Valero Energy (VLO) 10-Q 2009 Q3 Quarterly report

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 September 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. Yesþ Noo

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). Yesþ Noo

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 filerþ Accelerated filero Non-accelerated filero Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of October 30, 2009 was 564,349,512.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

INDEX

	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008		3
Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2009 and 2008		4
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008		5
Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 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		46
Item 3. Quantitative and Qualitative Disclosures About Market Risk		72
Item 4. Controls and Procedures		77
PART II – OTHER INFORMATION
Item 1. Legal Proceedings		78
Item 1A. Risk Factors		79
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		80
Item 6. Exhibits		81
SIGNATURE		82

2

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Par Value)

	September 30,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	1,605		$	940
Restricted cash		144			131
Receivables, net		3,923			2,897
Inventories		4,576			4,637
Income taxes receivable		81			197
Deferred income taxes		150			98
Prepaid expenses and other		386			550
Total current assets		10,865			9,450
Property, plant and equipment, at cost		29,863			28,103
Accumulated depreciation		(5,632	)		(4,890	)
Property, plant and equipment, net		24,231			23,213
Intangible assets, net		229			224
Deferred charges and other assets, net		1,480			1,530
Total assets	$	36,805		$	34,417
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	213		$	312
Accounts payable		5,756			4,446
Accrued expenses		633			374
Taxes other than income taxes		667			592
Income taxes payable		64			–
Deferred income taxes		424			485
Total current liabilities		7,757			6,209
Debt and capital lease obligations, less current portion		7,162			6,264
Deferred income taxes		3,872			4,163
Other long-term liabilities		2,124			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		7,975			7,190
Treasury stock, at cost; 110,454,703 and 111,290,436 common shares		(6,830	)		(6,884	)
Retained earnings		14,670			15,484
Accumulated other comprehensive income (loss)		68			(176	)
Total stockholders’ equity		15,890			15,620
Total liabilities and stockholders’ equity	$	36,805		$	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						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Operating revenues (1)	$	19,489		$	35,960		$	51,238		$	100,545
Costs and expenses:
Cost of sales		18,104			32,506			46,275			91,848
Operating expenses		923			1,136			2,778			3,383
Retail selling expenses		182			201			522			579
General and administrative expenses		167			169			435			421
Depreciation and amortization expense		389			370			1,156			1,106
Asset impairment loss		417			43			575			43
Gain on sale of Krotz Springs Refinery		–			(305	)		–			(305	)
Total costs and expenses		20,182			34,120			51,741			97,075
Operating income (loss)		(693	)		1,840			(503	)		3,470
Other income (expense), net		9			36			(16	)		71
Interest and debt expense:
Incurred		(149	)		(112	)		(386	)		(335	)
Capitalized		19			31			95			74
Income (loss) before income tax expense (benefit)		(814	)		1,795			(810	)		3,280
Income tax expense (benefit)		(185	)		643			(236	)		1,133
Net income (loss)	$	(629	)	$	1,152		$	(574	)	$	2,147
Earnings (loss) per common share	$	(1.12	)	$	2.20		$	(1.08	)	$	4.07
Weighted-average common shares outstanding (in millions)		561			522			534			526
Earnings (loss) per common share – assuming dilution	$	(1.12	)	$	2.18		$	(1.08	)	$	4.02
Weighted-average common shares outstanding – assuming dilution (in millions)		561			529			534			535
Dividends per common share	$	0.15		$	0.15		$	0.45		$	0.42
Supplemental information:
(1) Includes excise taxes on sales by our U.S. retail system	$	226		$	207		$	659		$	605

See Condensed Notes to Consolidated Financial Statements.

4

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

(Unaudited)

	Nine Months Ended September 30,
	2009			2008
Cash flows from operating activities:
Net income (loss)	$	(574	)	$	2,147
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense		1,156			1,106
Asset impairment loss		575			43
Gain on sale of Krotz Springs Refinery		–			(305	)
Stock-based compensation expense		35			36
Deferred income tax expense (benefit)		(302	)		260
Changes in current assets and current liabilities		1,154			381
Changes in deferred charges and credits and other operating activities, net		(104	)		(148	)
Net cash provided by operating activities		1,940			3,520
Cash flows from investing activities:
Capital expenditures		(1,820	)		(1,894	)
Deferred turnaround and catalyst costs		(301	)		(279	)
Purchase of certain VeraSun Energy Corporation facilities		(556	)		–
Return of investment in Cameron Highway Oil Pipeline Company		18			11
Proceeds from the sale of Krotz Springs Refinery		–			463
Contingent payment in connection with acquisition		–			(25	)
Minor acquisitions		(29	)		(144	)
Other investing activities, net		5			16
Net cash used in investing activities		(2,683	)		(1,852	)
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		–			(774	)
Issuance of common stock in connection with employee benefit plans		7			14
Effect of tax deduction in excess of (less than) recognized stock-based compensation cost		(2	)		15
Common stock dividends		(239	)		(221	)
Debt issuance costs		(8	)		–
Other financing activities		(3	)		(2	)
Net cash provided by (used in) financing activities		1,343			(1,342	)
Effect of foreign exchange rate changes on cash		65			(23	)
Net increase in cash and temporary cash investments		665			303
Cash and temporary cash investments at beginning of period		940			2,464
Cash and temporary cash investments at end of period	$	1,605		$	2,767

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						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Net income (loss)	$	(629	)	$	1,152		$	(574	)	$	2,147
Other comprehensive income (loss):
Foreign currency translation adjustment		214			(105	)		324			(167	)
Pension and other postretirement benefits net (gain) loss reclassified into income, net of income tax expense of $1, $-, $1, and $1		(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 $(12), $(34), $(46), and $20		24			62			87			(38	)
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $29, $(9), $89, and $(18)		(54	)		16			(166	)		33
Net gain (loss) on cash flow hedges		(30	)		78			(79	)		(5	)
Other comprehensive income (loss)		183			(27	)		244			(173	)
Comprehensive income (loss)	$	(446	)	$	1,125		$	(330	)	$	1,974

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 nine months ended September 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 nine months ended September 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 onForm 10-K for the year ended December 31, 2008.

See Note 3 for a discussion of the presentation in the statements of income of the results of operations of the Krotz Springs Refinery, which was sold effective July 1, 2008.

We have evaluated subsequent events that occurred after September 30, 2009 through the filing of this Form 10-Q on November 5, 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 in 2008 and 2009 have been reclassified to conform to the current 2009 presentation. The primary reclassification relates to the presentation of asset impairment losses (discussed in Note 4) on a separate line in the consolidated statements of income due to the materiality of the amount in the third quarter of 2009. For comparability with this presentation, asset impairment losses resulting from the cancellation of certain capital projects classified as “construction in progress” of

7

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

$158 million for the first six months of 2009 and $43 million for both the three months and nine months ended September 30, 2008 have been reclassified from operating expenses and reflected on a separate line. The asset impairment losses are also presented on a separate line in the consolidated statements of cash flows, which resulted in an adjustment to capital expenditures previously reported for the nine months ended September 30, 2008.

2. ACCOUNTING PRONOUNCEMENTS

Financial Accounting Standards Board (FASB) “Accounting Standards Codification™” (the Codification or ASC)
The Codification is the single 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. The Codification became effective for interim and annual periods ending after September 15, 2009 and superseded all previously existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification is nonauthoritative. Commencing with the quarter ended September 30, 2009, all of our references to GAAP now use the specific Codification Topic or Section rather than prior accounting and reporting standards. The Codification did not change existing GAAP and, therefore, did not affect our financial position or results of operations.

Fair Value Measurements and Disclosures
In February 2008, ASC Topic 820, “Fair Value Measurements and Disclosures,” was modified to delay the effective date for applying fair value measurement disclosures for nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008. The implementation of this provision of Topic 820 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 10.

In August 2009, the FASB modified Topic 820 to address the measurement of liabilities at fair value in circumstances in which a quoted price in an active market for the identical liability is not available. In such circumstances, a reporting entity is required to measure fair value using one or more of the following techniques: (i) a valuation technique that uses the quoted price of the identical liability when traded as an asset, or the quoted prices for similar liabilities or similar liabilities when traded as assets; or (ii) another valuation technique that is consistent with Topic 820. The FASB also clarified that when estimating the fair value of the liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability. This modification also clarified that both a quoted price in an active market for the identical liability at the measurement date and the quoted price for the identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are Level 1 fair value measurements. This guidance is effective for the first reporting period (including interim periods) beginning after issuance, the adoption of which in the fourth quarter of 2009 is not expected to materially affect our financial position or results of operations.

8

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

Business Combinations
In December 2007, ASC Topic 805, “Business Combinations,” was issued to improve the financial reporting of business combinations and clarify the accounting for these transactions. This guidance in Topic 805 is 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. In April 2009, Topic 805 was modified 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. These provisions 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.

Due to the adoption of the new business combination provisions of Topic 805 effective January 1, 2009, these provisions were applied to the acquisition of certain ethanol plants from VeraSun Energy Corporation (VeraSun, with the acquisition referred to as the VeraSun Acquisition) in the second quarter of 2009, which is discussed in Note 3.

Noncontrolling Interests in Consolidated Financial Statements
In December 2007, ASC Topic 810, “Consolidation,” was modified to provide guidance for the accounting and reporting of noncontrolling interests, changes in controlling interests, and the deconsolidation of subsidiaries. In addition, this modification provides that an entity shall disclose pro forma net income and pro forma earnings per share if an entity has one or more noncontrolling interests. The adoption of these provisions of Topic 810 effective January 1, 2009 has not affected our financial position or results of operations.

Derivatives and Hedging
In March 2008, ASC Topic 815, “Derivatives and Hedging,” was modified to establish disclosure requirements for derivative instruments and for hedging activities. The required disclosures include 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. These disclosures are effective for fiscal years, and interim periods within those fiscal years, beginning on or after November 15, 2008. The adoption of these provisions of Topic 815 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 11.

Earnings Per Share
In June 2008, the FASB modified ASC Topic 260, “Earnings Per Share,” to address 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 Topic 260. These Codification amendments are effective for fiscal years, and interim periods within those fiscal years, beginning 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 these provisions. The adoption of these provisions effective January 1, 2009 did not have any effect on the calculation of basic earnings per common share for the three and nine months ended September 30, 2009, but did reduce basic earnings per common share from the $2.21 and $4.08 amounts originally reported for the three and nine months ended September 30, 2008, respectively, to $2.20 and $4.07, respectively. The calculation is provided in Note 8.

9

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

Equity Method Investments
In November 2008, the FASB modified ASC Topic 323, “Investments—Equity Method and Joint Ventures,” to provide 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. These provisions are effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. These provisions are to be applied prospectively to equity method investments acquired after the effective date, and earlier application is not permitted. Because we have not acquired any equity method investments during 2009, the adoption of these provisions effective January 1, 2009 has not affected our financial position or results of operations.

Compensation – Retirement Benefits
In December 2008, the FASB modified ASC Topic 715, “Compensation—Retirement Benefits,” to require enhanced 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. These disclosures are effective for fiscal years ending after December 15, 2009, with earlier application permitted. Since only disclosures are affected by these requirements, the adoption of these provisions will not affect our financial position or results of operations.

Financial Instruments
In April 2009, the provisions of ASC Topic 825, “Financial Instruments,” were modified 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. This provision is effective for interim reporting periods ending after June 15, 2009. Early adoption is permitted for periods ending after March 15, 2009 if an entity also elects to apply the early adoption provisions of certain other fair value modifications in Topic 820, “Fair Value Measurements and Disclosures,” and Topic 320, “Investments—Debt and Equity Securities.” We adopted all of these provisions in the first quarter of 2009, none of which has affected our financial position or results of operations. However, the adoption of the modified provisions of Topic 825 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 6. 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.

Subsequent Events
In May 2009, ASC Topic 855, “Subsequent Events,” was issued, which established 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, guidance was provided 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 occur after the balance sheet date. The provisions of Topic 855 are to be applied

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

prospectively and are effective for interim or annual financial periods ending after June 15, 2009. The adoption of the provisions of Topic 855 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.” According to ASC Topic 105, “Generally Accepted Accounting Principles,” Statement No. 166 shall continue to represent authoritative guidance until it is integrated into the Codification. Statement No. 166 amends and clarifies provisions related to the transfer of financial assets 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.

