009 as discussed in Note 6 of Condensed Notes to Consolidated Financial Statements, were used mainly to:

• fund $1.6 billion of capital expenditures and deferred turnaround and catalyst costs;

• fund the VeraSun Acquisition for $556 million;

• make scheduled long-term note repayments of $209 million;

• pay common stock dividends of $155 million;

• fund a $29 million acquisition of two pipelines; and

• increase available cash on hand by $683 million.

The net cash generated from operating activities during the first six months of 2008, combined with $820 million of available cash on hand, were used mainly to:

• fund $1.4 billion of capital expenditures and deferred turnaround and catalyst costs;

• make an early redemption of our 9.5% senior notes for $367 million and scheduled long-term note repayments of $7 million;

• purchase 12.6 million shares of our common stock at a cost of $700 million;

• fund a $25 million contingent earn-out payment in connection with the acquisition of the St. Charles Refinery and a $57 million acquisition primarily of an interest in a refined product pipeline; and

• pay common stock dividends of $143 million.

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Capital Investments
During the six months ended June 30, 2009, we expended $1.4 billion for capital expenditures and $249 million for deferred turnaround and catalyst costs. Capital expenditures for the six months ended June 30, 2009 included $189 million of costs related to environmental projects.

For 2009, we expect to incur approximately $2.5 billion for capital investments, including approximately $2.1 billion for capital expenditures (approximately $500 million of which is for environmental projects) and approximately $440 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes expenditures related to strategic acquisitions. We continuously evaluate our capital budget and make changes as economic conditions warrant.

In the second quarter of 2009, we acquired seven ethanol plants and a site under development from VeraSun for $477 million, plus $79 million primarily for inventory and certain other working capital.

Contractual Obligations
As of June 30, 2009, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities.

On April 1, 2009, we made scheduled debt repayments of $200 million related to our 3.5% notes and $9 million related to our 5.125% Series 1997D industrial revenue bonds.

In March 2009, we issued $750 million of 9.375% notes due March 15, 2019 and $250 million of 10.5% notes due March 15, 2039. Proceeds from the issuance of these notes totaled approximately $998 million, before deducting underwriting discounts and other issuance costs of $8 million.

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. We amended our agreement in June 2009 to extend the maturity date to June 2010. As of December 31, 2008, the amount of eligible receivables sold to the third-party entities and financial institutions was $100 million, which was repaid in February 2009. In March 2009, we sold $100 million of eligible receivables to the third-party entities and financial institutions. In April 2009, we sold an additional $400 million of eligible receivables under this program, which we repaid in June 2009. As of June 30, 2009, the amount of eligible receivables sold to the third-party entities and financial institutions was $100 million. Proceeds from the sale of receivables under this facility are reflected as debt in our consolidated balance sheets.

Under the indenture related to our $100 million of 6.75% senior notes with a maturity date of October 15, 2037, on July 31, 2009, we notified the holders of such notes of our obligation to purchase any of those notes for which a written notice of purchase (purchase notice) is received from the holders prior to September 15, 2009. Any notes for which a purchase notice is received will be purchased at 100% of their principal amount plus accrued and unpaid interest to October 15, 2009, the date of payment of the purchase price.

On May 20, 2009, we entered into a Business Sale Agreement (Agreement) with Dow Chemical Company and certain of its affiliates (Dow) under which we agreed to purchase Dow’s 45% equity interest in Total Raffinaderij Nederland N.V. (TRN), which owns a refinery in the Netherlands, along with related businesses of TRN owned by Dow. The Agreement extends through December 31, 2009 and provides for a purchase price of $600 million plus an amount for related inventories. The closing of the transaction was conditioned upon, among other things, the expiration of a right of first refusal held by Total S.A. (Total) to purchase Dow’s equity interest in TRN or a waiver by Total of such right of first refusal. In June 2009, Total exercised its right of first refusal. To our knowledge, Total’s acquisition of

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Dow’s equity interest in TRN has not closed, and we and Dow have not executed a formal termination of the Agreement.

Other than the TRN Refinery commitment discussed above, during the six months ended June 30, 2009, we had no material changes outside the ordinary course of our business in capital lease obligations, operating leases, purchase obligations, or other long-term liabilities.

Our agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt to below investment grade ratings by Moody’s Investors Service and Standard & Poor’s Ratings Services, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. As of June 30, 2009, 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 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.

Other Commercial Commitments
As of June 30, 2009, our committed lines of credit were as follows:

	Borrowing
	Capacity	Expiration
Letter of credit facility	$300 million	June 2010
Letter of credit facility	$275 million	July 2009 *
Revolving credit facility	$2.5 billion	November 2012
Canadian revolving credit facility	Cdn. $115 million	December 2012

* The $275 million letter of credit facility expired in July 2009.

