Valero Energy (VLO) 10-Q 2010 Q1 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 March 31, 2010

OR

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

For the transition period from                                                  to                                                   

Commission file number 1-13175

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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

One Valero Way
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 April 30, 2010 was 565,475,748.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

INDEX

	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009		3
Consolidated Statements of Income for the Three Months Ended March 31, 2010 and 2009		4
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009		5
Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2010 and 2009		6
Condensed Notes to Consolidated Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		41
Item 3. Quantitative and Qualitative Disclosures About Market Risk		56
Item 4. Controls and Procedures		62
PART II – OTHER INFORMATION
Item 1. Legal Proceedings		63
Item 1A. Risk Factors		64
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		64
Item 6. Exhibits		65
SIGNATURE		66

2

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

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

	March 31,			December 31,
	2010			2009
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	1,887		$	825
Restricted cash		129			122
Receivables, net		3,947			3,773
Inventories		4,724			4,863
Income taxes receivable		58			888
Deferred income taxes		175			180
Prepaid expenses and other		181			261
Assets held for sale and assets related to discontinued operations		219			224
Total current assets		11,320			11,136
Property, plant and equipment, at cost		29,186			28,463
Accumulated depreciation		(5,851	)		(5,592	)
Property, plant and equipment, net		23,335			22,871
Intangible assets, net		226			227
Deferred charges and other assets, net		1,584			1,395
Total assets	$	36,465		$	35,629
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	635		$	237
Accounts payable		5,986			5,760
Accrued expenses		502			514
Taxes other than income taxes		604			725
Income taxes payable		22			95
Deferred income taxes		186			253
Liabilities related to discontinued operations		160			225
Total current liabilities		8,095			7,809
Debt and capital lease obligations, less current portion		7,718			7,163
Deferred income taxes		4,131			4,063
Other long-term liabilities		1,855			1,869
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 673,501,593 and 673,501,593 shares issued		7			7
Additional paid-in capital		7,879			7,896
Treasury stock, at cost; 108,318,528 and 108,798,847 common shares		(6,688	)		(6,721	)
Retained earnings		13,036			13,178
Accumulated other comprehensive income		432			365
Total stockholders’ equity		14,666			14,725
Total liabilities and stockholders’ equity	$	36,465		$	35,629

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
	March 31,
	2010			2009
Operating revenues (1)	$	19,643		$	13,328
Costs and expenses:
Cost of sales		18,136			11,204
Operating expenses		912			845
Retail selling expenses		173			169
General and administrative expenses		97			145
Depreciation and amortization expense		357			350
Asset impairment loss		–			22
Total costs and expenses		19,675			12,735
Operating income (loss)		(32	)		593
Other income (expense), net		11			(1	)
Interest and debt expense:
Incurred		(147	)		(119	)
Capitalized		20			39
Income (loss) from continuing operations before income tax expense (benefit)		(148	)		512
Income tax expense (benefit)		(47	)		148
Income (loss) from continuing operations		(101	)		364
Loss from discontinued operations, net of income taxes		(12	)		(55	)
Net income (loss)	$	(113	)	$	309
Earnings (loss) per common share:
Continuing operations	$	(0.18	)	$	0.70
Discontinued operations		(0.02	)		(0.10	)
Total	$	(0.20	)	$	0.60
Weighted-average common shares outstanding (in millions)		562			514
Earnings (loss) per common share – assuming dilution:
Continuing operations	$	(0.18	)	$	0.70
Discontinued operations		(0.02	)		(0.11	)
Total	$	(0.20	)	$	0.59
Weighted-average common shares outstanding – assuming dilution (in millions)		562			519
Dividends per common share	$	0.05		$	0.15
Supplemental information:
(1) Includes excise taxes on sales by our U.S. retail system	$	208		$	204

See Condensed Notes to Consolidated Financial Statements.

4

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

	Three Months Ended
	March 31,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	(113	)	$	309
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense		357			378
Asset impairment loss		–			37
Noncash interest expense and other income, net		(1	)		1
Stock-based compensation expense		12			12
Deferred income tax expense		17			169
Changes in current assets and current liabilities		753			(96	)
Changes in deferred charges and credits and other operating activities, net		(43	)		(29	)
Net cash provided by operating activities		982			781
Cash flows from investing activities:
Capital expenditures		(382	)		(735	)
Deferred turnaround and catalyst costs		(229	)		(167	)
Advance payments related to purchase of ethanol facilities		–			(13	)
Purchase of ethanol facilities		(260	)		–
Other investing activities, net		15			6
Net cash used in investing activities		(856	)		(909	)
Cash flows from financing activities:
Non-bank debt:
Borrowings		1,244			998
Repayments		(294	)		–
Accounts receivable sales program:
Proceeds from sale of receivables		1,225			100
Repayments		(1,225	)		(100	)
Purchase of common stock for treasury		(1	)		–
Issuance of common stock in connection with employee benefit plans		4			1
Benefit from tax deduction in excess of recognized stock-based compensation cost		2			1
Common stock dividends		(28	)		(77	)
Debt issuance costs		(10	)		(7	)
Other financing activities		(1	)		(2	)
Net cash provided by financing activities		916			914
Effect of foreign exchange rate changes on cash		20			(11	)
Net increase in cash and temporary cash investments		1,062			775
Cash and temporary cash investments at beginning of period		825			940
Cash and temporary cash investments at end of period	$	1,887		$	1,715

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
	March 31,
	2010			2009
Net income (loss)	$	(113	)	$	309
Other comprehensive income (loss):
Foreign currency translation adjustment		101			(81	)
Pension and other postretirement benefits:
Net gain reclassified into income, net of income tax expense of $- and $-		(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 $1 and $(32)		(1	)		60
Net gain reclassified into income, net of income tax expense of $17 and $21		(32	)		(40	)
Net gain (loss) on cash flow hedges		(33	)		20
Other comprehensive income (loss)		67			(61	)
Comprehensive income (loss)	$	(46	)	$	248

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 months ended March 31, 2010 and 2009 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited consolidated financial statements. Operating results for the three months ended March 31, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010.