FASB Statement No. 167
In June 2009, the FASB issued Statement No. 167, “Amendments to FASB Interpretation No. 46(R).” According to ASC Topic 105, Statement No. 167 shall continue to represent authoritative guidance until it is integrated into the Codification. Statement No. 167 amends provisions related to 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.

3. ACQUISITION AND DISPOSITION

Acquisition of VeraSun
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. We incurred approximately $10 million of acquisition-related costs that were recognized in general and administrative expenses in the consolidated statement of income for the nine months ended September 30, 2009.

11

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

The acquired ethanol business involves the production and marketing of ethanol and its co-products, including distillers grains. The ethanol operations are reflected as a reportable segment in Note 12, the operations of which will complement our existing clean motor fuels business. The acquisition cost was funded with part of the proceeds from a $1 billion issuance of notes in March 2009, which is discussed in Note 6.

An independent appraisal of the assets acquired in the VeraSun Acquisition has been 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. As a result, pro forma information for the three months ended September 30, 2009 presented below represents actual results of operations. The operating revenues and net income associated with the acquired ethanol plants included in our consolidated statements of income for the three and nine months ended September 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 financial information is not necessarily indicative of the results of future operations.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2009			2008		2009			2008
Actual amounts from acquired business:
Operating revenues	$	410			N/A	$	673			N/A
Net income		29			N/A		42			N/A
Consolidated pro forma:
Operating revenues		19,489		$	36,429		51,461		$	101,756
Net income (loss)		(629	)		1,078		(581	)		2,082
Earnings (loss) per common share – assuming dilution		(1.12	)		2.04		(1.09	)		3.89

12

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

Sale of Krotz Springs Refinery
Effective July 1, 2008, we sold our refinery in Krotz Springs, Louisiana 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 in the consolidated statements of income for the three and nine months ended September 30, 2008. Under the offtake agreement, we agreed to (i) purchase all refined products from the Krotz Springs Refinery for three months after the effective date of the sale, (ii) purchase certain products for an additional one to five years after the expiration of the initial three-month period of the agreement, and (iii) provide certain refined products to Alon that are not produced at the Krotz Springs Refinery for an initial term of 15 months and thereafter until terminated by either party.

The sale resulted in a pre-tax gain of $305 million ($170 million after tax), which is presented in “gain on sale of Krotz Springs Refinery” in the consolidated statements of income for the three and nine months ended September 30, 2008. Cash proceeds, net of certain costs related to the sale, were $463 million, including approximately $135 million from the sale of working capital to Alon primarily related to the sale of inventory by our marketing and supply subsidiary.

In addition to the cash consideration received, we also received contingent consideration in the form of a three-year earn-out agreement based on certain product margins. This earn-out agreement qualified as a derivative contract and had a fair value of $171 million as of July 1, 2008. We hedged the risk of a decline in the referenced product margins by entering into certain commodity derivative contracts. On August 27, 2009, we settled the earn-out agreement with Alon for $35 million, of which $18 million was received on the settlement date and the remaining amount will be received in eight payments of $2.2 million each quarter beginning in the fourth quarter of 2009. In connection with the settlement of the earn-out agreement, we effectively closed our positions in the related commodity derivative contracts during the third quarter of 2009, as a result of which we locked in $175 million of cash proceeds on those contracts, approximately $80 million of which was received as of September 30, 2009 with the remaining proceeds to be received in varying monthly amounts through July 2011. As such, the total amount earned on the Alon earn-out agreement, including the related commodity derivative contracts, was $210 million.

Financial information as of July 1, 2008 related to the Krotz Springs Refinery assets and liabilities sold is summarized as follows (in millions):

Current assets (primarily inventory)	$	138
Property, plant and equipment, net		153
Goodwill		42
Deferred charges and other assets, net		4
Assets held for sale	$	337
Current liabilities	$	10
Liabilities related to assets held for sale	$	10

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

4. ASSET IMPAIRMENTS

Impairment of Long-Lived Assets
Long-lived assets are 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.

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 second half 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 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 nine months of 2009, thereby impacting 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 September 30, 2009, as narrow heavy sour crude oil differentials made the refinery uneconomical to operate. The Aruba Refinery was shut down in July 2009 and is expected to continue to be shut down until market conditions improve. We are continuing to evaluate potential alternatives 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 and remains shut down. In September 2009, we announced the shutdown of our coker and gasification units at our Delaware City Refinery also due to economic reasons. The coker unit is expected to remain shut down until economics improve and the gasification unit has been permanently shut down. As a result of these factors, we readdressed the potential impairment of all of our facilities (excluding the Delaware City gasification unit) as of September 30, 2009 based on an assumption that we would operate these facilities in the future, 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 September 30, 2009. However, due to the permanent shutdown of the gasification unit at the Delaware City Refinery, we recorded a pre-tax loss of approximately $280 million related to the abandonment of that unit.

Capital Project Write-offs
Due to the impact of the continuing economic slowdown on refining industry fundamentals, we further evaluated the recoverability of all of our capital projects currently classified as “construction in progress” during the third quarter of 2009. This is a continuation of an ongoing process that had commenced during the second half of 2008. As a result of this assessment, certain additional capital projects were permanently cancelled, resulting in write-offs of $137 million of project costs for the three months ended

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

September 30, 2009 (of which approximately $60 million was for projects related to the gasification unit at our Delaware City Refinery). This amount, combined with capital projects written off earlier in 2009, has resulted in total write-offs of capital projects of $295 million for the nine months ended September 30, 2009. During the three months and nine months ended September 30, 2008, we wrote off $43 million of capital projects, the amount of which has been reclassified from operating expenses and presented separately for comparability with the 2009 presentation.

In addition to capital projects that have been written off, 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 temporarily suspended until market conditions and cash flows improve. As of September 30, 2009, approximately $1.0 billion of costs had been incurred on these two projects. In addition, various other projects with a total cost of approximately $600 million as of September 30, 2009 have also been temporarily suspended. These suspended projects are included in our strategic plan, and the costs incurred to date have not been written off. We believe that the overall market conditions and our cash flows will improve in the future such that the completion and recoverability of these temporarily suspended projects is probable.

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 additional potential asset impairments until conditions improve. Changes in market conditions, as well as changes in assumptions used to test for recoverability and to determine fair value, could result in additional significant impairment charges in the future, thus affecting our earnings.

5. INVENTORIES

Inventories consisted of the following (in millions):

	September 30,		December 31,
	2009		2008
Refinery feedstocks	$	1,936	$	2,140
Refined products and blendstocks		2,240		2,224
Ethanol feedstocks and products		101		–
Convenience store merchandise		94		90
Materials and supplies		205		183
Inventories	$	4,576	$	4,637

As of September 30, 2009 and December 31, 2008, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $3.2 billion and $686 million, respectively.

6. DEBT

Non-Bank 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) was received from the holders prior to

15

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

September 15, 2009. A purchase notice was received related to $76 million of the outstanding notes, which resulted in a charge of $6 million in the third quarter of 2009 to write off a pro rata portion of unamortized fair value adjustment. We redeemed the $76 million of notes at 100% of their principal amount plus accrued and unpaid interest to October 15, 2009, the date of the payment of the purchase price.

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 $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.

Bank Credit Facilities
In October 2009, Lehman Brothers Bank, FSB, one of the participating banks under our $2.5 billion revolving credit facility, failed to fund its loan commitment related to our borrowing under this facility discussed below. Lehman Brothers’ aggregate commitment under the revolving credit facility was $84 million. As a result, our borrowing capacity under that revolving credit facility has been reduced to$2.4 billion commencing in October 2009.

During the nine months ended September 30, 2009, we had no borrowings or repayments under our revolving bank credit facilities. As of September 30, 2009, we had no borrowings outstanding under our revolving bank credit facilities. In October 2009, we borrowed and subsequently repaid approximately $40 million under our U.S. committed revolving bank credit facility.

As of September 30, 2009, we had $76 million of letters of credit outstanding under our uncommitted short-term bank credit facilities and $113 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 September 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 nine months ended September 30, 2008, we borrowed and repaid $296 million under our U.S. committed 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.

16

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

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 September 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):

	September 30,		December 31,
	2009		2008
Carrying amount	$	7,338	$	6,537
Fair value		8,335		6,462

7. 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 nine months ended September 30, 2009. During the nine months ended September 30, 2008, we purchased 14.6 million shares of our common stock at a cost of $774 million in connection with the administration of our employee benefit plans and common stock purchase programs authorized by our board of directors. During the nine months ended September 30, 2009 and 2008, we issued 0.9 million shares and 1.3 million shares, respectively, from treasury for our employee benefit plans.

Common Stock Dividends
On October 15, 2009, our board of directors declared a regular quarterly cash dividend of $0.15 per common share payable on December 9, 2009 to holders of record at the close of business on November 11, 2009.

17

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

8. 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 September 30,
	2009					2008
	Restricted		Common			Restricted		Common
	Stock		Stock			Stock		Stock
Earnings (loss) per common share:
Net income (loss)			$	(629	)			$	1,152
Less dividends paid:
Common stock				84					78
Nonvested restricted stock				–					–
Undistributed earnings (loss)			$	(713	)			$	1,074
Weighted-average common shares outstanding		2		561			1		522
Earnings (loss) per common share:
Distributed earnings	$	0.15	$	0.15		$	0.14	$	0.15
Undistributed earnings (loss)		–		(1.27	)		2.05		2.05
Total earnings (loss) per common share (1)	$	0.15	$	(1.12	)	$	2.19	$	2.20
Earnings (loss) per common share – assuming dilution:
Net income (loss)			$	(629	)			$	1,152
Weighted-average common shares outstanding				561					522
Common equivalent shares (2):
Stock options				–					6
Performance awards and other benefit plans				–					1
Weighted-average common shares outstanding – assuming dilution				561					529
Earnings (loss) per common share – assuming dilution			$	(1.12	)			$	2.18

(1)	The basic earnings per common share amount for the three months ended September 30, 2008 changed from the $2.21 originally reported as a result of the adoption of certain modifications that require our restricted stock to be treated as a participating security in calculating basic earnings per common share effective January 1, 2009, as discussed in Note 2.
(2)	Common equivalent shares were excluded from the computation of diluted earnings (loss) per common share for the three months ended September 30, 2009 because the effect of including such shares would be antidilutive.

18

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

	Nine Months Ended September 30,
	2009					2008
	Restricted		Common			Restricted		Common
	Stock		Stock			Stock		Stock
Earnings (loss) per common share:
Net income (loss)			$	(574	)			$	2,147
Less dividends paid:
Common stock				238					221
Nonvested restricted stock				1					–
Undistributed earnings (loss)			$	(813	)			$	1,926
Weighted-average common shares outstanding		2		534			1		526
Earnings (loss) per common share:
Distributed earnings	$	0.44	$	0.45		$	0.41	$	0.42
Undistributed earnings (loss)		–		(1.53	)		3.65		3.65
Total earnings (loss) per common share (1)	$	0.44	$	(1.08	)	$	4.06	$	4.07
Earnings (loss) per common share – assuming dilution:
Net income (loss)			$	(574	)			$	2,147
Weighted-average common shares outstanding				534					526
Common equivalent shares (2):
Stock options				–					8
Performance awards and other benefit plans				–					1
Weighted-average common shares outstanding – assuming dilution				534					535
Earnings (loss) per common share – assuming dilution			$	(1.08	)			$	4.02

(1)	The basic earnings per common share amount for the nine months ended September 30, 2008 changed from the $4.08 originally reported as a result of the adoption of certain modifications that require our restricted stock to be treated as a participating security in calculating basic earnings per common share effective January 1, 2009, as discussed in Note 2.
(2)	Common equivalent shares were excluded from the computation of diluted earnings (loss) per common share for the nine months ended September 30, 2009 because the effect of including such shares would be antidilutive.