As of June 30, 2009, we had $247 million of letters of credit outstanding under our uncommitted short-term bank credit facilities and $249 million of letters of credit outstanding under our U.S. committed revolving credit facilities. Under our Canadian committed revolving credit facility, we had Cdn. $19 million of letters of credit outstanding as of June 30, 2009. Our letters of credit expire during 2009 and 2010.

Common Stock Offering
On June 3, 2009, we sold in a public offering 46 million shares of our common stock, which included 6 million shares related to an overallotment option exercised by the underwriters, at a price of $18.00 per share and received proceeds, net of underwriting discounts and commissions and other issuance costs, of $799 million.

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Stock Purchase Programs
As of June 30, 2009, we have approvals under common stock purchase programs previously approved by our board of directors to purchase approximately $3.5 billion of our common stock.

Tax Matters
As discussed in Note 13 of Condensed Notes to Consolidated Financial Statements, we are subject to extensive tax liabilities. 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.

Effective January 1, 2007, the Government of Aruba (GOA) enacted a turnover tax on revenues from the sale of goods produced and services rendered in Aruba. The turnover tax, which is 3% for on-island sales and services and 1% on export sales, is being assessed by the GOA on sales by our Aruba Refinery. However, due to a previous tax holiday that was granted to our Aruba Refinery by the GOA through December 31, 2010 as well as other reasons, we believe that exports by our Aruba Refinery should not be subject to this turnover tax. We commenced arbitration proceedings with the Netherlands Arbitration Institute pursuant to which we are seeking to enforce our rights under the tax holiday and other agreements related to the refinery. The arbitration hearing was held on February 3-4, 2009. We anticipate a decision sometime later this year. We have also filed protests of these assessments through proceedings in Aruba. In April 2008, we entered into an escrow agreement with the GOA and Caribbean Mercantile Bank NV (CMB), pursuant to which we agreed to deposit an amount equal to the disputed turnover tax on exports into an escrow account with CMB, pending resolution of the tax protest proceedings in Aruba. Under this escrow agreement, we are required to continue to deposit an amount equal to the disputed tax on a monthly basis until the tax dispute is resolved through the Aruba proceedings. On April 20, 2009, we were notified that the Aruban tax court overruled our protests with respect to the turnover tax assessed in January and February 2007, totaling $8 million. Under the escrow agreement, we expensed and paid $8 million, plus $1 million of interest, to the GOA in the second quarter of 2009. The tax protests for the remaining periods remain outstanding, and no expense or liability has been recognized in our consolidated financial statements with respect to these remaining periods. Amounts deposited under this escrow agreement, which totaled $111 million and $102 million as of June 30, 2009 and December 31, 2008, respectively, are reflected as “restricted cash” in our consolidated balance sheets.

In addition to the turnover tax described above, the GOA has also asserted other tax amounts aggregating approximately $25 million related to dividends and other tax items. The GOA, through the arbitration, is also now questioning the validity of the tax holiday generally, although the GOA has not issued any formal assessment for profit tax at any time during the tax holiday period. We believe that the provisions of our tax holiday agreement exempt us from all of these taxes and, accordingly, no expense or liability has been recognized in our consolidated financial statements. We are also challenging approximately $30 million in foreign exchange payments made to the Central Bank of Aruba as payments exempted under our tax holiday, as well as other reasons. These taxes and assessments are also being addressed in the arbitration proceedings discussed above.

Asset Impairments
Under FASB Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” long-lived assets must be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the long-lived assets may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized

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in an amount by which its carrying amount exceeds its fair value, with fair value determined under Statement No. 157, generally based on discounted estimated net cash flows.

In order to test long-lived assets for recoverability, management must make estimates of projected cash flows related to the asset being evaluated, which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment.

During the fourth quarter of 2008, there were severe disruptions in the capital and commodities markets that contributed to a significant decline in our common stock price, thus causing our market capitalization to decline to a level substantially below our net book value. Due to these adverse changes in market conditions during the fourth quarter of 2008, we evaluated our significant operating assets for potential impairment as of December 31, 2008, and we determined that the carrying amount of each of these assets was recoverable. The economic slowdown that began in 2008 continued throughout the first six months of 2009, thereby further reducing demand for refined products and putting significant pressure on refined product margins. Due to these economic conditions, in June 2009, we announced our plan to temporarily shut down the Aruba Refinery, which had a net book value of approximately $1.0 billion as of June 30, 2009, for at least two months as narrow heavy sour crude oil differentials currently make the refinery uneconomical to operate. The Aruba Refinery was shut down in July 2009. We are continuing to pursue potential transactions for this refinery, which may include the sale of the refinery. In June 2009, the coker unit at the Corpus Christi East Refinery was also temporarily shut down, partly due to economic reasons. As a result of these factors, we readdressed the potential impairment of all of our significant operating assets as of June 30, 2009, incorporating updated 2009 price assumptions into our estimated cash flows. Based on this analysis, we determined that the carrying amount of each of our significant operating assets continued to be recoverable as of June 30, 2009.