The consolidated balance sheet as of December 31, 2009 has been derived from the audited financial statements as of that date. For further information, refer to the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2009.

We have evaluated subsequent events that occurred after March 31, 2010 through the filing of this Form 10-Q. 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 have been reclassified to conform to the 2010 presentation.

As discussed in Note 4, we permanently shut down our Delaware City Refinery in the fourth quarter of 2009, and our board of directors approved a plan of sale for our terminal, pipeline, and shutdown refinery assets at Delaware City in the first quarter of 2010. As a result, these assets have been presented in the consolidated balance sheet as assets held for sale and assets of discontinued operations as of March 31, 2010 and December 31, 2009. In addition, the results of operations of the Delaware City Refinery have been presented as discontinued operations in the consolidated statements of income for both periods presented.

7

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

Asset impairment losses have been presented on a separate line in the 2009 consolidated statement of income. These losses resulted from the cancellation of certain capital projects classified as “construction in progress,” and for the three months ended March 31, 2009, such losses have been reclassified from operating expenses and presented separately. The asset impairment losses are also presented on a separate line in the consolidated statements of cash flows, which resulted in an adjustment to “changes in deferred charges and credits and other operating activities, net” previously reported for the three months ended March 31, 2009. Asset impairment losses presented in the consolidated statements of cash flows includes asset impairment losses associated with the Delaware City Refinery. Such losses, however, are included in discontinued operations in the consolidated statements of income.

2. ACCOUNTING PRONOUNCEMENTS

Transfers of Financial Assets

In June 2009, Topic 860 of the Accounting Standards Codification (the Codification, or ASC), “Transfers and Servicing,” was modified to clarify the requirements for derecognizing transferred financial assets, remove the concept of a qualifying special-purpose entity and related exceptions, and require additional disclosures related to transfers of financial assets. This guidance was effective for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2009, and earlier application was prohibited. The adoption of these provisions of ASC Topic 860 effective January 1, 2010 did not affect our financial position or results of operations.

Variable Interest Entities

In June 2009, ASC Topic 810, “Consolidation,” was amended to modify provisions related to variable interest entities to include entities previously considered qualifying special-purpose entities, as the concept of these entities was eliminated. This modification also clarifies consolidation requirements and expands disclosure requirements related to variable interest entities. These provisions of ASC Topic 810 were effective for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2009, and earlier application was prohibited. The adoption of these provisions of ASC Topic 810 effective January 1, 2010 did not affect our financial position or results of operations.

3. ACQUISITIONS

The acquired ethanol businesses discussed below involve the production and marketing of ethanol and its co-products, including distillers grains. The operations of our ethanol business complement our existing clean motor fuels business.

Acquisitions of ASA and Renew Assets

In December 2009, we signed an agreement with ASA Ethanol Holdings, LLC (ASA) to buy two ethanol plants located in Linden, Indiana and Bloomingburg, Ohio and made a $20 million advance payment towards the purchase of these facilities. On January 13, 2010, we completed the acquisition of the facilities, including certain inventories, for a total purchase price of $202 million.

8

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

Also in December 2009, we received approval from a bankruptcy court to acquire an ethanol facility located near Jefferson, Wisconsin from Renew Energy LLC (Renew) and made a $1 million advance payment towards the purchase of this facility. We completed the acquisition of this facility, including certain receivables and inventories, on February 4, 2010 for a total purchase price of $79 million.

The assets acquired from ASA and Renew have been recognized at estimated acquisition-date fair values as determined by preliminary independent appraisals and other evaluations as follows (in millions):

Current assets, primarily inventory	$	11
Property, plant and equipment		270
Total consideration	$	281

Neither goodwill nor a gain from a bargain purchase is expected to be recognized in conjunction with the ASA and Renew acquisitions, and no contingent assets or liabilities were acquired or assumed. In addition, pro forma results of operations for the three months ended March 31, 2010 have not been presented for these acquisitions as the acquisitions were not material to our financial position or results of operations. The consolidated statement of income for the three months ended March 31, 2010 includes the results of the ASA and Renew acquisitions as of their respective acquisition dates in the first quarter of 2010.

Acquisition of VeraSun Assets

In the second quarter of 2009, we acquired seven ethanol plants and a site under development from VeraSun Energy Corporation (VeraSun). The acquisition of these ethanol plants (referred to as the VeraSun Acquisition) was completed under three separate closing transactions. The purchase price for the VeraSun Acquisition was $477 million plus $79 million primarily for inventory and certain other working capital.