19

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

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 antidilutive (in millions). As indicated above, common equivalent shares, which represent primarily stock options, were excluded as a result of the net losses reported for the three and nine months ended September 30, 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 September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Common equivalent shares		4		–		4		–
Stock options		10		7		10		7

9. SUPPLEMENTAL CASH FLOW INFORMATION

In order to determine net cash provided by operating activities, net income (loss) is adjusted by, among other things, changes in current assets and current liabilities as follows (in millions):

	Nine Months EndedSeptember 30,
	2009			2008
Decrease (increase) in current assets:
Restricted cash	$	(13	)	$	(90	)
Receivables, net		(966	)		1,120
Inventories		198			(842	)
Income taxes receivable		137			–
Prepaid expenses and other		119			(6	)
Increase (decrease) in current liabilities:
Accounts payable		1,466			476
Accrued expenses		94			32
Taxes other than income taxes		54			(77	)
Income taxes payable		65			(232	)
Changes in current assets and current liabilities	$	1,154		$	381

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;

• amounts accrued for capital expenditures, deferred turnaround and catalyst costs, and contingent earn-out payments are reflected in investing activities in the consolidated statements of cash flows when such amounts are paid;

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

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

• 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 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 nine months ended September 30, 2009 and 2008.

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

	Nine Months EndedSeptember 30,
	2009			2008
Interest paid in excess of amount capitalized	$	232		$	187
Income taxes paid (net of tax refunds received)		(134	)		1,092

10. FAIR VALUE MEASUREMENTS

A fair value hierarchy (Level 1, Level 2, or Level 3) is used to categorize fair value amounts based on the quality of inputs used to measure fair value. Accordingly, 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 tables below present information (dollars in millions) about our financial assets and liabilities measured and recorded at fair value on a recurring basis and indicate the fair value hierarchy of the inputs utilized by us to determine the fair values as of September 30, 2009 and December 31, 2008.

	Fair Value Measurements Using
	Quoted		Significant
	Prices		Other		Significant
	in Active		Observable		Unobservable		Total as of
	Markets		Inputs		Inputs		September 30,
	(Level 1)		(Level 2)		(Level 3)		2009
Assets:
Commodity derivative contracts	$	44	$	490	$	–	$	534
Nonqualified benefit plans		106		–		–		106
Liabilities:
Commodity derivative contracts		149		11		–		160
Certain nonqualified benefit plans		32		–		–		32

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

	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. 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, was measured at fair value using a discounted cash flow model and was categorized in Level 3 of the fair value hierarchy through July 2009. Significant inputs to the model included expected payments and discount rates that considered the effects of both credit risk and the time value of money. On August 27, 2009, we settled the Alon earn-out agreement as discussed in Note 3. We have elected not to apply the fair value option to this settlement receivable.

Cash received from brokers of $41 million, resulting from the equity in broker accounts covered by master netting arrangements exceeding the minimum margin requirements for such accounts, is netted against 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. 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.

22

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 nine months ended September 30, 2009.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Balance at beginning of period	$	38		$	–		$	13		$	–
Alon earn-out agreement (see Note 3)		(33	)		171			(33	)		171
Net realized and unrealized gains (losses) included in earnings		(5	)		(14	)		20			(14	)
Transfers in and/or out of Level 3		–			–			–			–
Balance at end of period	$	–		$	157		$	–		$	157

The above realized and unrealized gains and losses, which are reported in “other income (expense), net” in the consolidated statements of income, related to the Alon earn-out agreement that was settled in August 2009, as discussed above. These gains and losses were offset by the recognition in “other income (expense), net” of losses and gains 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 prior to the settlement are included in the “commodity derivative contracts” amounts reflected in the fair value table as of December 31, 2008 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, and indicates the fair value hierarchy of the inputs utilized by us to determine the fair values as of September 30, 2009.

	Fair Value Measurements Using
	Quoted		Significant
	Prices		Other		Significant
	in Active		Observable		Unobservable		Total as of
	Markets		Inputs		Inputs		September 30,
	(Level 1)		(Level 2)		(Level 3)		2009
Liabilities:
Asset retirement obligations	$	–	$	–	$	13	$	13

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.

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

11. 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 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. The cash flow effects of all of our derivative contracts are reflected in operating activities in the consolidated statements of cash flows for all periods presented.

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 commodity derivative 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 commodity derivative 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 September 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 September 30, 2009, we had the following outstanding commodity derivative 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)		5,133

24

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

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

Derivative Instrument / Maturity	Contract Volumes
Swaps – long:
2009		10,722
2010		24,810
Swaps – short:
2009		10,722
2010		24,810
Futures – long (2009)		1,218

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

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, and (ii) manage price volatility in certain forecasted refinery feedstock, product, and grain purchases, refined product sales, and natural gas purchases. In addition, through August 2009, we used economic hedges to manage price volatility in the referenced product margins associated with the Alon earn-out agreement, which was a separate contractual derivative that we entered into with the sale of our Krotz Springs Refinery but which was settled in August 2009, as further discussed in Note 3. 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 September 30, 2009, we had the following outstanding commodity derivative 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		45,030
2010		107,194
2011		26,275
Swaps – short:
2009		20,458
2010		63,633
2011		11,025
Futures – long:
2009		222,053
2010		102,235
2009 (grain)		3,705
2010 (grain)		75
Futures – short:
2009		216,315
2010		101,388
2009 (grain)		10,585
2010 (grain)		4,495
Options – long:
2009		6
2010		511
Options – short:
2010		500

26

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

Trading Activities

These represent commodity derivative instruments held or issued for trading purposes. Our objective in entering into commodity derivative 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 September 30, 2009, we had the following outstanding commodity derivative 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		6,502
2010		23,589
2011		3,000
Swaps – short:
2009		5,679
2010		27,946
2011		3,900
Futures – long:
2009		25,809
2010		4,318
2009 (natural gas)		3,750
2010 (natural gas)		100
Futures – short:
2009		25,859
2010		4,268
2009 (natural gas)		3,750
2010 (natural gas)		100
Options – long:
2009		40
Options – short:
2009		40

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.

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

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 September 30, 2009, we had commitments to purchase $248 million of U.S. dollars. These commitments matured on or before November 2, 2009, resulting in a $5 million loss in the fourth quarter of 2009.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
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 September 30, 2009 (in millions) and the line items in the balance sheet in which the fair values are reflected. See Note 10 for additional information related to the fair values of our derivative instruments. As indicated in Note 10, 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, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts. In addition, in Note 10 we netted cash received from brokers attributable to excess margin against the fair value of the commodity derivatives; this cash receipt 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	$	12	Receivables, net	$	5
Futures	Accrued expenses		60	Accrued expenses		52
Swaps	Receivables, net		315	Receivables, net		267
Swaps	Prepaid expenses and other current assets		1,025	Prepaid expenses and other current assets		902
Swaps	Accrued expenses		3	Accrued expenses		4
Total derivatives designated as hedging instruments		$	1,415		$	1,230
Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	23	Receivables, net	$	26
Futures	Accrued expenses		2,273	Accrued expenses		2,349
Swaps	Receivables, net		575	Receivables, net		430
Swaps	Prepaid expenses and other current assets		1,254	Prepaid expenses and other current assets		1,079
Swaps	Accrued expenses		13	Accrued expenses		24
Options	Prepaid expenses and other current assets		1	Prepaid expenses and other current assets		1
Options	Accrued expenses		–	Accrued expenses		–
Foreign currency contracts	Receivables, net		–	Accounts payable		–
Total derivatives not designated as hedging instruments		$	4,139		$	3,909
Total derivatives		$	5,554		$	5,139

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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 September 30, 2009, we had net receivables related to derivative instruments of $27 million from counterparties in the refining industry and $271 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 nine months ended September 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

Nine

Three

Nine

Three

Nine

Months

Months

Months

Months

Months

Months

Ended

Ended

Ended

Ended

Ended

Ended

September 30, 2009

September 30, 2009

September 30, 2009

Commodity contracts

Cost of sales

$

(5

)

$

(94

)

Cost of sales

$

(3

)

$

87

$

(8

)

$

(7

)

Total

$

(5

)

$

(94

)

$

(3

)

$

87

$

(8

)

$

(7

)

(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.

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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

Recognized in

Recognized in

Cash Flow

OCI on

Accumulated OCI

from Accumulated

Income on

Income on

Hedging

Derivatives

into Income

OCI into Income

Derivatives

Derivatives

Relationships

(Effective Portion)

(Effective Portion)

(Effective Portion)

(Ineffective Portion)

(Ineffective Portion) (1)

Three

Nine

Three

Nine

Three

Nine

Months

Months

Months

Months

Months

Months

Ended

Ended

Ended

Ended

Ended

Ended

September 30, 2009

September 30, 2009

September 30, 2009

Commodity contracts (2)

$

36

$

133

Cost of sales

$

83

$

255

Cost of sales

$

6

$

5

Total

$

36

$

133

$

83

$

255

$

6

$

5

(1)

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

(2)

For the three and nine months ended September 30, 2009, cash flow hedges primarily related to forward sales of distillates and associated forward purchases of crude oil, with $90 million of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive income as of September 30, 2009. We expect that a significant amount of the deferred gains at September 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 nine months ended September 30, 2009, there were no amounts reclassified from accumulated other comprehensive income 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			Nine Months
		Ended			Ended
		September 30, 2009
Commodity contracts	Cost of sales	$	(68	)	$	(30	)
Foreign currency contracts	Cost of sales		(9	)		(25	)
			(77	)		(55	)
Alon earn-out agreement	Other income (expense)		(5	)		20
Alon earn-out hedge (commodity contracts)	Other income (expense)		1			(62	)
			(4	)		(42	)
Total		$	(81	)	$	(97	)

	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		Nine Months
		Ended		Ended
		September 30, 2009
Commodity contracts	Cost of sales		$  9	$	125
Total			$  9	$	125

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

12. 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 September 30, 2009:
Operating revenues from external customers	$	16,932		$	2,147	$	410	$	–		$	19,489
Intersegment revenues		1,388			–		47		–			1,435
Operating income (loss)		(674	)		111		49		(179	)		(693	)
Three months ended September 30, 2008:
Operating revenues from external customers		32,903			3,057		–		–			35,960
Intersegment revenues		2,296			–		–		–			2,296
Operating income (loss)		1,913			107		–		(180	)		1,840
Nine months ended September 30, 2009:
Operating revenues from external customers		44,817			5,748		673		–			51,238
Intersegment revenues		3,676			–		76		–			3,752
Operating income (loss)		(335	)		232		71		(471	)		(503	)
Nine months ended September 30, 2008:
Operating revenues from external customers		91,958			8,587		–		–			100,545
Intersegment revenues		6,563			–		–		–			6,563
Operating income (loss)		3,716			206		–		(452	)		3,470

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

	September 30,		December 31,
	2009		2008
Refining	$	32,056	$	30,801
Retail		1,863		1,818
Ethanol		605		–
Corporate		2,281		1,798
Total consolidated assets	$	36,805	$	34,417

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

13. EMPLOYEE BENEFIT PLANS

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

							Other Postretirement
	Pension Plans						Benefit Plans
	2009			2008			2009			2008
Three months ended September 30:
Components of net periodic benefit cost:
Service cost	$	26		$	22		$	3		$	3
Interest cost		19			19			6			7
Expected return on plan assets		(27	)		(26	)		–			–
Amortization of:
Prior service cost (credit)		1			1			(5	)		(2	)
Net loss		3			–			2			1
Net periodic benefit cost	$	22		$	16		$	6		$	9
Nine months ended September 30:
Components of net periodic benefit cost:
Service cost	$	78		$	69		$	9		$	10
Interest cost		59			57			19			21
Expected return on plan assets		(81	)		(78	)		–			–
Amortization of:
Prior service cost (credit)		2			2			(14	)		(7	)
Net loss		8			1			5			3
Net periodic benefit cost	$	66		$	51		$	19		$	27

During the nine months ended September 30, 2009 and 2008, we contributed $72 million and $110 million, respectively, to our qualified pension plans.

14. 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 September 30, 2009, we have no further commitments with respect to contingent earn-out agreements. However, as discussed in Note 3, in July 2008 we received contingent consideration from Alon in the form of a three-year earn-out agreement based on certain product margins, as partial consideration for the sale of our Krotz Springs Refinery. On August 27, 2009, we settled this earn-out agreement with Alon for $35 million, of which $18 million was received on the settlement date and the remaining amount will be received in eight payments of $2.2 million each quarter beginning in the fourth quarter of 2009.