Also in the second quarter of 2009, due to the impact of the continuing economic slowdown on refining industry fundamentals and in an effort to conserve cash, we evaluated all of our capital projects currently in progress. As a result of this assessment, certain capital projects were permanently cancelled, resulting in the write-off of $122 million of project costs in the second quarter of 2009. We have also suspended continued construction activity on various other projects. For example, our two hydrocracker projects on the Gulf Coast, one at the St. Charles Refinery and the other at the Port Arthur Refinery, have been suspended pending a reassessment of the demand for the additional refined product supply that would result from these projects. As of June 30, 2009, approximately $915 million of costs had been incurred on these two projects. In addition, various other projects with a total cost of approximately $430 million as of June 30, 2009 have also been suspended.

Due to the effect of the current unfavorable economic conditions on the refining industry, and our expectations of a continuation of such conditions for the near term, we will continue to monitor both our operating assets and our capital projects for potential asset impairments or project write-offs until conditions improve. Our current evaluations are focused on our Delaware City Refinery, which had a net book value of approximately $2.0 billion as of June 30, 2009. Additional assessments will be performed in conjunction with our annual strategic plan process in the third quarter of 2009. Changes in market conditions, as well as changes in assumptions used to test for recoverability and to determine fair value, could result in significant impairment charges or project write-offs in the future, thus affecting our earnings.

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American Clean Energy and Security Act of 2009

On June 26, 2009, the U.S. House of Representatives narrowly approved the American Clean Energy and Security Act of 2009 (ACESA), also known as the Waxman-Markey Bill. The ACESA, if passed by the U.S. Senate, would establish a national “cap-and-trade” program beginning in 2012 to address greenhouse gas emissions and climate change. The ACESA proposes to reduce carbon dioxide and other greenhouse gas emissions by 3% below 2005 levels by 2012, 20% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050. The cap-and-trade program would require businesses that emit greenhouse gases to acquire emission credits from the government, other businesses, or through an auction process. In addition, refiners would be obligated to purchase emission credits associated with the transportation fuels (gasoline, diesel, and jet fuel) sold and consumed in the United States. As a result of such a program, we could be required to purchase emission credits for greenhouse gas emissions resulting from our operations and from the fuels we sell. Although it is not possible at this time to predict the final form of the ACESA (or whether it will be passed by the U.S. Senate), any new federal restrictions on greenhouse gas emissions – including a cap-and-trade program – could result in increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have an adverse effect on our financial position, results of operations, and liquidity.

Other
We expect to contribute a total of approximately $70 million to our qualified pension plans during 2009. In January 2009, we contributed $50 million of this amount to our main qualified pension plan.

We are subject to extensive federal, state, and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our refineries could require material additional expenditures to comply with environmental laws and regulations.

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.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Our critical accounting policies are disclosed in our annual report on Form 10-K for the year ended December 31, 2008.

As discussed in Note 2 of Condensed Notes to Consolidated Financial Statements, certain new financial accounting pronouncements have been issued that either have already been reflected in the accompanying consolidated financial statements, or will become effective for our financial statements at various dates in the future.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

COMMODITY PRICE RISK

For information regarding gains and losses on our derivative instruments, see Note 10 of Condensed Notes to Consolidated Financial Statements. The following tables provide information about our derivative commodity instruments as of June 30, 2009 and December 31, 2008 (dollars in millions, except for the weighted-average pay and receive prices as described below), including:

Fair Value Hedges – Fair value hedges are used to hedge certain refining inventories (which had a carrying amount of $4.2 billion and $4.4 billion as of June 30, 2009 and December 31, 2008, respectively, and a fair value of $7.2 billion and $5.1 billion as of June 30, 2009 and December 31, 2008, respectively) and our firm commitments (i.e., binding agreements to purchase inventories in the future). The gain or loss on a derivative instrument designated and qualifying as a fair value hedge and the offsetting loss or gain on the hedged item are recognized currently in income in the same period.