An independent appraisal of the assets acquired in the VeraSun Acquisition was 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 VeraSun Acquisition commencing on the respective closing dates in the second quarter of 2009. As a result, pro forma information for the three months ended March 31, 2010 has not been presented since the results of operations of the VeraSun Acquisition have been included in our actual consolidated results of operations for the entire period. The pro forma information presented below for the three months ended March 31, 2009 assumes that the purchase price was funded with proceeds from the issuance of $556 million of debt

9

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

on January 1, 2009. The consolidated pro forma operating revenues, net income, and earnings per common share – assuming dilution of the combined entity for the three months ended March 31, 2009 had the VeraSun Acquisition occurred on January 1, 2009 are shown in the table below (in millions, except per share amounts). The pro forma financial information is not necessarily indicative of the results of future operations.

	Three Months Ended
	March 31, 2009
Consolidated pro forma:
Operating revenues	$	13,551
Income from continuing operations		358
Earnings per common share from continuing operations – assuming dilution		0.69

4. ASSETS HELD FOR SALE AND ASSETS AND LIABILITIES OF DISCONTINUED OPERATIONS

On November 20, 2009, we announced the permanent shutdown of our Delaware City Refinery due to financial losses caused by poor economic conditions, significant capital spending requirements, and high operating costs. In the fourth quarter of 2009, we recorded a pre-tax loss of $1.9 billion, of which $1.4 billion represented the write-down of the book value of the refinery assets to net realizable value. The results of operations of the Delaware City Refinery have been presented as discontinued operations in the consolidated statements of income for both periods presented because of the permanent shutdown of the refinery. Certain terminal and pipeline assets previously associated with the refinery were not shut down and have continued to be operated, with the results of their operations reflected in continuing operations in the consolidated statements of income for both periods presented.

In the first quarter of 2010, our board of directors approved a plan of sale for our terminal, pipeline, and shutdown refinery assets at Delaware City. On April 7, 2010, we entered into an agreement to sell those assets to wholly owned subsidiaries of PBF Energy Partners LP (PBF) for $220 million in proceeds. The transaction is expected to close during the second quarter of 2010, subject to regulatory approvals, as well as finalization of certain agreements with the state of Delaware. As a result, the shutdown Delaware City Refinery assets and the associated terminal and pipeline assets have been presented in the consolidated balance sheets within assets held for sale and assets related to discontinued operations as of March 31, 2010 and December 31, 2009. All other related assets, consisting primarily of accounts receivable and certain inventories, and liabilities of the shutdown Delaware City Refinery that will not be sold are also presented as assets and liabilities related to discontinued operations as of March 31, 2010 and December 31, 2009. The nature and significance of our post-closing participation in the terminalling agreement described below represents a continuation of activities with the terminal operations of the Delaware City Refinery for accounting purposes, and as such the results of operations related to these terminal operations have not been presented as discontinued operations in the consolidated statements of income for any of the periods presented.

In connection with this sale, we will enter into a terminalling and offtake agreement with PBF under which PBF will provide certain terminalling services including receipt, storage, handling, and redelivery of refined products for us. If PBF resumes refinery operations, the terminalling agreement will terminate and we will purchase certain off-take products as prescribed in the agreement. The initial term of this

10

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

agreement is for one year and shall automatically renew for 180-day periods until terminated by either party.

Financial information related to the assets held for sale and the assets and liabilities related to the discontinued operations is summarized as follows (in millions):

	March 31, 2010
			Assets and
			Liabilities
	Assets		Related to
	Held		Discontinued
	for Sale		Operations		Total
Current assets:
Receivables, net	$	–	$	7	$	7
Inventories		–		4		4
Property, plant and equipment, net:
Refinery		16		–		16
Terminal and pipeline		140		–		140
Deferred income taxes		–		52		52
Current assets	$	156	$	63	$	219
Current liabilities:
Accounts payable	$	–	$	59	$	59
Accrued expenses		–		101		101
Current liabilities	$	–	$	160	$	160
	December 31, 2009
			Assets and
			Liabilities
	Assets		Related to
	Held		Discontinued
	for Sale		Operations		Total
Current assets:
Receivables, net	$	–	$	6	$	6
Inventories		–		4		4
Property, plant and equipment, net:
Refinery		16		–		16
Terminal and pipeline		141		–		141
Deferred income taxes		–		57		57
Current assets	$	157	$	67	$	224
Current liabilities:
Accounts payable	$	–	$	90	$	90
Accrued expenses		–		135		135
Current liabilities	$	–	$	225	$	225

11

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

Results of operations for the Delaware City Refinery are summarized as follows (in millions):

	Three Months Ended March 31,
	2010			2009
Operating revenues	$	–		$	496
Loss before income tax benefit		(26	)		(85	)

5. IMPAIRMENTS

Due to the economic slowdown that persisted throughout 2009 and its negative impact on the refining industry, we evaluated our refining operating assets for potential impairment in 2009. Such evaluations were based on expected future cash flows for each of our refineries using significant estimates and assumptions about the future operations of those refineries, including overall throughput volumes, types of crude oil processed, types of products produced, and prices for crude oil and refined products. Prices for crude oil and refined products fluctuate significantly based on market factors, including geopolitical matters. Prices, in turn, impact refinery throughput assumptions. In addition, we considered matters specific to our Aruba Refinery and Paulsboro Refinery to develop expected future cash flows for those refineries. We determined that there was no indication of potential impairment of our refining operating assets as of December 31, 2009.