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 insurance carriers under our insurance policies. We reached a settlement with the insurance carriers on

33

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

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 extended through December 31, 2009 and provided 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 and in September 2009, Total completed its acquisition of Dow’s equity interest in TRN. Our obligations under the Agreement have since been terminated.

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 (NAI) pursuant to which we sought 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 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. Amounts deposited under the escrow agreement, which totaled $114 million and $102 million as of September 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 $20 million related to dividends. We have also challenged approximately $35 million in foreign exchange payments made to the Central Bank of Aruba as payments exempted under our tax

34

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

holiday, as well as other reasons. Both the dividend tax and the foreign exchange payment matters were also addressed in the arbitration proceedings discussed above.

On November 3, we received an interim First Partial Award from the NAI arbitral panel.  The panel’s ruling validated our tax holiday agreement, but the panel also ruled in favor of the GOA on our dispute of the $35 million in foreign exchange payments previously made to the Central Bank of Aruba.  The panel’s decision did not, however, fully resolve the remaining two items in the arbitration, the applicable dividend tax rate and the turnover tax.  With respect to the dividend tax, the panel ruled that the dividend tax was not a profit tax covered by the tax holiday agreement, but the panel did not address the fact that Aruban companies with tax holidays are subject to a 0% dividend withholding rate rather than the 5% rate alleged by the GOA.  With respect to the turnover tax, the panel did reject our contractual claims but it decided that our non-contractual claims against the turnover tax merited further discussion with and review by the panel before a final decision could be rendered.  Prior to this interim decision, no expense or liability had been recognized in our consolidated financial statements with respect to unfunded amounts.  In light of the now uncertain timing of any final resolution of these claims, we have recorded a loss contingency accrual of approximately $140 million, including interest, with respect to both the dividend and turnover taxes.  We continue to believe that our remaining claims against these taxes have significant merit, and intend to vigorously pursue these claims through the arbitration proceedings and in on-island proceedings as well.

American Clean Energy and Security Act of 2009 and Clean Energy Jobs and American Power Act of 2009
On June 26, 2009, the U.S. House of Representatives narrowly approved the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey bill. On September 30, 2009, the U.S. Senate Committee on Environment and Public Works introduced a similar bill in the Senate, the Clean Energy Jobs and American Power Act of 2009, also known as the Kerry-Boxer bill. These bills, if passed by Congress, would establish a national “cap-and-trade” program beginning in 2012 to address greenhouse gas emissions and climate change. The Waxman-Markey bill 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, while the Kerry-Boxer bill proposes a more accelerated timetable for carbon dioxidereductions. The cap-and-trade program would require businesses that emit greenhouse gases to buy 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 would 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 a cap-and-trade bill (or whether such a bill will be passed by Congress), any new federal restrictions on greenhouse gas emissions – including a cap-and-trade program – could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have an adverse effect on our financial position, results of operations, and liquidity.

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

Litigation
MTBE Litigation
As of November 5, 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). Sixteen cases are pending in state court. We recently settled theCity of New Yorkcase, which had been set for trial in June 2009. TheVillage of Hempstead andWest Hempstead Water Districtcases will be set for trial in the summer of 2010. Discovery is open in all cases. We believe that we have strong defenses to all claims and are vigorously defending the lawsuits.

We have recorded a loss contingency liability with respect to our MTBE litigation portfolio. However, due to the inherent uncertainty of litigation, we believe that it is reasonably possible 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 November 5, 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 may rule on certain class certification issues in 2009 or early 2010. 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 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.

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

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.

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.

15. 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 September 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.

37

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

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

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	298		$	–		$	1,307		$	–		$	1,605
Restricted cash		23			1			120			–			144
Receivables, net		–			38			3,885			–			3,923
Inventories		–			521			4,055			–			4,576
Income taxes receivable		58			–			81			(58	)		81
Deferred income taxes		–			–			150			–			150
Prepaid expenses and other		–			8			378			–			386
Total current assets		379			568			9,976			(58	)		10,865
Property, plant and equipment, at cost		–			5,834			24,029			–			29,863
Accumulated depreciation		–			(582	)		(5,050	)		–			(5,632	)
Property, plant and equipment, net		–			5,252			18,979			–			24,231
Intangible assets, net		–			–			229			–			229
Investment in Valero Energy affiliates		5,553			3,410			(701	)		(8,262	)		–
Long-term notes receivable from affiliates		16,745			–			–			(16,745	)		–
Deferred income tax receivable		1,351			–			–			(1,351	)		–
Deferred charges and other assets, net		132			134			1,214			–			1,480
Total assets	$	24,160		$	9,364		$	29,697		$	(26,416	)	$	36,805
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	109		$	–		$	104		$	–		$	213
Accounts payable		42			180			5,534			–			5,756
Accrued expenses		166			99			368			–			633
Taxes other than income taxes		–			21			646			–			667
Income taxes payable		–			–			122			(58	)		64
Deferred income taxes		424			–			–			–			424
Total current liabilities		741			300			6,774			(58	)		7,757
Debt and capital lease obligations, less current portion		6,233			896			33			–			7,162
Long-term notes payable to affiliates		–			7,646			9,099			(16,745	)		–
Deferred income taxes		–			1,076			4,147			(1,351	)		3,872
Other long-term liabilities		1,296			147			681			–			2,124
Stockholders’ equity:
Common stock		7			–			1			(1	)		7
Additional paid-in capital		7,975			1,598			4,402			(6,000	)		7,975
Treasury stock		(6,830	)		–			–			–			(6,830	)
Retained earnings		14,670			(2,289	)		4,479			(2,190	)		14,670
Accumulated other comprehensive income (loss)		68			(10	)		81			(71	)		68
Total stockholders’ equity		15,890			(701	)		8,963			(8,262	)		15,890
Total liabilities and stockholders’ equity	$	24,160		$	9,364		$	29,697		$	(26,416	)	$	36,805

38

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

39

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

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

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	3,925		$	17,533		$	(1,969	)	$	19,489
Costs and expenses:
Cost of sales		–			4,406			15,667			(1,969	)		18,104
Operating expenses		–			149			774			–			923
Retail selling expenses		–			–			182			–			182
General and administrative expenses		1			39			127			–			167
Depreciation and amortization expense		–			56			333			–			389
Asset impairment loss		–			370			47			–			417
Total costs and expenses		1			5,020			17,130			(1,969	)		20,182
Operating income (loss)		(1	)		(1,095	)		403			–			(693	)
Equity in earnings (losses) of subsidiaries		(650	)		358			(406	)		698			–
Other income (expense), net		309			(5	)		187			(482	)		9
Interest and debt expense:
Incurred		(176	)		(142	)		(313	)		482			(149	)
Capitalized		–			1			18			–			19
Income (loss) before income tax expense (benefit)		(518	)		(883	)		(111	)		698			(814	)
Income tax expense (benefit) (1)		111			(477	)		181			–			(185	)
Net loss	$	(629	)	$	(406	)	$	(292	)	$	698		$	(629	)

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

40

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

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

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	6,952		$	35,548		$	(6,540	)	$	35,960
Costs and expenses:
Cost of sales		–			6,736			32,310			(6,540	)		32,506
Operating expenses		–			183			953			–			1,136
Retail selling expenses		–			–			201			–			201
General and administrative expenses		(1	)		5			165			–			169
Depreciation and amortization expense		–			57			313			–			370
Asset impairment loss		–			11			32			–			43
Gain on sale of Krotz Springs Refinery		–			–			(305	)		–			(305	)
Total costs and expenses		(1	)		6,992			33,669			(6,540	)		34,120
Operating income (loss)		1			(40	)		1,879			–			1,840
Equity in earnings of subsidiaries		1,116			296			181			(1,593	)		–
Other income (expense), net		265			(24	)		232			(437	)		36
Interest and debt expense:
Incurred		(152	)		(134	)		(263	)		437			(112	)
Capitalized		–			7			24			–			31
Income before income tax expense (benefit)		1,230			105			2,053			(1,593	)		1,795
Income tax expense (benefit) (1)		78			(76	)		641			–			643
Net income	$	1,152		$	181		$	1,412		$	(1,593	)	$	1,152

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

41

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

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

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	10,116		$	49,003		$	(7,881	)	$	51,238
Costs and expenses:
Cost of sales		–			10,838			43,318			(7,881	)		46,275
Operating expenses		–			529			2,249			–			2,778
Retail selling expenses		–			–			522			–			522
General and administrative expenses		2			41			392			–			435
Depreciation and amortization expense		–			179			977			–			1,156
Asset impairment loss		–			475			100			–			575
Total costs and expenses		2			12,062			47,558			(7,881	)		51,741
Operating income (loss)		(2	)		(1,946	)		1,445			–			(503	)
Equity in earnings (losses) of subsidiaries		(728	)		692			(766	)		802			–
Other income (expense), net		853			(47	)		500			(1,322	)		(16	)
Interest and debt expense:
Incurred		(481	)		(384	)		(843	)		1,322			(386	)
Capitalized		–			15			80			–			95
Income (loss) before income tax expense (benefit)		(358	)		(1,670	)		416			802			(810	)
Income tax expense (benefit) (1)		216			(904	)		452			–			(236	)
Net income (loss)	$	(574	)	$	(766	)	$	(36	)	$	802		$	(574	)

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

42

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

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

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	22,691		$	99,226		$	(21,372	)	$	100,545
Costs and expenses:
Cost of sales		–			22,004			91,216			(21,372	)		91,848
Operating expenses		–			624			2,759			–			3,383
Retail selling expenses		–			–			579			–			579
General and administrative expenses		(4	)		19			406			–			421
Depreciation and amortization expense		–			195			911			–			1,106
Asset impairment loss		–			11			32			–			43
Gain on sale of Krotz Springs Refinery		–			–			(305	)		–			(305	)
Total costs and expenses		(4	)		22,853			95,598			(21,372	)		97,075
Operating income (loss)		4			(162	)		3,628			–			3,470
Equity in earnings of subsidiaries		1,903			472			89			(2,464	)		–
Other income (expense), net		838			(50	)		614			(1,331	)		71
Interest and debt expense:
Incurred		(424	)		(414	)		(828	)		1,331			(335	)
Capitalized		–			16			58			–			74
Income (loss) before income tax expense (benefit)		2,321			(138	)		3,561			(2,464	)		3,280
Income tax expense (benefit) (1)		174			(227	)		1,186			–			1,133
Net income	$	2,147		$	89		$	2,375		$	(2,464	)	$	2,147

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

43

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

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

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(164	)	$	(1,216	)	$	3,320		$	–		$	1,940
Cash flows from investing activities:
Capital expenditures		–			(420	)		(1,400	)		–			(1,820	)
Deferred turnaround and catalyst costs		–			(41	)		(260	)		–			(301	)
Purchase of certain VeraSun Energy Corporation facilities		–			–			(556	)		–			(556	)
Return of investment in Cameron Highway Oil Pipeline Company		–			–			18			–			18
Minor acquisition		–			–			(29	)		–			(29	)
Net intercompany loans		(1,099	)		–			–			1,099			–
Other investing activities, net		–			–			5			–			5
Net cash used in investing activities		(1,099	)		(461	)		(2,222	)		1,099			(2,683	)
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		(239	)		–			–			–			(239	)
Net intercompany borrowings (repayments)		–			1,677			(578	)		(1,099	)		–
Other financing activities, net		(3	)		–			(3	)		–			(6	)
Net cash provided by (used in) financing activities		1,346			1,677			(581	)		(1,099	)		1,343
Effect of foreign exchange rate changes on cash		–			–			65			–			65
Net increase in cash and temporary cash investments		83			–			582			–			665
Cash and temporary cash investments at beginning of period		215			–			725			–			940
Cash and temporary cash investments at end of period	$	298		$	–		$	1,307		$	–		$	1,605

44

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

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

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG (1)			Subsidiaries (1)			Eliminations			Consolidated
Net cash provided by operating activities	$	248		$	53		$	3,219		$	–		$	3,520
Cash flows from investing activities:
Capital expenditures		–			(397	)		(1,497	)		–			(1,894	)
Deferred turnaround and catalyst costs		–			(62	)		(217	)		–			(279	)
Return of investment in Cameron Highway Oil Pipeline Company		–			–			11			–			11
Proceeds from the sale of Krotz Springs Refinery		–			–			463			–			463
Contingent payment in connection with acquisition		–			–			(25	)		–			(25	)
Investments in subsidiaries		(1,043	)		–			–			1,043			–
Net intercompany loan repayments		1,993			–			–			(1,993	)		–
Minor acquisitions		–			–			(144	)		–			(144	)
Other investing activities, net		–			1			15			–			16
Net cash provided by (used in) investing activities		950			(458	)		(1,394	)		(950	)		(1,852	)
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		(774	)		–			–			–			(774	)
Common stock dividends		(221	)		–			–			–			(221	)
Net intercompany borrowings (repayments)		–			773			(2,766	)		1,993			–
Capital contributions from parent		–			–			1,043			(1,043	)		–
Other financing activities		29			–			(2	)		–			27
Net cash provided by (used in) financing activities		(972	)		405			(1,725	)		950			(1,342	)
Effect of foreign exchange rate changes on cash		–			–			(23	)		–			(23	)
Net increase in cash and temporary cash investments		226			–			77			–			303
Cash and temporary cash investments at beginning of period		1,414			–			1,050			–			2,464
Cash and temporary cash investments at end of period	$	1,640		$	–		$	1,127		$	–		$	2,767

(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.