Cash Flow Hedges – Cash flow hedges are used to hedge certain forecasted feedstock and product purchases, refined product sales, and natural gas purchases. 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.

Economic Hedges – Economic hedges are hedges not designated as fair value or cash flow hedges that are used to:

– manage price volatility in refinery feedstock, refined product, and grain inventories;

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

– manage price volatility in the referenced product margins associated with the three-year earn-out agreement with Alon in connection with the sale of our Krotz Springs Refinery.

The derivative instruments related to economic hedges are recorded at fair value and changes in the fair value of the derivative instruments are recognized currently in income.

Trading Activities – These represent derivative commodity instruments held or issued for trading purposes. The derivative instruments entered into by us for trading activities are recorded at fair value and changes in the fair value of the derivative instruments are recognized currently in income.

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

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short positions. The weighted-average pay price and weighted-average receive price for options represent their strike price.

	June 30, 2009
			Wtd Avg		Wtd Avg							Pre-tax
	Contract		Pay		Receive		Contract		Market			Fair
	Volumes		Price		Price		Value		Value			Value
Fair Value Hedges:
Futures – short:
2009 (crude oil and refined products)		5,178		N/A	$	71.12	$	368	$	365		$	3
Cash Flow Hedges:
Swaps – long:
2009 (crude oil and refined products)		14,157	$	114.84		72.98		N/A		(593	)		(593	)
2010 (crude oil and refined products)		15,900		60.46		75.34		N/A		237			237
Swaps – short:
2009 (crude oil and refined products)		14,157		78.06		132.06		N/A		764			764
2010 (crude oil and refined products)		15,900		86.57		72.68		N/A		(221	)		(221	)
Futures – long:
2009 (crude oil and refined products)		1,211		72.12		N/A		87		85			(2	)
Economic Hedges:
Swaps – long:
2009 (crude oil and refined products)		52,625		34.89		30.43		N/A		(235	)		(235	)
2010 (crude oil and refined products)		51,514		51.27		41.88		N/A		(484	)		(484	)
2011 (crude oil and refined products)		11,750		45.56		30.16		N/A		(181	)		(181	)
Swaps – short:
2009 (crude oil and refined products)		36,233		44.99		54.49		N/A		344			344
2010 (crude oil and refined products)		47,878		50.77		63.34		N/A		602			602
2011 (crude oil and refined products)		8,850		44.07		65.39		N/A		189			189
Futures – long:
2009 (crude oil and refined products)		238,825		66.24		N/A		15,820		17,679			1,859
2010 (crude oil and refined products)		39,618		67.40		N/A		2,670		3,168			498
2009 (grain)		7,605		4.11		N/A		31		26			(5	)
2010 (grain)		50		4.29		N/A		–		–			–
Futures – short:
2009 (crude oil and refined products)		231,332		N/A		66.96		15,491		17,298			(1,807	)
2010 (crude oil and refined products)		39,174		N/A		69.53		2,724		3,228			(504	)
2009 (grain)		20,355		N/A		4.16		85		72			13
2010 (grain)		3,405		N/A		4.48		15		13			2
Trading Activities:
Swaps – long:
2009 (crude oil and refined products)		10,413		63.80		51.56		N/A		(127	)		(127	)
2010 (crude oil and refined products)		18,780		24.92		28.96		N/A		76			76
2011 (crude oil and refined products)		3,000		53.70		57.55		N/A		12			12
Swaps – short:
2009 (crude oil and refined products)		12,455		43.38		54.41		N/A		137			137
2010 (crude oil and refined products)		22,008		24.98		23.91		N/A		(24	)		(24	)
2011 (crude oil and refined products)		3,900		44.27		43.29		N/A		(4	)		(4	)

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	June 30, 2009
			Wtd Avg		Wtd Avg						Pre-tax
	Contract		Pay		Receive		Contract		Market		Fair
	Volumes		Price		Price		Value		Value		Value
Futures – long:
2009 (crude oil and refined products)		30,122	$	75.04		N/A	$	2,260	$	2,222	$	(38	)
2010 (crude oil and refined products)		2,321		77.04		N/A		179		190		11
2009 (natural gas)		5,350		4.95		N/A		26		25		(1	)
2010 (natural gas)		100		6.10		N/A		1		1		–
Futures – short:
2009 (crude oil and refined products)		30,214		N/A	$	75.01		2,266		2,223		43
2010 (crude oil and refined products)		2,346		N/A		75.68		178		191		(13	)
2009 (natural gas)		5,100		N/A		5.02		25		24		1
2010 (natural gas)		100		N/A		5.46		1		1		–
Total pre-tax fair value of open positions											$	552