While the economy and refining industry fundamentals improved during the first quarter of 2010, refining industry fundamentals continued to be negatively impacted by the economic slowdown. As a result, we updated our evaluation of potential impairments of our refining operating assets as of March 31, 2010, and we determined that there was no indication of impairment. Our cash flow estimates are based on our continued expectation of improved refined product prices resulting from an expected improvement in the worldwide economy, and we updated our assumptions related to matters specific to our Aruba and Paulsboro Refineries that impact expected future cash flows for those refineries. We believe that our estimates used to develop expected cash flows are reasonable; however, future cash flows will differ from our estimates and such differences may be material. The sensitivity of our estimates is most significant with respect to our Aruba and Paulsboro Refineries. Therefore, should prices fail to improve as expected or other factors occur that impact our expectations regarding these refineries, we may determine that either or both refineries are impaired, and the resulting impairment loss could be material to our results of operations.

For further information regarding impairments, see Note 3 of Notes to Consolidated Financial Statements included in our annual report on Form 10-K for the year ended December 31, 2009.

12

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

6. INVENTORIES

Inventories consisted of the following (in millions):

	March 31,		December 31,
	2010		2009
Refinery feedstocks	$	2,549	$	2,124
Refined products and blendstocks		1,710		2,317
Ethanol feedstocks and products		183		141
Convenience store merchandise		93		96
Materials and supplies		189		185
Inventories	$	4,724	$	4,863

As of March 31, 2010 and December 31, 2009, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $4.9 billion and $4.5 billion, respectively.

7. DEBT

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

In February 2010, we issued $400 million of 4.50% notes due in February 2015 and $850 million of 6.125% notes due in February 2020. Proceeds from the issuance of these notes totaled approximately $1.24 billion, before deducting underwriting discounts of $8 million.

On March 15, 2010, we redeemed our 7.50% senior notes with a maturity date of June 15, 2015 for $294 million, or 102.5% of stated value. These notes had a carrying amount of $296 million as of the redemption date, resulting in a $2 million gain that was included in “other income (expense), net” in the consolidated statement of income.

In March 2010, we called for redemption our 6.75% senior notes with a maturity date of May 1, 2014 for $190 million, or 102.25% of stated value. The redemption date was May 3, 2010. These notes had a carrying amount of $187 million as of the redemption date, resulting in a loss on the redemption of approximately $3 million.

Bank Credit Facilities
We have a revolving credit facility (the Revolver) that has a maturity date of November 2012. As of March 31, 2010, the Revolver had a borrowing capacity of $2.4 billion. The Revolver has certain restrictive covenants, including a maximum debt-to-capitalization ratio of 60%. As of March 31, 2010 and December 31, 2009, our debt-to-capitalization ratios, calculated in accordance with the terms of the Revolver, were 30.6% and 30.9%, respectively. We believe that we will remain in compliance with this covenant.

13

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

During the three months ended March 31, 2010, we had no borrowings or repayments under our Revolver or other revolving bank credit facilities. As of March 31, 2010 and December 31, 2009, we had no borrowings outstanding under these committed revolving credit facilities.

As of March 31, 2010 and December 31, 2009, we had $242 million and $259 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities and $329 million and $299 million, respectively, of letters of credit outstanding under our U.S. committed revolving credit facilities. Under our Canadian committed revolving credit facility, we had Cdn. $22 million of letters of credit outstanding as of both March 31, 2010 and December 31, 2009.

Accounts Receivable Sales Facility
We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables. We amended our agreement in June 2009 to extend the maturity date to June 2010. As of December 31, 2009, the amount of eligible receivables sold to the third-party entities and financial institutions was $200 million. During the quarter ended March 31, 2010, we sold and repaid $1.2 billion of eligible receivables to the third-party entities and financial institutions. As of March 31, 2010, the amount of eligible receivables sold to the third-party entities and financial institutions was $200 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):

	March 31,		December 31,
	2010		2009
Carrying amount	$	8,313	$	7,364
Fair value		9,329		8,228

8. STOCKHOLDERS’ EQUITY

Treasury Stock
No significant purchases of our common stock were made during the three months ended March 31, 2010 and 2009. During the three months ended March 31, 2010 and 2009, we issued 0.5 million and 0.2 million shares from treasury, respectively, for our employee benefit plans.

Common Stock Dividends
On April 29, 2010, our board of directors declared a regular quarterly cash dividend of $0.05 per common share payable on June 16, 2010 to holders of record at the close of business on May 19, 2010.

14

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

9. 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 March 31,
	2010					2009
	Restricted		Common			Restricted			Common
	Stock		Stock			Stock			Stock
Earnings (loss) per common share from continuing operations:
Income (loss) from continuing operations			$	(101	)				$	364
Less dividends paid:
Common stock				28						77
Nonvested restricted stock				–						–
Undistributed earnings (loss)			$	(129	)				$	287
								��
Weighted-average common shares outstanding		3		562			2			514
Earnings (loss) per common share from continuing operations:
Distributed earnings	$	0.05	$	0.05		$	0.15		$	0.15
Undistributed earnings (loss)		–		(0.23	)		0.55			0.55
Total earnings (loss) per common share from continuing operations	$	0.05	$	(0.18	)	$	0.70		$	0.70
Earnings (loss) per common share from continuing operations – assuming dilution:
Income (loss) from continuing operations			$	(101	)				$	364
Weighted-average common shares outstanding				562						514
Common equivalent shares (1):
Stock options				–						4
Performance awards and other benefit plans				–						1
Weighted-average common shares outstanding – assuming dilution				562						519
Earnings (loss) per common share from continuing operations – assuming dilution			$	(0.18	)				$	0.70

(1) Common equivalent shares were excluded from the computation of diluted loss per share for the three months ended March 31, 2010 because the effect of including such shares would be antidilutive.