45

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;

46

• 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.

47

OVERVIEW

In this overview, we describe some of the primary factors that we believe affected our results of operations in the third quarter and first nine months of 2009. We reported a net loss of $629 million, or $1.12 per share, for the third quarter of 2009, compared to net income of $1.2 billion, or $2.18 per share, for the third quarter of 2008. We reported a net loss of $574 million, or $1.08 per share, for the first nine months of 2009, compared to net income of $2.1 billion, or $4.02 per share, for the first nine months of 2008. The results of operations for the third quarter and first nine months of 2009 were unfavorably impacted by asset impairment losses of $417 million ($0.48 per share) and $575 million ($0.70 per share), respectively, which are discussed further below, as well as a $140 million ($0.25 per share and $0.26 per share, respectively, for the third quarter and first nine months of 2009) loss contingency accrual (including interest) recorded in the third quarter of 2009 related to our dispute of a turnover tax on export sales and other tax matters involving the Government of Aruba. The results of operations for the third quarter and first nine months of 2008 included a $0.32 per share benefit from the gain on the sale of our Krotz Springs Refinery. In addition, results of operations for the first nine months of 2008 included a pre-tax benefit of approximately $100 million, or $0.12 per share, resulting from a settlement of our business interruption insurance claims related to a 2007 fire at our McKee Refinery.

Due to the impact of the continuing economic slowdown on refining industry fundamentals, during the third quarter of 2009, we continued to assess our assets for potential impairment. This evaluation included an assessment of our operating assets as well as an evaluation of our capital projects classified as “construction in progress.” As a result of this analysis, we recorded asset impairment losses of $417 million and $575 million for the third quarter and first nine months of 2009, respectively. Of these amounts, approximately $340 million related to the write-off in the third quarter of 2009 of costs related to the gasification unit at our Delaware City Refinery. The remaining write-offs related to the permanent cancellation of various capital projects at various refineries.

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 economic slowdown that has existed throughout 2009 has caused a continuing weakness in demand for refined products, which put pressure on refined product margins during the third quarter and first nine months of 2009. This reduced demand, combined with increased inventory levels, caused a significant decline in diesel and jet fuel margins in the third quarter and first nine months of 2009 compared to the corresponding periods of 2008. However, margins on other refined products were generally favorable in 2009 compared to 2008. Although overall gasoline margins were somewhat lower in the third quarter of 2009 compared to the third quarter of 2008, they were favorable in all of our regions for the first nine months of 2009 compared to the same period of 2008. 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 third quarter and first nine months of 2009 compared to 2008.

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 third quarter and first nine months of 2009 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 addition, high prices of residual fuel oil relative to sweet crude oil prices caused a significant reduction in discounts realized on residual fuel oil that we processed during the third quarter and first nine months of 2009. These higher residual fuel oil

48

prices also contributed to the decrease in sour crude oil differentials because sour crude oil competes with residual fuel oil as a refinery feedstock.

In March 2009, we issued $750 million of 10-year notes and $250 million of 30-year notes. Proceeds from these notes were 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 $49 million and $71 million of operating income for the three and nine months ended September 30, 2009, respectively.

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.

49

RESULTS OF OPERATIONS

Third Quarter 2009 Compared to Third Quarter 2008

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

	Three Months Ended September 30,
	2009 (a)			2008			Change
Operating revenues	$	19,489		$	35,960		$	(16,471	)
Costs and expenses:
Cost of sales		18,104			32,506			(14,402	)
Operating expenses		923			1,136			(213	)
Retail selling expenses		182			201			(19	)
General and administrative expenses		167			169			(2	)
Depreciation and amortization expense:
Refining		345			331			14
Retail		25			28			(3	)
Ethanol		7			–			7
Corporate		12			11			1
Asset impairment loss (b)		417			43			374
Gain on sale of Krotz Springs Refinery		–			(305	)		305
Total costs and expenses		20,182			34,120			(13,938	)
Operating income (loss)		(693	)		1,840			(2,533	)
Other income, net		9			36			(27	)
Interest and debt expense:
Incurred		(149	)		(112	)		(37	)
Capitalized		19			31			(12	)
Income (loss) before income tax expense (benefit)		(814	)		1,795			(2,609	)
Income tax expense (benefit)		(185	)		643			(828	)
Net income (loss)	$	(629	)	$	1,152		$	(1,781	)
Earnings (loss) per common share – assuming dilution	$	(1.12	)	$	2.18		$	(3.30	)

See the footnote references on page 54.

50

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

	Three Months Ended September 30,
	2009			2008			Change
Refining:
Operating income (loss)	$	(674	)	$	1,913		$	(2,587	)
Throughput margin per barrel (c)	$	4.86		$	13.11		$	(8.25	)
Operating costs per barrel (b):
Refining operating expenses	$	3.94		$	4.78		$	(0.84	)
Depreciation and amortization		1.58			1.39			0.19
Total operating costs per barrel	$	5.52		$	6.17		$	(0.65	)
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		443			565			(122	)
Medium/light sour crude		544			670			(126	)
Acidic sweet crude		24			75			(51	)
Sweet crude		676			578			98
Residuals		211			282			(71	)
Other feedstocks		179			136			43
Total feedstocks		2,077			2,306			(229	)
Blendstocks and other		302			281			21
Total throughput volumes		2,379			2,587			(208	)
Yields (thousand barrels per day):
Gasolines and blendstocks		1,207			1,136			71
Distillates		744			906			(162	)
Petrochemicals		72			66			6
Other products (d)		360			464			(104	)
Total yields		2,383			2,572			(189	)
Retail – U.S.:
Operating income	$	79		$	81		$	(2	)
Company-operated fuel sites (average)		998			984			14
Fuel volumes (gallons per day per site)		4,963			4,946			17
Fuel margin per gallon	$	0.231		$	0.273		$	(0.042	)
Merchandise sales	$	315		$	292		$	23
Merchandise margin (percentage of sales)		28.7	%		29.8	%		(1.1	)%
Margin on miscellaneous sales	$	22		$	24		$	(2	)
Retail selling expenses	$	120		$	134		$	(14	)
Depreciation and amortization expense	$	17		$	18		$	(1	)
Retail – Canada:
Operating income	$	32		$	26		$	6
Fuel volumes (thousand gallons per day)		3,115			3,126			(11	)
Fuel margin per gallon	$	0.263		$	0.261		$	0.002
Merchandise sales	$	58		$	56		$	2
Merchandise margin (percentage of sales)		28.6	%		28.6	%		–	%
Margin on miscellaneous sales	$	10		$	10		$	–
Retail selling expenses	$	62		$	67		$	(5	)
Depreciation and amortization expense	$	8		$	10		$	(2	)

See the footnote references on page 54.

51

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

	Three Months Ended September 30,
	2009		2008		Change
Ethanol (a):
Operating income	$	49		N/A	$	49
Ethanol production (thousand gallons per day)		2,116		N/A		2,116
Gross margin per gallon of ethanol production	$	0.59		N/A	$	0.59
Operating costs per gallon of ethanol production:
Ethanol operating expenses	$	0.31		N/A	$	0.31
Depreciation and amortization		0.03		N/A		0.03
Total operating costs per gallon of ethanol production	$	0.34		N/A	$	0.34

See the footnote references on page 54.

52

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

	Three Months Ended September 30,
	2009			2008			Change
Gulf Coast:
Operating income (loss)	$	(81	)	$	1,159		$	(1,240	)
Throughput volumes (thousand barrels per day)		1,238			1,324			(86	)
Throughput margin per barrel (c)	$	4.66		$	13.21		$	(8.55	)
Operating costs per barrel (b):
Refining operating expenses	$	3.81		$	4.83		$	(1.02	)
Depreciation and amortization		1.57			1.37			0.20
Total operating costs per barrel	$	5.38		$	6.20		$	(0.82	)
Mid-Continent:
Operating income	$	5		$	296		$	(291	)
Throughput volumes (thousand barrels per day)		374			426			(52	)
Throughput margin per barrel (c)	$	5.38		$	13.23		$	(7.85	)
Operating costs per barrel (b):
Refining operating expenses	$	3.69		$	4.41		$	(0.72	)
Depreciation and amortization		1.53			1.28			0.25
Total operating costs per barrel	$	5.22		$	5.69		$	(0.47	)
Northeast:
Operating income (loss)	$	(134	)	$	387		$	(521	)
Throughput volumes (thousand barrels per day)		485			552			(67	)
Throughput margin per barrel (c)	$	2.86		$	13.53		$	(10.67	)
Operating costs per barrel (b):
Refining operating expenses	$	4.26		$	4.54		$	(0.28	)
Depreciation and amortization		1.59			1.36			0.23
Total operating costs per barrel	$	5.85		$	5.90		$	(0.05	)
West Coast:
Operating income	$	67		$	114		$	(47	)
Throughput volumes (thousand barrels per day)		282			285			(3	)
Throughput margin per barrel (c)	$	8.51		$	11.60		$	(3.09	)
Operating costs per barrel (b):
Refining operating expenses	$	4.35		$	5.53		$	(1.18	)
Depreciation and amortization		1.58			1.70			(0.12	)
Total operating costs per barrel	$	5.93		$	7.23		$	(1.30	)
Operating income (loss) for regions above	$	(143	)	$	1,956		$	(2,099	)
Asset impairment loss applicable to refining		(417	)		(43	)		(374	)
Loss contingency accrual related to Aruban tax matter (f)		(114	)		–			(114	)
Total refining operating income (loss)	$	(674	)	$	1,913		$	(2,587	)

See the footnote references on page 54.

53

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

	Three Months Ended September 30,
	2009		2008		Change
Feedstocks:
West Texas Intermediate (WTI) crude oil	$	68.18	$	117.83	$	(49.65	)
WTI less sour crude oil at U.S. Gulf Coast (h)		1.72		4.05		(2.33	)
WTI less Mars crude oil		1.78		5.26		(3.48	)
WTI less Maya crude oil		5.01		11.36		(6.35	)
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		7.85		12.13		(4.28	)
No. 2 fuel oil less WTI		4.53		19.27		(14.74	)
Ultra-low-sulfur diesel less WTI		6.99		23.91		(16.92	)
Propylene less WTI		8.22		7.21		1.01
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		8.11		8.62		(0.51	)
Low-sulfur diesel less WTI		8.01		25.55		(17.54	)
U.S. Northeast:
Conventional 87 gasoline less WTI		8.34		5.80		2.54
No. 2 fuel oil less WTI		4.95		19.86		(14.91	)
Lube oils less WTI		28.89		89.33		(60.44	)
U.S. West Coast:
CARBOB 87 gasoline less WTI		18.00		11.28		6.72
CARB diesel less WTI		9.29		22.94		(13.65	)

The following notes relate to references on pages 50 through 54.
(a)	The information presented for the three months ended September 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.
(b)	The asset impairment loss for the three months ended September 30, 2009 relates primarily to charges of approximately $340 million resulting from the permanent shutdown of the gasification unit at our Delaware City Refinery. The remaining loss for the three months ended September 30, 2009 relates to the permanent cancellation of certain capital projects classified as “construction in progress” as a result of the unfavorable impact of the continuing economic slowdown on refining industry fundamentals. Losses resulting from the permanent cancellation of certain capital projects in prior periods have been reclassified from operating expenses and presented separately for comparability with the third quarter 2009 presentation. The asset impairment loss amounts have been excluded from operating costs in determining operating costs per barrel, resulting in an adjustment to the operating costs per barrel previously reported in 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, 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. In addition, the gain on the sale of the Krotz Springs Refinery to Alon Refining Krotz Springs, Inc. (Alon), a subsidiary of Alon USA Energy, Inc. effective July 1, 2008 is included in the operating income of the Gulf Coast refining region for the third quarter of 2008.
(f)	A loss contingency accrual of $140 million ($0.25 per share) was recorded in the third quarter of 2009 related to our dispute with the Government of Aruba regarding a turnover tax on export sales as well as other tax matters. The portion of the loss contingency accrual that relates to the turnover tax was recorded in cost of sales for the three months ended September 30, 2009, and therefore is included in refining operating income (loss) but has been excluded in determining throughput margin per barrel.