67

	December 31, 2008
			Wtd Avg		Wtd Avg							Pre-tax
	Contract		Pay		Receive		Contract		Market			Fair
	Volumes		Price		Price		Value		Value			Value
Fair Value Hedges:
Futures – short:
2009 (crude oil and refined products)		6,904		N/A	$	48.28	$	333	$	320		$	13
Cash Flow Hedges:
Swaps – long:
2009 (crude oil and refined products)		60,162	$	121.69		58.44		N/A		(3,805	)		(3,805	)
2010 (crude oil and refined products)		4,680		63.72		64.03		N/A		1			1
Swaps – short:
2009 (crude oil and refined products)		60,162		62.38		129.80		N/A		4,056			4,056
2010 (crude oil and refined products)		4,680		76.32		78.69		N/A		11			11
Futures – long:
2009 (crude oil and refined products)		780		38.62		N/A		30		27			(3	)
Economic Hedges:
Swaps – long:
2009 (crude oil and refined products)		25,987		96.88		55.25		N/A		(1,082	)		(1,082	)
2010 (crude oil and refined products)		19,734		105.96		63.94		N/A		(829	)		(829	)
2011 (crude oil and refined products)		3,900		124.78		67.99		N/A		(221	)		(221	)
Swaps – short:
2009 (crude oil and refined products)		25,931		59.65		106.81		N/A		1,223			1,223
2010 (crude oil and refined products)		19,734		72.18		121.96		N/A		982			982
2011 (crude oil and refined products)		3,900		74.08		136.66		N/A		244			244
Futures – long:
2009 (crude oil and refined products)		135,882		59.17		N/A		8,040		7,319			(721	)
2010 (crude oil and refined products)		3,466		78.33		N/A		271		240			(31	)
2009 (natural gas)		4,310		8.46		N/A		36		24			(12	)
Futures – short:
2009 (crude oil and refined products)		135,091		N/A		62.74		8,475		7,510			965
2010 (crude oil and refined products)		3,692		N/A		84.66		313		276			37
2009 (natural gas)		4,310		N/A		5.68		24		24			–
Options – long:
2009 (crude oil and refined products)		57		60.64		N/A		1		–			(1	)
Trading Activities:
Swaps – long:
2009 (crude oil and refined products)		19,887		77.56		45.09		N/A		(646	)		(646	)
2010 (crude oil and refined products)		10,050		40.66		35.35		N/A		(53	)		(53	)
2011 (crude oil and refined products)		1,950		78.36		65.80		N/A		(24	)		(24	)
Swaps – short:
2009 (crude oil and refined products)		16,084		56.44		97.17		N/A		655			655
2010 (crude oil and refined products)		5,850		64.19		73.12		N/A		52			52
2011 (crude oil and refined products)		1,950		68.06		80.59		N/A		24			24

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	December 31, 2008
			Wtd Avg		Wtd Avg						Pre-tax
	Contract		Pay		Receive		Contract		Market		Fair
	Volumes		Price		Price		Value		Value		Value
Futures – long:
2009 (crude oil and refined products)		24,039	$	71.70		N/A	$	1,724	$	1,300	$	(424	)
2010 (crude oil and refined products)		956		84.12		N/A		80		70		(10	)
2009 (natural gas)		200		5.79		N/A		1		1		–
Futures – short:
2009 (crude oil and refined products)		21,999		N/A	$	73.38		1,614		1,209		405
2010 (crude oil and refined products)		956		N/A		83.63		80		70		10
2009 (natural gas)		200		N/A		5.82		1		1		–
Options – long:
2009 (crude oil and refined products)		100		30.00		N/A		–		–		–
Total pre-tax fair value of open positions											$	816

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INTEREST RATE RISK

The following table provides information about our debt instruments (dollars in millions), the fair value of which is 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 June 30, 2009 and December 31, 2008.

	June 30, 2009
	Expected Maturity Dates
																There-						Fair
	2009			2010			2011			2012			2013			after			Total			Value
Debt:
Fixed rate	$	–		$	33		$	418		$	759		$	489		$	5,597		$	7,296		$	7,205
Average interest rate		–	%		6.8	%		6.4	%		6.9	%		5.5	%		7.3	%		7.1	%
Floating rate	$	–		$	100		$	–		$	–		$	–		$	–		$	100		$	100
Average interest rate		–	%		1.8	%		–	%		–	%		–	%		–	%		1.8	%

	December 31, 2008
	Expected Maturity Dates
																There-						Fair
	2009			2010			2011			2012			2013			after			Total			Value
Debt:
Fixed rate	$	209		$	33		$	418		$	759		$	489		$	4,597		$	6,505		$	6,362
Average interest rate		3.6	%		6.8	%		6.4	%		6.9	%		5.5	%		6.8	%		6.6	%
Floating rate	$	100		$	–		$	–		$	–		$	–		$	–		$	100		$	100
Average interest rate		3.9	%		–	%		–	%		–	%		–	%		–	%		3.9	%

FOREIGN CURRENCY RISK

As of June 30, 2009, we had commitments to purchase $301 million of U.S. dollars. These commitments matured on or before July 20, 2009, resulting in a $7 million loss in the third quarter of 2009.