The following table reflects potentially dilutive securities that were excluded from the calculation of “earnings (loss) per common share from continuing operations – assuming dilution” as the effect of including such securities would have been antidilutive (in millions). For the three months ended March 31, 2010, common equivalent shares, which represent primarily stock options, were excluded as a

15

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

result of the net loss reported for the first quarter of 2010. In addition, for both 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 March 31,
	2010		2009
Common equivalent shares		5		–
Stock options		14		10

10. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2010			2009
Decrease (increase) in current assets:
Restricted cash	$	(7	)	$	(8	)
Receivables, net		(189	)		(245	)
Inventories		168			(50	)
Income taxes receivable		830			117
Prepaid expenses and other		39			(90	)
Increase (decrease) in current liabilities:
Accounts payable		155			231
Accrued expenses		(47	)		35
Taxes other than income taxes		(126	)		(86	)
Income taxes payable		(70	)		–
Changes in current assets and current liabilities	$	753		$	(96	)

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, as well as the effect of certain noncash investing and financing activities discussed below;

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

• changes in assets and liabilities related to the discontinued operations of the Delaware City Refinery prior to its shutdown 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.

16

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

There were no significant noncash investing or financing activities for the three months ended March 31, 2010 and 2009.

Cash flows related to the discontinued operations of the Delaware City Refinery have been combined with the cash flows from continuing operations within each category in the consolidated statements of cash flows for both periods presented and are summarized as follows (in millions):

	Three Month Ended March 31,
	2010			2009
Cash used in operating activities	$	(12	)	$	(42	)
Cash used in investing activities		–			(34	)

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

	Three Months Ended March 31,
	2010			2009
Interest paid in excess of (less than) amount capitalized	$	56		$	(19	)
Income taxes paid (net of tax refunds received)		(839	)		(168	)

11. 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 March 31, 2010 and December 31, 2009.

17

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
	Markets		Inputs		Inputs		Total as of
	(Level 1)		(Level 2)		(Level 3)		March 31, 2010
Assets:
Commodity derivative contracts	$	30	$	235	$	–	$	265
Nonqualified benefit plans		102		–		10		112
Liabilities:
Commodity derivative contracts		84		10		–		94
Certain nonqualified benefit plans		33		–		–		33
	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)		2009
Assets:
Commodity derivative contracts	$	10	$	349	$	–	$	359
Nonqualified benefit plans		99		–		10		109
Liabilities:
Commodity derivative contracts		100		9		–		109
Certain nonqualified benefit plans		34		–		–		34

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.

• The nonqualified benefit plan assets and certain nonqualified benefit plan liabilities categorized in Level 1 of the fair value hierarchy are measured at fair value using a market approach based on quotations from national securities exchanges. The nonqualified benefit plan assets categorized in Level 3 of the fair value hierarchy represent insurance contracts, the fair values of which are provided by the insurer.

As of March 31, 2010, our obligation to pay cash collateral to brokers under master netting arrangements of $25 million was netted against the fair value of the commodity derivatives reflected in Level 1. As of December 31, 2009, cash received from brokers of $64 million, resulting from the equity in broker accounts covered by master netting arrangements exceeding the minimum margin requirements for such accounts, was 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

18

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

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.

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 months ended March 31, 2010 and 2009.

	Three Months Ended March 31,
	2010		2009
Balance at beginning of period	$	10	$	13
Net unrealized gains included in earnings		–		11
Balance at end of period	$	10	$	24

Unrealized gains for the three months ended March 31, 2009, which are reported in “other income (expense), net” in the consolidated statement of income, related to the three-year earn-out agreement with Alon Refining Krotz Springs Inc. (Alon) that was entered into in connection with the sale of our Krotz Springs Refinery and was settled in August 2009. These unrealized gains were offset by the recognition in “other income (expense), net” of losses on derivative instruments entered into to hedge the risk of changes in the fair value of the Alon earn-out agreement.

12. PRICE RISK MANAGEMENT ACTIVITIES

We are exposed to market risks related to the volatility in the price of commodities, interest rates and foreign currency exchange rates, and we enter into derivative instruments to manage those risks. We also enter into derivative instruments to manage the price risk on other contractual derivatives into which we have entered. The only types of derivative instruments we enter into are those related to the various commodities we purchase or produce, interest rate swaps, and foreign currency exchange and purchase contracts, as described below. 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 both periods presented.

19

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

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

For risk management purposes, we use fair value hedges, cash flow hedges, and economic hedges. In addition to the use of derivative instruments to manage commodity price risk, we also enter into certain commodity derivative instruments for trading purposes. Our objective for entering into each type of hedge or trading activity is 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 generally represents the amount by which our inventories differ from our previous year-end LIFO inventory levels.

As of March 31, 2010, we had the following outstanding commodity derivative instruments that were entered into to hedge crude oil and refined product inventories. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).

	Notional
Derivative Instrument / Maturity	Contract Volumes
Futures – short:
2010 (crude oil)		12,036

20

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 objective of our cash flow hedges is to lock in the price of forecasted feedstock, product, or natural gas purchases or refined product sales at existing market prices that are deemed favorable by management.