54

(g)

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.

(h)

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

General

Operating revenues decreased 46% for the third quarter of 2009 compared to the third quarter of 2008 primarily as a result of lower refined product prices between the two periods. Operating income declined $2.5 billion and net income decreased $1.8 billion for the three months ended September 30, 2009 compared to amounts reported for the three months ended September 30, 2008 primarily due to a $2.6 billion decrease in refining segment operating income discussed below.

Refining

Results of operations of our refining segment decreased from operating income of $1.9 billion for the third quarter of 2008 to an operating loss of $674 million for the third quarter of 2009. The decrease in operating income was attributable to a $374 million increase in asset impairment losses (as further discussed in Note 4 of Condensed Notes to Consolidated Financial Statements), a $305 million gain on the sale of the Krotz Springs Refinery in the third quarter of 2008 (as further discussed in Note 3 of Condensed Notes to Consolidated Financial Statements), a $114 million loss contingency accrual recorded in the third quarter of 2009 related to our dispute of a turnover tax on export sales in Aruba (as further discussed in Note 14 of Condensed Notes to Consolidated Financial Statements), a 63% decrease in throughput margin per barrel, and an 8% decline in throughput volumes, partially offset by an 18% decrease in refining operating expenses (including depreciation and amortization expense).

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

• Distillate margins in the third quarter of 2009 decreased significantly in all of our refining regions from the high margins in the third 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.

• Sour crude oil and residual fuel oil feedstock differentials to WTI crude oil during the third quarter of 2009 declined significantly compared to the differentials in the third quarter of 2008. The unfavorable sour crude oil differentials were attributable mainly to reduced production of sour crude oil by OPEC and other producers as well as high relative prices for residual fuel oil with which sour crude oil competes as a refinery feedstock. The high relative residual fuel oil prices, and resulting narrow residual fuel oil discounts, were caused by lower production of residual fuel oil attributable to reduced refinery throughput due to lower refined product demand. This reduced supply more than offset the effect of reduced worldwide demand for residual fuel oil.

• Margins on various secondary refined products such as asphalt, fuel oils, and petroleum coke improved significantly from the third quarter of 2008 to the third 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. The price of West Texas Intermediate crude oil declined by approximately $50 per barrel, or 42%, from the third quarter of 2008 to the third quarter of 2009.

55

• Throughput volumes decreased 208,000 barrels per day during the third quarter of 2009 compared to the third quarter of 2008 primarily due to the temporary shutdown of our Aruba Refinery commencing in July 2009 and 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 24% lower for the quarter ended September 30, 2009 compared to the quarter ended September 30, 2008 primarily due to a significant decrease in energy costs. Refining depreciation and amortization expense increased 4% from the third quarter of 2008 to the third quarter of 2009 primarily due to the completion of new capital projects.

Retail

Retail operating income was $111 million for the quarter ended September 30, 2009 compared to $107 million for the quarter ended September 30, 2008. The increase in operating income was primarily due to a $6 million increase in our Canadian retail operations resulting mainly from lower selling expenses. In our U.S. retail operations, a $0.042 per gallon decrease in fuel margins was offset by lower selling expenses.

Ethanol

Ethanol operating income was $49 million for the quarter ended September 30, 2009, which represents the operations of the seven ethanol plants acquired in the second quarter of 2009 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, reflected almost no change from the third quarter of 2008 to the third quarter of 2009 as reductions in variable compensation expense, insurance expense, and tax expense were offset by increased litigation costs.

Other income for the third quarter of 2009 decreased from the third quarter of 2008 due mainly to a $16 million unfavorable change in fair value adjustments related to the Alon earn-out agreement and associated derivative instruments, as discussed in Notes 3, 10, and 11 of Condensed Notes to Consolidated Financial Statements, and reduced interest income resulting from lower cash balances and interest rates.

Interest and debt expense increased from the third quarter of 2008 to the third quarter of 2009 due mainly to interest incurred in the third quarter of 2009 on $1 billion of notes issued in March 2009, a $6 million charge in the third quarter of 2009 to write off a pro rata portion of the unamortized fair value adjustment related to $76 million of 6.75% putable senior notes for which we received purchase notices from the holders of the notes, as discussed in Note 6 of Condensed Notes to Consolidated Financial Statements, and decreased capitalized interest due to the cancellation or deferral of various capital projects.

Income tax expense decreased $828 million from $643 million of expense in the third quarter of 2008 to a $185 million benefit in the third quarter of 2009 mainly as a result of lower operating income.

56

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

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

	Nine Months Ended September 30,
	2009 (a)			2008 (b)			Change
Operating revenues	$	51,238		$	100,545		$	(49,307	)
Costs and expenses:
Cost of sales		46,275			91,848			(45,573	)
Operating expenses		2,778			3,383			(605	)
Retail selling expenses		522			579			(57	)
General and administrative expenses		435			421			14
Depreciation and amortization expense:
Refining		1,035			998			37
Retail		74			77			(3	)
Ethanol		12			–			12
Corporate		35			31			4
Asset impairment loss (c)		575			43			532
Gain on sale of Krotz Springs Refinery		–			(305	)		305
Total costs and expenses		51,741			97,075			(45,334	)
Operating income (loss)		(503	)		3,470			(3,973	)
Other income (expense), net		(16	)		71			(87	)
Interest and debt expense:
Incurred		(386	)		(335	)		(51	)
Capitalized		95			74			21
Income (loss) before income tax expense (benefit)		(810	)		3,280			(4,090	)
Income tax expense (benefit)		(236	)		1,133			(1,369	)
Net income (loss)	$	(574	)	$	2,147		$	(2,721	)
Earnings (loss) per common share – assuming dilution	$	(1.08	)	$	4.02		$	(5.10	)

See the footnote references on page 61.

57

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

	Nine Months Ended September 30,
	2009			2008			Change
Refining (b):
Operating income (loss)	$	(335	)	$	3,716		$	(4,051	)
Throughput margin per barrel (d)	$	6.09		$	10.80		$	(4.71	)
Operating costs per barrel (c):
Refining operating expenses	$	4.01		$	4.66		$	(0.65	)
Depreciation and amortization		1.55			1.38			0.17
Total operating costs per barrel	$	5.56		$	6.04		$	(0.48	)
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		489			580			(91	)
Medium/light sour crude		582			680			(98	)
Acidic sweet crude		80			76			4
Sweet crude		619			622			(3	)
Residuals		193			242			(49	)
Other feedstocks		177			141			36
Total feedstocks		2,140			2,341			(201	)
Blendstocks and other		305			306			(1	)
Total throughput volumes		2,445			2,647			(202	)
Yields (thousand barrels per day):
Gasolines and blendstocks		1,176			1,197			(21	)
Distillates		789			920			(131	)
Petrochemicals		67			74			(7	)
Other products (e)		409			449			(40	)
Total yields		2,441			2,640			(199	)
Retail – U.S.:
Operating income	$	140		$	120		$	20
Company-operated fuel sites (average)		1,001			961			40
Fuel volumes (gallons per day per site)		5,022			4,997			25
Fuel margin per gallon	$	0.157		$	0.173		$	(0.016	)
Merchandise sales	$	888		$	819		$	69
Merchandise margin (percentage of sales)		29.2	%		30.0	%		(0.8	)%
Margin on miscellaneous sales	$	66		$	74		$	(8	)
Retail selling expenses	$	349		$	375		$	(26	)
Depreciation and amortization expense	$	52		$	51		$	1
Retail – Canada:
Operating income	$	92		$	86		$	6
Fuel volumes (thousand gallons per day)		3,155			3,169			(14	)
Fuel margin per gallon	$	0.255		$	0.278		$	(0.023	)
Merchandise sales	$	146		$	156		$	(10	)
Merchandise margin (percentage of sales)		29.1	%		28.5	%		0.6	%
Margin on miscellaneous sales	$	25		$	29		$	(4	)
Retail selling expenses	$	173		$	204		$	(31	)
Depreciation and amortization expense	$	22		$	26		$	(4	)

See the footnote references on page 61.

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

	Nine Months Ended September 30,
	2009		2008		Change
Ethanol (a):
Operating income	$	71		N/A	$	71
Ethanol production (thousand gallons per day)		1,229		N/A		1,229
Gross margin per gallon of ethanol production	$	0.55		N/A	$	0.55
Operating costs per gallon of ethanol production:
Ethanol operating expenses	$	0.31		N/A	$	0.31
Depreciation and amortization		0.03		N/A		0.03
Total operating costs per gallon of ethanol production	$	0.34		N/A	$	0.34

See the footnote references on page 61.

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

	Nine Months Ended September 30,
	2009			2008			Change
Gulf Coast (b):
Operating income	$	28		$	2,639		$	(2,611	)
Throughput volumes (thousand barrels per day)		1,316			1,399			(83	)
Throughput margin per barrel (d)	$	5.22		$	12.01		$	(6.79	)
Operating costs per barrel (c):
Refining operating expenses	$	3.65		$	4.62		$	(0.97	)
Depreciation and amortization		1.49			1.30			0.19
Total operating costs per barrel	$	5.14		$	5.92		$	(0.78	)
Mid-Continent:
Operating income	$	197		$	514		$	(317	)
Throughput volumes (thousand barrels per day)		381			426			(45	)
Throughput margin per barrel (d)	$	7.18		$	9.94		$	(2.76	)
Operating costs per barrel (c):
Refining operating expenses	$	3.72		$	4.25		$	(0.53	)
Depreciation and amortization		1.57			1.29			0.28
Total operating costs per barrel	$	5.29		$	5.54		$	(0.25	)
Northeast:
Operating income (loss)	$	(203	)	$	357		$	(560	)
Throughput volumes (thousand barrels per day)		467			545			(78	)
Throughput margin per barrel (d)	$	4.94		$	8.50		$	(3.56	)
Operating costs per barrel (c):
Refining operating expenses	$	4.90		$	4.69		$	0.21
Depreciation and amortization		1.62			1.42			0.20
Total operating costs per barrel	$	6.52		$	6.11		$	0.41
West Coast:
Operating income	$	331		$	249		$	82
Throughput volumes (thousand barrels per day)		281			277			4
Throughput margin per barrel (d)	$	10.59		$	10.55		$	0.04
Operating costs per barrel (c):
Refining operating expenses	$	4.60		$	5.50		$	(0.90	)
Depreciation and amortization		1.67			1.76			(0.09	)
Total operating costs per barrel	$	6.27		$	7.26		$	(0.99	)
Operating income for regions above	$	353		$	3,759		$	(3,406	)
Asset impairment loss applicable to refining		(574	)		(43	)		(531	)
Loss contingency accrual related to Aruban tax matter (g)		(114	)		–			(114	)
Total refining operating income (loss)	$	(335	)	$	3,716		$	(4,051	)

See the footnote references on pages 61 and 62.