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 June 30, 2009.

(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, 2008, or our quarterly report on Form 10-Q for the quarter ended March 31, 2009.

Litigation

For the legal proceedings listed below, we hereby incorporate by reference into this Item our disclosures made in Part I, Item 1 of this Report included in Note 13 of Condensed Notes to Consolidated Financial Statements under the caption “Litigation.”

• MTBE Litigation

• Retail Fuel Temperature Litigation

• Rosolowski

• Other Litigation

Environmental Enforcement Matters

While it is not possible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against us, we believe that there would be no material effect on our consolidated financial position or results of operations. We are reporting these proceedings to comply with SEC regulations, which require us to disclose 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.

United States Environmental Protection Agency (EPA) (Paulsboro Refinery). On July 9, 2009, the EPA issued a demand for a $1,017,500 stipulated penalty under a Section 114 Consent Decree for an acid gas flaring incident in September 2008.

Los Angeles Regional Water Quality Control Board (LARWQCB) (Wilmington Marine Terminal) (this matter was last reported in our Form 10-K for the year ended December 31, 2008). In December 2007, as part of the National Pollutant Discharge Elimination System Permit renewal process for our Wilmington marine terminal, the LARWQCB issued a notice of violation (NOV) and Request for Information. The NOV alleged violations of acute toxicity effluent limits between 2000 and 2006 and reporting violations between 2001 and 2005. We settled this matter in the second quarter of 2009.

South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). On June 26, 2009, the SCAQMD issued a Request for Flare Minimization Plan and Mitigation Fees pursuant to its amended Rule 1118 (Control of Emissions from Refinery Flares). The Request related to two flaring events at our Wilmington Refinery in the fall of 2008. We submitted the mitigation plan and paid the mitigation fee of $1,319,505 on July 28, 2009.

Texas Commission on Environmental Quality (TCEQ) (Corpus Christi West Refinery). In the second quarter of 2009, the TCEQ issued a notice of enforcement (NOE) to our Corpus Christi West Refinery. The NOE alleges excess air emissions relating to two cooling tower leaks that occurred in 2008. The penalty demanded in the TCEQ’s Preliminary Report and Petition was $1,100,424. On July 27, 2009, we filed a response and request for hearing on this matter. Settlement discussions continue on this matter.

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Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2008.

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		Average		Total Number of		Total Number of		Maximum Number (or
	Number of		Price		Shares Not		Shares Purchased		Approximate Dollar
	Shares		Paid per		Purchased as Part		as Part of		Value) of Shares that
	Purchased		Share		of Publicly		Publicly		May Yet Be Purchased
					Announced Plans		Announced Plans		Under the Plans or
					or Programs (1)		or Programs		Programs
									(at month end) (2)
April 2009		2,571		$ 19.99		2,571		–	$ 3.46 billion
May 2009		6,385		$ 20.80		6,385		–	$ 3.46 billion
June 2009		397		$ 22.03		397		–	$ 3.46 billion
Total		9,353		$ 20.63		9,353		–	$ 3.46 billion

(1)

The shares reported in this column represent purchases settled in the second quarter of 2009 relating to (a) our purchases of shares in open-market transactions to meet our obligations under employee benefit plans, and (b) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our incentive compensation plans.

(2)

On 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 new $3 billion common stock purchase program. This program is in addition to the $6 billion program. This $3 billion program has no expiration date.

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Item 4. Submission of Matters to a Vote of Security Holders.

Valero’s annual meeting of stockholders (the Annual Meeting) was held April 30, 2009. Matters voted on at the Annual Meeting and the results thereof were as follows:

(a) Proposal 1: a proposal to elect four Class III directors to serve until the 2012 annual meeting. Valero’s bylaws require each director to be elected by the vote of the majority of the votes cast at the Annual Meeting. For purposes of this election, a “majority of the votes cast” means that the number of shares voted “for” a director’s election exceeds 50% of the number of votes cast with respect to that director’s election. The election of each Class III director was approved as follows.