As of March 31, 2010, we had the following outstanding commodity derivative instruments that were entered into to hedge forecasted purchases or sales of crude oil and refined products. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).

	Notional
Derivative Instrument / Maturity	Contract Volumes
Swaps – long:
2010 (crude oil)		11,925
2010 (distillate)		20,025
Swaps – short:
2010 (crude oil)		11,925
2010 (distillate)		20,025
Futures – long:
2010 (crude oil)		89

21

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 corn inventories, and (ii) manage price volatility in certain forecasted refinery feedstock, product, and corn purchases, refined product sales, and natural gas purchases. 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 March 31, 2010, we had the following outstanding commodity derivative instruments that were entered into as economic hedges. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as corn contracts that are presented in thousands of bushels).

	Notional
Derivative Instrument / Maturity	Contract Volumes
Swaps – long:
2010 (crude oil)		82,679
2010 (distillate)		39,621
2010 (gasoline)		8,475
2011 (crude oil)		48,600
2011 (distillate)		5,850
2011 (gasoline)		4,950
Swaps – short:
2010 (crude oil)		63,691
2010 (distillate)		54,114
2010 (gasoline)		11,475
2011 (crude oil)		48,600
2011 (distillate)		5,850
2011 (gasoline)		4,950
Futures – long:
2010 (crude oil)		150,251
2010 (distillate)		63,635
2010 (gasoline)		26,501
2010 (corn)		6,070
2011 (distillate)		66
2011 (corn)		150
Futures – short:
2010 (crude oil)		142,324
2010 (distillate)		52,155
2010 (gasoline)		45,238
2010 (corn)		25,255
2011 (corn)		860
Options – long:
2010 (distillate)		6

22

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

Trading Activities
Derivatives entered into for trading activities 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 March 31, 2010, we had the following outstanding commodity derivative instruments that were entered into for trading purposes. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes represent thousands of barrels, except those identified as natural gas contracts that are presented in billions of British thermal units).

	Notional
Derivative Instrument / Maturity	Contract Volumes
Swaps – long:
2010 (crude oil)		13,188
2010 (distillate)		19,853
2010 (gasoline)		9,330
2011 (crude oil)		2,565
2011 (distillate)		600
2011 (gasoline)		3,000
Swaps – short:
2010 (crude oil)		12,930
2010 (distillate)		19,886
2010 (gasoline)		9,555
2011 (crude oil)		2,250
2011 (distillate)		915
2011 (gasoline)		3,000
Futures – long:
2010 (crude oil)		20,561
2010 (distillate)		19,179
2010 (gasoline)		7,454
2010 (natural gas)		310
2011 (crude oil)		1,040
2011 (distillate)		10
Futures – short:
2010 (crude oil)		22,334
2010 (distillate)		19,121
2010 (gasoline)		7,307
2010 (natural gas)		310
2011 (crude oil)		950
2011 (distillate)		70
Options – long:
2010 (crude oil)		3,136
Options – short:
2010 (crude oil)		5,136

23

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

Interest Rate Risk
Our primary market risk exposure for changes in interest rates relates to our debt obligations. We manage our exposure to changing interest rates through the use of a combination of fixed-rate and floating-rate debt. In addition, we have at times used interest rate swap agreements to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt. These interest rate swap agreements are generally accounted for as fair value hedges. However, we have not had any outstanding interest rate swap agreements since 2006.

Foreign Currency Risk
We are exposed to exchange rate fluctuations on transactions related to our Canadian operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of March 31, 2010, we had commitments to purchase $189 million of U.S. dollars. These commitments matured on or before April 16, 2010, resulting in a $1 million loss in the second quarter of 2010.

24

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 March 31, 2010 and December 31, 2009 (in millions) and the line items in the balance sheet in which the fair values are reflected. See Note 11 for additional information related to the fair values of our derivative instruments. As indicated in Note 11, we net fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty under master netting arrangements. The tables below, however, are presented on a gross asset and gross liability basis, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts. In addition, in Note 11 we netted cash collateral payable to brokers and cash received from brokers against the fair value of the commodity derivatives; these cash amounts are not reflected in the tables below.

	Asset Derivatives			Liability Derivatives
		Fair Value			Fair Value
		as of			as of
	Balance Sheet	March 31,		Balance Sheet	March 31,
	Location	2010		Location	2010
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	2	Receivables, net	$	32
Futures	Accrued expenses		35	Accrued expenses		64
Swaps	Receivables, net		254	Receivables, net		224
Swaps	Prepaid expenses and other		353	Prepaid expenses and other		238
Swaps	Accrued expenses		7	Accrued expenses		6
Total derivatives designated as hedging instruments		$	651		$	564
Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	49	Receivables, net	$	32
Futures	Accrued expenses		2,092	Accrued expenses		2,128
Swaps	Receivables, net		424	Receivables, net		321
Swaps	Prepaid expenses and other		869	Prepaid expenses and other		882
Swaps	Accrued expenses		8	Accrued expenses		20
Total derivatives not designated as hedging instruments		$	3,442		$	3,383
Total derivatives		$	4,093		$	3,947