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

	Nine Months Ended September 30,
	2009			2008			Change
Feedstocks:
WTI crude oil	$	56.90		$	113.25		$	(56.35	)
WTI less sour crude oil at U.S. Gulf Coast (i)		1.25			5.20			(3.95	)
WTI less Mars crude oil		1.06			6.40			(5.34	)
WTI less Maya crude oil		4.68			16.39			(11.71	)
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		8.85			7.66			1.19
No. 2 fuel oil less WTI		6.40			19.17			(12.77	)
Ultra-low-sulfur diesel less WTI		8.59			24.38			(15.79	)
Propylene less WTI		(3.05	)		(0.11	)		(2.94	)
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		9.09			6.49			2.60
Low-sulfur diesel less WTI		8.63			25.10			(16.47	)
U.S. Northeast:
Conventional 87 gasoline less WTI		8.78			4.62			4.16
No. 2 fuel oil less WTI		7.68			20.85			(13.17	)
Lube oils less WTI		40.54			51.75			(11.21	)
U.S. West Coast:
CARBOB 87 gasoline less WTI		18.40			12.13			6.27
CARB diesel less WTI		10.30			24.57			(14.27	)

The following notes relate to references on pages 57 through 61.
(a)	The information presented for the nine months ended September 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 nine months ended September 30, 2009 are based on 273 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 nine months ended September 30, 2008.
(c)	The asset impairment loss for the nine months ended September 30, 2009 relates primarily to charges of approximately $340 million resulting from the permanent shutdown of the gasification unit at our Delaware City Refinery. The remaining loss for the nine months ended September 30, 2009 relates to the permanent cancellation of certain capital projects classified as “construction in progress” as a result of the unfavorable impact of the continuing economic slowdown on refining industry fundamentals. Losses resulting from the permanent cancellation of certain capital projects in prior periods have been reclassified from operating expenses and presented separately for comparability with the 2009 presentation. The asset impairment loss amounts have been excluded from operating costs in determining operating costs per barrel, resulting in an adjustment to the operating costs per barrel previously reported in 2008.
(d)	Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.
(e)	Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
(f)	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 (prior to its sale effective July 1, 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.

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(g)	A loss contingency accrual of $140 million was recorded in the third quarter of 2009 related to our dispute with the Government of Aruba regarding a turnover tax on export sales as well as other tax matters. The portion of the loss contingency accrual that relates to the turnover tax was recorded in cost of sales for the nine months ended September 30, 2009, and therefore is included in refining operating income (loss) but has been excluded in determining throughput margin per barrel.
(h)	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.
(i)	The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.

General

Operating revenues decreased 49% for the first nine months of 2009 compared to the first nine months of 2008 primarily as a result of lower refined product prices between the two periods. Operating income declined $4.0 billion and net income decreased $2.7 billion for the nine months ended September 30, 2009 compared to the amounts in the first nine months of 2008 primarily due to a $4.1 billion decrease in refining segment operating income discussed below.

Refining

Operating income for our refining segment decreased from operating income of $3.7 billion for the first nine months of 2008 to an operating loss of $335 million for the first nine months of 2009. The decrease in operating income was attributable to a $532 million increase in asset impairment losses (as further discussed in Note 4 of Condensed Notes to Consolidated Financial Statements), a $305 million gain on the sale of the Krotz Springs Refinery in the third quarter of 2008 (as further discussed in Note 3 of Condensed Notes to Consolidated Financial Statements), a $114 million loss contingency accrual recorded in the third quarter of 2009 related to our dispute of a turnover tax on export sales in Aruba (as further discussed in Note 14 of Condensed Notes to Consolidated Financial Statements), a 44% decrease in throughput margin per barrel, and an 8% decline in throughput volumes, partially offset by a 15% decrease in refining operating expenses (including depreciation and amortization expense).

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

• Distillate margins in the first nine months of 2009 decreased significantly in all of our refining regions from the high margins in the first nine 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 and residual fuel oil feedstock differentials to WTI crude oil during the first nine months of 2009 declined significantly compared to the differentials in the first nine months of 2008. The unfavorable sour crude oil differentials were attributable mainly to reduced production of sour crude oil by OPEC and other producers as well as high relative prices for residual fuel oil with which sour crude oil competes as a refinery feedstock. The high relative residual fuel oil prices, and resulting narrow residual fuel oil discounts, were caused by lower production of residual fuel oil attributable to reduced refinery throughput due to lower refined product demand. This reduced supply more than offset the effect of reduced worldwide demand for residual fuel oil.

• Gasoline margins increased in all of our refining regions in the first nine months of 2009 compared to the first nine months of 2008 primarily due to a better balance of supply and demand.

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• Margins on various secondary refined products such as asphalt, fuel oils, and petroleum coke improved significantly from the first nine months of 2008 to the first nine 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. The price of West Texas Intermediate crude oil declined by approximately $56 per barrel, or 50%, from the first nine months of 2008 to the first nine months of 2009.

• Throughput margin for the first nine months of 2008 included approximately $100 million related to the McKee Refinery business interruption insurance settlement discussed in Note 14 of Condensed Notes to Consolidated Financial Statements.

• Throughput volumes decreased 202,000 barrels per day during the first nine months of 2009 compared to the first nine 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, (iv) the temporary shutdown of our Aruba Refinery commencing in July 2009, and (v) 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 21% lower for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008 primarily due to a decrease in energy costs, lower maintenance expenses, a reduction in sales and use taxes, lower variable compensation and overtime costs, and $43 million of operating expenses related to the Krotz Springs Refinery prior to its sale effective July 1, 2008. Refining depreciation and amortization expense increased 4% from the first nine months of 2008 to the first nine months of 2009 primarily due to the completion of new capital projects and increased turnaround and catalyst amortization.

Retail

Retail operating income was $232 million for the nine months ended September 30, 2009 compared to $206 million for the nine months ended September 30, 2008. This 13% increase was primarily due to increased in-store sales and lower selling expenses, partially offset by a $0.016 per gallon decrease in fuel margins, in our U.S. retail operations.

Ethanol

Ethanol operating income was $71 million for the nine months ended September 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 $18 million from the first nine months of 2008 to the first nine months of 2009 due mainly to increases in litigation costs, severance expenses, and costs associated with the VeraSun Acquisition, partially offset by lower variable compensation expense and reductions in insurance expense, professional fees, and environmental costs.

Other income for the first nine months of 2009 decreased from the first nine months of 2008 primarily due to a $53 million unfavorable change in fair value adjustments related to the Alon earn-out agreement and associated derivative instruments (as discussed in Notes 3, 10, and 11 of Condensed Notes to Consolidated Financial Statements), reduced interest income resulting from lower cash balances and

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interest rates, and the nonrecurrence of a $14 million gain recognized in the first nine months of 2008 on the redemption of our 9.5% senior notes as discussed in Note 6 of Condensed Notes to Consolidated Financial Statements.

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

Income tax expense decreased $1.4 billion from $1.1 billion of expense for the first nine months of 2008 to a $236 million benefit for the first nine 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, 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 with a resulting increase in refined product margins and sour crude oil differentials.

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. These facilities continue to be temporarily shut down, and they are expected to remain shut down until economic conditions improve. In addition, in September, we permanently shut down the gasification unit at our Delaware City Refinery. 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. Although feedstock discounts have improved recently, refined product margins have weakened, so we expect overall throughput margins for the fourth quarter to be similar to what we experienced in the third quarter, which could result in losses in the fourth quarter and for the full year of 2009.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Nine Months Ended September 30, 2009 and 2008
Net cash provided by operating activities for the nine months ended September 30, 2009 was $1.9 billion compared to $3.5 billion for the nine months ended September 30, 2008. The decrease in cash generated from operating activities was primarily due to the cash utilization attributable to the decrease in operating income discussed above under “Results of Operations,” partially offset by an approximate $1.2 billion 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 nine months of 2009 and 2008 are shown in Note 9 of Condensed Notes to Consolidated Financial Statements. Both receivables and accounts payable increased for the first nine months of 2009 due mainly to a significant increase in gasoline, distillate, and crude oil prices at September 30, 2009 compared to such prices at the end of 2008.

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The net cash generated from operating activities during the first nine months of 2009, combined with $998 million of proceeds from the issuance of $1 billion of notes in March 2009 as discussed in Note 6 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 7 of Condensed Notes to Consolidated Financial Statements, were used mainly to:

• fund $2.1 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 $239 million; and

• increase available cash on hand by $665 million.

The net cash generated from operating activities during the first nine months of 2008, combined with $463 million of proceeds from the sale of our Krotz Springs Refinery, were used mainly to:

• fund $2.2 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 14.6 million shares of our common stock at a cost of $774 million;

• fund a $25 million contingent earn-out payment in connection with the acquisition of the St. Charles Refinery, an $87 million acquisition of retail fuel sites, and a $57 million acquisition primarily of an interest in a refined product pipeline;

• pay common stock dividends of $221 million; and

• increase available cash on hand by $303 million.

Capital Investments
During the nine months ended September 30, 2009, we expended $1.8 billion for capital expenditures and $301 million for deferred turnaround and catalyst costs. Capital expenditures for the nine months ended September 30, 2009 included $292 million of costs related to environmental projects.

For 2009, we expect to incur approximately $2.7 billion for capital investments, including approximately $2.2 billion for capital expenditures (approximately $475 million of which is for environmental projects) and approximately $500 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 September 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 $998 million, before deducting underwriting discounts and other issuance costs of $8 million.

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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 September 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) was received from the holders prior to September 15, 2009. A purchase notice was received related to $76 million of the outstanding notes. We redeemed the $76 million of notes at 100% of their principal amount plus accrued and unpaid interest to October 15, 2009, the date of the 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 extended through December 31, 2009 and provided 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 and in September 2009, Total completed its acquisition of Dow’s equity interest in TRN. Our obligations under the Agreement have since been terminated.

Other than the TRN Refinery commitment discussed above, during the nine months ended September 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 September 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 (negative 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.

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

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

In October 2009, Lehman Brothers Bank, FSB, one of the participating banks under our $2.5 billion revolving credit facility, failed to fund its loan commitment related to our borrowing under this facility discussed below. Lehman Brothers’ aggregate commitment under the revolving credit facility was $84 million. As a result, our borrowing capacity under that revolving credit facility has been reduced to$2.4 billion commencing in October 2009.

As of September 30, 2009, we had no amounts borrowed under our revolving credit facilities. However, we had $76 million of letters of credit outstanding under our uncommitted short-term bank credit facilities and $113 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 September 30, 2009. Our letters of credit expire during 2009 and 2010. In October 2009, we borrowed and subsequently repaid approximately $40 million under our U.S. committed revolving bank credit facility.

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.

Stock Purchase Programs
As of September 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 14 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 (NAI) pursuant to which we sought 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 also filed protests of these assessments through proceedings in Aruba.

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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. Amounts deposited under the escrow agreement, which totaled $114 million and $102 million as of September 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 $20 million related to dividends. We have also challenged approximately $35 million in foreign exchange payments made to the Central Bank of Aruba as payments exempted under our tax holiday, as well as other reasons. Both the dividend tax and the foreign exchange payment matters were also addressed in the arbitration proceedings discussed above.

On November 3, we received an interim First Partial Award from the NAI arbitral panel. The panel’s ruling validated our tax holiday agreement, but the panel also ruled in favor of the GOA on our dispute of the $35 million in foreign exchange payments previously made to the Central Bank of Aruba. The panel’s decision did not, however, fully resolve the remaining two items in the arbitration, the applicable dividend tax rate and the turnover tax. With respect to the dividend tax, the panel ruled that the dividend tax was not a profit tax covered by the tax holiday agreement, but the panel did not address the fact that Aruban companies with tax holidays are subject to a 0% dividend withholding rate rather than the 5% rate alleged by the GOA. With respect to the turnover tax, the panel did reject our contractual claims but it decided that our non-contractual claims against the turnover tax merited further discussion with and review by the panel before a final decision could be rendered. Prior to this interim decision, no expense or liability had been recognized in our consolidated financial statements with respect to unfunded amounts. In light of the now uncertain timing of any final resolution of these claims, we have recorded a loss contingency accrual of approximately $140 million, including interest, with respect to both the dividend and turnover taxes. We continue to believe that our remaining claims against these taxes have significant merit, and intend to vigorously pursue these claims through the arbitration proceedings and in on-island proceedings as well.

Asset Impairments
Long-lived assets are 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.