Directors	For		Against		Abstain
Jerry D. Choate		274,635,688		160,197,114		1,889,959
William R. Klesse		276,485,338		158,311,375		1,926,048
Donald L. Nickles		273,997,328		160,869,421		1,856,011
Susan Kaufman Purcell		277,154,116		157,768,781		1,799,864

	Directors whose terms of office continued after the annual meeting were: W.E. “Bill” Bradford, Ronald K. Calgaard, Irl F. Engelhardt, Ruben M. Escobedo, Bob Marbut, Robert A. Profusek, and Stephen M. Waters.
(b)	Proposal 2: a proposal to ratify the appointment of KPMG LLP to serve as Valero’s independent registered public accounting firm for the fiscal year ending December 31, 2009. Proposal 2 required approval by the affirmative vote of a majority of the voting power of the shares present in person or by proxy at the Annual Meeting and entitled to vote. Proposal 2 was approved as follows:

For	Against	Abstain	(1)
430,981,925	4,563,821	1,177,014
Total Affirmative Votes	Total Negative Votes
430,981,925	5,740,835
Percentage of Shares Present and Entitled to Vote	Percentage of Shares Present and Entitled to Vote
98.69%	1.31%

	Stockholder Proposals:
(c)	Proposal 3: a stockholder proposal entitled, “Say-On-Pay” was approved as follows:

For	Against	Abstain	(1)	Non-Votes	(2)
195,481,456	117,571,382	28,978,894		94,691,029
Total Affirmative Votes	Total Negative Votes
195,481,456	146,550,276
Percentage of Shares Present and Entitled to Vote	Percentage of Shares Present and Entitled to Vote
57.15%	42.85%

^{(1) (2)} See notes on following page.

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(d) Proposal 4: a stockholder proposal entitled, “Stock Retention by Executives” was not approved as follows:

For	Against	Abstain	(1)	Non-Votes	(2)
144,998,858	193,369,259	3,663,615		94,691,029
Total Affirmative Votes	Total Negative Votes
144,998,858	197,032,874
Percentage of Shares Present and Entitled to Vote	Percentage of Shares Present and Entitled to Vote
42.39%	57.61%

(e) Proposal 5: a stockholder proposal entitled, “Compensation Consultant Disclosures” was approved as follows:

For	Against	Abstain	(1)	Non-Votes	(2)
190,261,333	146,832,853	4,937,545		94,691,030
Total Affirmative Votes	Total Negative Votes
190,261,333	151,770,398
Percentage of Shares Present and Entitled to Vote	Percentage of Shares Present and Entitled to Vote
55.63%	44.37%

(f) Proposal 6: a stockholder proposal entitled, “Disclosure of Political Contributions/Trade Associations” was not approved as follows:

For	Against	Abstain	(1)	Non-Votes	(2)
133,683,745	148,235,929	60,112,059		94,691,028
Total Affirmative Votes	Total Negative Votes
133,683,745	208,347,988
Percentage of Shares Present and Entitled to Vote	Percentage of Shares Present and Entitled to Vote
39.09%	60.91%

Required votes. For Proposal 1, directors were to be elected by a majority of votes cast by the holders of shares of Valero’s common stock present in person or by proxy at the Annual Meeting and entitled to vote. Proposals 2, 3, 4, 5, and 6 required approval by the affirmative vote of a majority of the voting power of the shares present in person or by proxy at the Annual Meeting and entitled to vote. Only Proposals 1, 2, 3, and 5 received the required votes for approval.

Notes :

(1) Effect of abstentions. Shares voted to “abstain” are treated as “present” for purposes of determining a quorum, and have the effect of a negative vote when approval for a proposal requires a majority of the voting power of the issued and outstanding shares of the company or a majority of the voting power of the shares present in person or by proxy and entitled to vote.

(2) Effect of “broker non-votes.” Brokers holding shares for the beneficial owners of such shares must vote according to specific instructions received from the beneficial owners. If specific instructions are not received, a broker may vote the shares in the broker’s discretion in certain instances. However, the New York Stock Exchange (NYSE) precludes brokers from exercising voting discretion on certain proposals, including stockholder proposals, without specific instructions from the beneficial owner. This results in a

74

“broker non-vote” on the proposal. A broker non-vote is treated as “present” for purposes of determining a quorum, has the effect of a negative vote when approval for a particular proposal requires a majority of the voting power of the issued and outstanding shares of the company, and has no effect when approval for a proposal requires a majority of the voting power of the shares present in person or by proxy and entitled to vote. Per the NYSE’s rules, brokers had discretion to vote on Proposals 1 and 2 at the Annual Meeting, but did not have discretion to vote on the shareholder proposals presented as Proposals 3, 4, 5, and 6.