25

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

	Asset Derivatives			Liability Derivatives
		Fair Value			Fair Value
		as of			as of
	Balance Sheet	December 31,		Balance Sheet	December 31,
	Location	2009		Location	2009
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	1	Receivables, net	$	2
Futures	Accrued expenses		13	Accrued expenses		37
Swaps	Receivables, net		308	Receivables, net		271
Swaps	Prepaid expenses and other		579	Prepaid expenses and other		415
Swaps	Accrued expenses		28	Accrued expenses		19
Total derivatives designated as hedging instruments		$	929		$	744
Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	34	Receivables, net	$	29
Futures	Accrued expenses		2,094	Accrued expenses		2,101
Swaps	Receivables, net		506	Receivables, net		370
Swaps	Prepaid expenses and other		1,049	Prepaid expenses and other		1,037
Swaps	Accrued expenses		46	Accrued expenses		62
Options	Accrued expenses		–	Accrued expenses		1
Total derivatives not designated as hedging instruments		$	3,729		$	3,600
Total derivatives		$	4,658		$	4,344

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 March 31, 2010, we had net receivables related to derivative instruments of $19 million from counterparties in the refining industry and $83 million from counterparties in the financial services industry. As of December 31, 2009, we had net receivables related to derivative instruments of $19 million from counterparties in the refining industry and $157 million from counterparties in the

26

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

financial services industry. These amounts represent the aggregate amount payable to us by companies in those industries, reduced by payables from us to those companies under master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party. We do not require any collateral or other security to support derivative instruments into which we enter. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.

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 months ended March 31, 2010 and 2009 (in millions), and the line items in the financial statements in which such gains and losses are reflected.

	Location of	Amount of						Location of	Amount of				Amount of
Derivatives in	Gain or (Loss)	Gain or (Loss)						Gain or (Loss)	Gain or (Loss)				Gain or (Loss)
Fair Value	Recognized in	Recognized in						Recognized in	Recognized				Recognized in Income
Hedging	Income on	Income on						Income on	in Income on				for Ineffective Portion
Relationships	Derivatives	Derivatives						Hedged Item	Hedged Item				of Derivative (1)
		Three Months							Three Months				Three Months
		Ended March 31,							Ended March 31,				Ended March 31,
		2010			2009				2010		2009		2010			2009
Commodity contracts	Cost of sales	$	(17	)	$	(15	)	Cost of sales	$	16	$	15	$	(1	)	$	–
Total		$	(17	)	$	(15	)		$	16	$	15	$	(1	)	$	–

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

Location of

Gain or (Loss)

Location of

Amount of

Reclassified from

Amount of

Gain or (Loss)

Amount of

Gain or (Loss)

Accumulated

Gain or (Loss)

Recognized in

Gain or (Loss)

Derivatives in

Recognized in

OCI

Reclassified from

Income on

Recognized in

Cash Flow

OCI on

into Income

Accumulated OCI

Derivatives

Income on

Hedging

Derivatives

(Effective

into Income

(Ineffective

Derivatives

Relationships

(Effective Portion)

Portion)

(Effective Portion)

Portion)

(Ineffective Portion) (1)

Three Months

Three Months

Three Months

Ended

Ended

Ended

March 31,

March 31,

March 31

2010

2009

2010

2009

2010

2009

Commodity contracts (2)

$

(2

)

$

92

Cost of sales

$

49

$

61

Cost of sales

$

–

$

–

Total

$

(2

)

$

92

$

49

$

61

$

–

$

–

(1)

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

(2)

For the three months ended March 31, 2010, cash flow hedges primarily related to forward sales of distillates and associated forward purchases of crude oil, with $84 million of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive income as of March 31, 2010. We expect that all of the deferred gains at March 31, 2010 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 months ended March 31, 2010 and 2009, there were no amounts reclassified from accumulated other comprehensive income into income as a result of the discontinuance of cash flow hedge accounting.

27

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

	Location of	Amount of
Derivatives Designated as	Gain or (Loss)	Gain or (Loss)
Economic Hedges	Recognized in	Recognized in
and Other	Income on	Income on
Derivative Instruments	Derivatives	Derivatives
		Three Months Ended
		March 31,
		2010			2009
Commodity contracts	Cost of sales	$	(39	)	$	96
Foreign currency contracts	Cost of sales		(13	)		6
			(52	)		102
Alon earn-out agreement	Other income (expense)		–			11
Alon earn-out hedge (commodity contracts)	Other income (expense)		–			(15	)
			–			(4	)
Total		$	(52	)	$	98
	Location of	Amount of
	Gain or (Loss)	Gain or (Loss)
	Recognized in	Recognized in
Derivatives Designated as	Income on	Income on
Trading Activities	Derivatives	Derivatives
		Three Months Ended
		March 31,
		2010			2009
Commodity contracts	Cost of sales	$	(3	)	$	91
Total		$	(3	)	$	91

28

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

13. SEGMENT INFORMATION

Prior to the second quarter of 2009, we had two reportable segments, which were refining and retail. As a result of the VeraSun Acquisition during the second quarter of 2009 (as discussed in Note 3), ethanol is presented as a third reportable segment.