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 second half 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

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conditions during 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 nine months of 2009, thereby impacting 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 September 30, 2009, as narrow heavy sour crude oil differentials made the refinery uneconomical to operate. The Aruba Refinery was shut down in July 2009 and is expected to continue to be shut down until market conditions improve. We are continuing to evaluate potential alternatives 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 and remains shut down. In September 2009, we announced the shutdown of our coker and gasification units at our Delaware City Refinery also due to economic reasons. The coker unit is expected to remain shut down until economics improve and the gasification unit has been permanently shut down. As a result of these factors, we readdressed the potential impairment of all of our facilities (excluding the Delaware City gasification unit) as of September 30, 2009 based on an assumption that we would operate these facilities in the future, 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 September 30, 2009. However, due to the permanent shutdown of the gasification unit at the Delaware City Refinery, we recorded a pre-tax loss of approximately $280 million related to the abandonment of that unit.

Due to the impact of the continuing economic slowdown on refining industry fundamentals, we further evaluated the recoverability of all of our capital projects currently classified as “construction in progress” during the third quarter of 2009. This is a continuation of an ongoing process that had commenced during the second half of 2008. As a result of this assessment, certain additional capital projects were permanently cancelled, resulting in write-offs of $137 million of project costs for the three months ended September 30, 2009 (of which approximately $60 million was for projects related to the gasification unit at our Delaware City Refinery). This amount, combined with capital projects written off earlier in 2009, has resulted in total write-offs of capital projects of $295 million for the nine months ended September 30, 2009.

In addition to capital projects that have been written off, 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 temporarily suspended until market conditions and cash flows improve. As of September 30, 2009, approximately $1.0 billion of costs had been incurred on these two projects. In addition, various other projects with a total cost of approximately $600 million as of September 30, 2009 have also been temporarily suspended. These suspended projects are included in our strategic plan, and the costs incurred to date have not been written off. We believe that the overall market conditions and our cash flows will improve in the future such that the completion and recoverability of these temporarily suspended projects is probable.

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 additional potential asset impairments until conditions improve. Changes in market conditions, as well as changes in assumptions used to test for recoverability and to determine fair value, could result in additional significant impairment charges in the future, thus affecting our earnings.

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American Clean Energy and Security Act of 2009 and Clean Energy Jobs and American Power Act of 2009
On June 26, 2009, the U.S. House of Representatives narrowly approved the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey bill. On September 30, 2009, the U.S. Senate Committee on Environment and Public Works introduced a similar bill in the Senate, the Clean Energy Jobs and American Power Act of 2009, also known as the Kerry-Boxer bill. These bills, if passed by Congress, would establish a national “cap-and-trade” program beginning in 2012 to address greenhouse gas emissions and climate change. The Waxman-Markey bill 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, while the Kerry-Boxer bill proposes a more accelerated timetable for carbon dioxide reductions. The cap-and-trade program would require businesses that emit greenhouse gases to buy 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 would 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 a cap-and-trade bill (or whether such a bill will be passed by Congress), any new federal restrictions on greenhouse gas emissions – including a cap-and-trade program – could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have an adverse effect on our financial position, results of operations, and liquidity.

Other
During the nine months ended September 30, 2009, we contributed $72 million to our qualified pension plans. No additional contributions to the qualified pension plans are anticipated during 2009.

On October 15, 2009, our board of directors declared a regular quarterly cash dividend of $0.15 per common share payable on December 9, 2009 to holders of record at the close of business on November 11, 2009. At the same time, we announced that if industry conditions do not improve measurably for 2010, our board of directors would evaluate a reduction in the amount of our quarterly dividend payment.

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.

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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 11 of Condensed Notes to Consolidated Financial Statements. The following tables provide information about our commodity derivative instruments as of September 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 September 30, 2009 and December 31, 2008, respectively, and a fair value of $7.4 billion and $5.1 billion as of September 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; and

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

In addition, through August 2009, we used economic hedges to manage price volatility in the referenced product margins associated with the three-year earn-out agreement with Alon that was entered into in connection with the sale of our Krotz Springs Refinery, but which was settled in the third quarter of 2009 as discussed in Note 3 of Condensed Notes to Consolidated Financial Statements. 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 commodity derivative 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

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

	September 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)		5,133		N/A	$	71.05	$	364	$	364		$	–
Cash Flow Hedges:
Swaps – long:
2009 (crude oil and refined products)		10,722	$	99.45		74.59		N/A		(267	)		(267	)
2010 (crude oil and refined products)		24,810		67.67		77.14		N/A		235			235
Swaps – short:
2009 (crude oil and refined products)		10,722		74.59		107.41		N/A		352			352
2010 (crude oil and refined products)		24,810		80.16		72.65		N/A		(186	)		(186	)
Futures – long:
2009 (crude oil and refined products)		1,218		66.46		N/A		81		86			5
Economic Hedges:
Swaps – long:
2009 (crude oil and refined products)		45,030		25.21		21.70		N/A		(158	)		(158	)
2010 (crude oil and refined products)		107,194		31.37		26.58		N/A		(513	)		(513	)
2011 (crude oil and refined products)		26,275		21.55		14.49		N/A		(186	)		(186	)
Swaps – short:
2009 (crude oil and refined products)		20,458		47.93		57.57		N/A		197			197
2010 (crude oil and refined products)		63,633		47.78		58.42		N/A		677			677
2011 (crude oil and refined products)		11,025		34.68		52.45		N/A		196			196
Futures – long:
2009 (crude oil and refined products)		222,053		70.61		N/A		15,678		16,153			475
2010 (crude oil and refined products)		102,235		75.79		N/A		7,748		8,189			441
2009 (grain)		3,705		3.20		N/A		12		13			1
2010 (grain)		75		4.03		N/A		–		–			–
Futures – short:
2009 (crude oil and refined products)		216,315		N/A		71.20		15,401		15,767			(366	)
2010 (crude oil and refined products)		101,388		N/A		74.63		7,567		7,998			(431	)
2009 (grain)		10,585		N/A		3.51		37		36			1
2010 (grain)		4,495		N/A		4.26		19		16			3
Options – long:
2009 (crude oil and refined products)		6		37.94		N/A		–		–			–
2010 (crude oil and refined products)		511		40.44		N/A		1		1			–
Options – short:
2010 (crude oil and refined products)		500		N/A		42.50		2		1			1

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	September 30, 2009
			Wtd Avg		Wtd Avg							Pre-tax
	Contract		Pay		Receive		Contract		Market			Fair
	Volumes		Price		Price		Value		Value			Value
Trading Activities:
Swaps – long:
2009 (crude oil and refined products)		6,502	$	48.69	$	37.91		N/A	$	(70	)	$	(70	)
2010 (crude oil and refined products)		23,589		21.20		24.20		N/A		71			71
2011 (crude oil and refined products)		3,000		53.70		56.64		N/A		9			9
Swaps – short:
2009 (crude oil and refined products)		5,679		42.57		56.44		N/A		79			79
2010 (crude oil and refined products)		27,946		20.62		20.05		N/A		(16	)		(16	)
2011 (crude oil and refined products)		3,900		43.57		43.29		N/A		(1	)		(1	)
Futures – long:
2009 (crude oil and refined products)		25,809		76.91		N/A	$	1,985		1,887			(98	)
2010 (crude oil and refined products)		4,318		77.88		N/A		336		343			7
2009 (natural gas)		3,750		5.59		N/A		21		21			–
2010 (natural gas)		100		6.10		N/A		1		1			–
Futures – short:
2009 (crude oil and refined products)		25,859		N/A		77.22		1,997		1,893			104
2010 (crude oil and refined products)		4,268		N/A		76.94		328		338			(10	)
2009 (natural gas)		3,750		N/A		5.37		20		21			(1	)
2010 (natural gas)		100		N/A		5.46		1		1			–
Options – long:
2009 (crude oil and refined products)		40		42.50		N/A		–		–			–
Options – short:
2009 (crude oil and refined products)		40		N/A		17.00		–		–			–
Total pre-tax fair value of open positions												$	551

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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
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 September 30, 2009 and December 31, 2008.

	September 30, 2009
	Expected Maturity Dates
																There-						Fair
	2009			2010			2011			2012			2013			after			Total			Value
Debt:
Fixed rate	$	76		$	33		$	418		$	759		$	489		$	5,521		$	7,296		$	8,235
Average interest rate		6.8	%		6.8	%		6.4	%		6.9	%		5.5	%		7.3	%		7.1	%
Floating rate	$	–		$	100		$	–		$	–		$	–		$	–		$	100		$	100
Average interest rate		–	%		1.1	%		–	%		–	%		–	%		–	%		1.1	%

	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 September 30, 2009, we had commitments to purchase $248 million of U.S. dollars. These commitments matured on or before November 2, 2009, resulting in a $5 million loss in the fourth 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 September 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 quarters ended March 31, 2009 and June 30, 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 14 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) (this matter was last reported in our Form 10-Q for the quarter ended June 30, 2009). On July 9, 2009, the EPA issued a demand for a stipulated penalty under a Section 114 Consent Decree for an acid gas flaring incident in September 2008 at our Paulsboro Refinery. We paid the final penalty amount on August 20, 2009.

EPA(Paulsboro Refinery). In September 2009, the EPA issued a proposed penalty of $211,000 in connection with an alleged unit leak of chlorinated fluorocarbons at our Paulsboro Refinery. We are in negotiations with the EPA to resolve this matter.

Delaware Department of Natural Resources and Environmental Control (DDNREC)(Delaware City Refinery). Our Delaware City Refinery received a stipulated penalty demand from the DDNREC in August 2009 for $200,000, and another in October 2009 for $100,000, for our alleged failure to complete construction of a coke storage and handling system on a timely basis. The refinery received an additional stipulated penalty demand in October 2009 for $250,000 for our alleged failure to timely complete construction on certain FCCU NOx controls. We are filing dispute resolutions at the DDNREC in connection with each of these stipulated penalty demands, and we are negotiating with the DDNREC to resolve these matters.

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New Jersey Department of Environmental Protection (NJDEP)(Paulsboro Refinery). In March 2009 and August 2009, the NJDEP issued an Administrative Order of Revocation and Notice of Administrative Civil Penalty Assessments (Notice) to our Paulsboro Refinery. The first Notice relates to an FCC stack test conducted in 2007. The second Notice relates to an FCC stack test conducted in February 2009. The Notices assess penalties of $40,000 and $285,000, respectively, and direct the Refinery to either perform a new stack test or submit an application to modify the permit limits. We have commenced discussions with the NJDEP to resolve this matter, and we continue to work with the NJDEP on additional stack testing. Appeals and requests for a stay on both Notices have been filed. The stay on the first Notice has been granted, and the request for stay on the second Notice has yet to be ruled on.

Texas Commission on Environmental Quality (TCEQ)(McKee Refinery). In August 2009, our McKee Refinery received an agreed order from the TCEQ with a proposed administrative penalty of $469,251 for a number of self-reported Title V permit deviations that occurred in 2008 and several emission events that occurred in 2009. We have commenced discussions with the TCEQ to resolve this matter.

TCEQ(Port Arthur Refinery) (this matter was last reported in our Form 10-K for the year ended December 31, 2008). In September 2005, we received two enforcement actions from the TCEQ relating to alleged Texas Clean Air Act violations at the Port Arthur Refinery dating back to 2002. In 2007, these enforcement actions were referred to the Texas Attorney General’s office and consolidated with TCEQ Docket No. 2005-1596-AIR-E. In the third quarter 2009, we settled these matters with the Texas Attorney General’s office. The agreed final judgment was filed on September 23, 2009, and this matter is now fully resolved.

TCEQ(Port Arthur Refinery). In October 2009, our Port Arthur Refinery received a proposed Agreed Order from the TCEQ for $155,825 relating to alleged multiple emissions events in 2008 and early 2009. We are reviewing the proposed order and evaluating our options for response.

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.

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

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

          (b) Use of Proceeds. Not applicable.

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

Period	Total		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)
July 2009		1,939	$ 15.92		1,939		–	$ 3.46 billion
August 2009		93	$ 18.60		93		–	$ 3.46 billion
September 2009		1,448	$ 18.90		1,448		–	$ 3.46 billion
Total		3,480	$ 17.23		3,480		–	$ 3.46 billion

(1)

The shares reported in this column represent purchases settled in the third 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 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 September 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.

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SIGNATURE

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

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

Date: November 5, 2009

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