Item 6. Exhibits

Exhibit No.	Description
*12.01	Statements of Computations of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Fixed Charges and Preferred Stock Dividends.
*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	The following materials from Valero Energy Corporation’s Form 10-Q for the quarter ended June 30, 2009, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Other Comprehensive Income, and (v) Condensed Notes to Consolidated Financial Statements, tagged as blocks of text.

*	Filed herewith.
**	Submitted electronically herewith.

In accordance with Rule 402 of Regulation S-T, the XBRL information in Exhibit 101 to this Quarterly Report on Form 10-Q shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

75

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: August 7, 2009

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EX-12.01

Exhibit 12.01

VALERO ENERGY CORPORATION AND SUBSIDIARIES
STATEMENTS OF COMPUTATIONS OF RATIOS OF EARNINGS TO FIXED
CHARGES AND RATIOS OF EARNINGS TO FIXED CHARGES AND PREFERRED
STOCK DIVIDENDS
(Millions of Dollars)

	Six Months
	Ended			Year Ended December 31,
	June 30,
	2009			2008			2007			2006			2005			2004
Ratio of Earnings to Fixed Charges:
Earnings:
Income (loss) from continuing operations before income tax expense (benefit), minority interest in net income of consolidated subsidiaries, and income from equity investees	$	(2	)	$	320		$	6,743		$	7,872		$	5,013		$	2,726
Add:
Fixed charges		336			643			658			566			474			410
Amortization of capitalized interest		10			18			15			9			8			7
Distributions from equity investees		–			–			–			47			50			42
Less:
Interest capitalized		(76	)		(111	)		(107	)		(165	)		(66	)		(37	)
Total earnings	$	268		$	870		$	7,309		$	8,329		$	5,479		$	3,148
Fixed charges:
Interest expense, net	$	161		$	340		$	359		$	212		$	268		$	260
Interest capitalized		76			111			107			165			66			37
Rental expense interest factor (1)		99			192			192			189			140			113
Total fixed charges	$	336		$	643		$	658		$	566		$	474		$	410
Ratio of earnings to fixed charges		0.8	x		1.4	x		11.1	x		14.7	x		11.6	x		7.7	x
Ratio of Earnings to Fixed Charges and Preferred Stock Dividends:
Total earnings	$	268		$	870		$	7,309		$	8,329		$	5,479		$	3,148
Total fixed charges	$	336		$	643		$	658		$	566		$	474		$	410
Preferred stock dividends		–			–			–			3			20			19
Total fixed charges and preferred stock dividends	$	336		$	643		$	658		$	569		$	494		$	429
Ratio of earnings to fixed charges and preferred stock dividends		0.8	x		1.4	x		11.1	x		14.6	x		11.1	x		7.3	x

(1) The interest portion of rental expense represents one-third of rents, which is deemed representative of the interest portion of rental expense.

EX-31.01

Exhibit 31.01

CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

     I, William R. Klesse, certify that:

     1. I have reviewed this quarterly report on Form 10-Q of Valero Energy Corporation;

     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

     (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

     (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

     (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

     (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

     (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

     (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 7, 2009

/s/ William R. Klesse William R. Klesse

Chief Executive Officer and President

EX-31.02

Exhibit 31.02

CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

     I, Michael S. Ciskowski, certify that:

     1. I have reviewed this quarterly report on Form 10-Q of Valero Energy Corporation;

     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

     (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

     (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

     (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

     (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

     (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

     (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 7, 2009

/s/ Michael S. Ciskowski Michael S. Ciskowski

Executive Vice President and Chief Financial Officer

EX-32.01

Exhibit 32.01

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Valero Energy Corporation (the Company) on Form 10-Q for the quarter ended June 30, 2009, as filed with the Securities and Exchange Commission on the date hereof (the Report), I, William R. Klesse, Chief Executive Officer and President of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ William R. Klesse William R. Klesse

Chief Executive Officer and President

August 7, 2009

A signed original of the written statement required by Section 906 has been provided to Valero Energy Corporation and will be retained by Valero Energy Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Valero Energy Corporation (the Company) on Form 10-Q for the quarter ended June 30, 2009, as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Michael S. Ciskowski, Executive Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Michael S. Ciskowski

Michael S. Ciskowski

Executive Vice President and Chief Financial Officer

August 7, 2009

A signed original of the written statement required by Section 906 has been provided to Valero Energy Corporation and will be retained by Valero Energy Corporation and furnished to the Securities and Exchange Commission or its staff upon request.