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

	Refining			Retail		Ethanol		Corporate			Total
Three months ended March 31, 2010:
Operating revenues from external customers	$	16,897		$	2,176	$	570	$	–		$	19,643
Intersegment revenues		1,508			–		55		–			1,563
Operating income (loss)		(51	)		71		57		(109	)		(32	)
Three months ended March 31, 2009:
Operating revenues from external customers		11,696			1,632		–		–			13,328
Intersegment revenues		1,007			–		–		–			1,007
Operating income (loss)		693			56		–		(156	)		593

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

	March 31,		December 31,
	2010		2009
Refining	$	31,114	$	30,901
Retail		1,881		1,875
Ethanol		950		654
Corporate		2,520		2,199
Total consolidated assets	$	36,465	$	35,629

Corporate assets primarily include cash, corporate office buildings, and income tax receivables that may exist from time to time.

29

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

14. EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost related to our defined benefit plans were as follows for the three months ended March 31, 2010 and 2009 (in millions):

							Other Postretirement
	Pension Plans						Benefit Plans
	2010			2009			2010			2009
Components of net periodic benefit cost:
Service cost	$	22		$	26		$	3		$	3
Interest cost		20			20			6			6
Expected return on plan assets		(28	)		(27	)		–			–
Amortization of:
Prior service cost (credit)		1			–			(5	)		(4	)
Net loss		–			3			1			2
Net periodic benefit cost	$	15		$	22		$	5		$	7

Our anticipated contributions to our qualified pension plans during 2010 have not changed from amounts previously disclosed in our consolidated financial statements for the year ended December 31, 2009. During both of the three month periods ended March 31, 2010 and 2009, we contributed $50 million to our qualified pension plans.

In March 2010, a comprehensive health care reform package composed of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (Health Care Reform) was enacted into law. As a result of the Health Care Reform, the income tax benefit presented in our consolidated statement of income for the three months ended March 31, 2010 includes a charge of $16 million related to the non-deductibility of certain retiree prescription health care costs, to the extent of federal subsidies received. Although the tax change provisions of the Health Care Reform are not effective until 2013, the effect of changes in tax laws or rates on deferred tax assets and liabilities are recognized in the period that includes the enactment date, even though the changes may not be effective until future periods. Other provisions of the Health Care Reform are also expected to affect the future costs of our retiree health care plans. An estimate of the additional impacts of the Health Care Reform is not yet practicable due to the number and complexity of the provisions; however, we are currently evaluating the potential impact of the Health Care Reform on our financial position and results of operations.

30

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

15. COMMITMENTS AND CONTINGENCIES

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 initially was 3% for on-island sales and services (but has subsequently been reduced to 1.5%) and 1% on export sales, is being assessed by the GOA on sales by our Aruba Refinery. We disputed the GOA’s assessment of the turnover tax in arbitration proceedings with the Netherlands Arbitration Institute (NAI) pursuant to which we sought to enforce our rights under a tax holiday agreement related to the refinery and other agreements. 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 $115 million as of March 31, 2010 and December 31, 2009 are reflected as restricted cash in our consolidated balance sheets. In addition to the turnover tax described above, the GOA has asserted other tax amounts including approximately $35 million related to various dividends. We 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, 2009, 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 uncertain timing of any final resolution of these claims as a result of

31

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

the First Partial Award from the panel, we recorded a loss contingency accrual of approximately $140 million, including interest, with respect to both the dividend and turnover taxes.

Following the November ruling, we entered into settlement discussions with the GOA. On February 24, 2010, we signed a settlement agreement that details the parties’ proposed terms for settlement of these disputes and provides a framework for taxation of our operations in Aruba on a go-forward basis as our tax holiday was set to expire on December 31, 2010. Under the proposed settlement, we will make a payment to the GOA of $118 million in consideration of a full release of all tax claims prior to the effective date of the settlement, including the turnover tax disputed in the Netherlands Arbitration. The GOA will eliminate the turnover tax on exports as of the effective date of the settlement. In addition, we will agree to exit the tax holiday regime following the effective date of the settlement agreement and will enter into a new tax regime under which we will be subject to a net profit tax of less than 10% on an overall basis. Beginning on the second anniversary of the settlement agreement’s effective date, we will also begin to make an annual prepayment of taxes of $10 million, with the ability to carry forward any excess tax prepayments to future tax years. The proposed settlement will not be effective until the settlement agreement is approved by the Aruban Parliament and certain laws and regulations are modified and/or established to provide for the terms of the settlement. The parties anticipate that this will occur on or before June 1, 2010. If the settlement is not effective as of June 1, 2010, we both have the right to terminate the settlement agreement and return to arbitration and the on-island proceedings to continue litigation.

Litigation

MTBE Litigation
As of May 7, 2010, we were named as a defendant in 38 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). Twenty cases are pending in state court. Discovery is open in all cases. We believe that we have strong defenses to all claims and are vigorously defending the lawsuits.

We recently reached an agreement to settle 25 of the MTBE lawsuits. Final settlement is subject to formal adoption of the settlement agreement under the administrative procedures of the various plaintiffs. We expect this process to be completed in the second quarter of 2010. We have recorded a loss contingency liability with respect to our MTBE litigation portfolio. While 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 do not believe that such an outcome in any one or more of these lawsuits would have a material adverse effect on our results of operations or financial position.

32

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

Retail Fuel Temperature Litigation
As of May 7, 2010, 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 and wholesale 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 or price 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. We expect the court to issue its ruling on the Kansas-based class certification motion only in the second quarter of 2010, and then make a decision on how to further proceed with the rest of the docket. 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.

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 submitted renewed motions for judgment notwithstanding the verdict or, alternatively, a new trial. During the first quarter of 2010, we reached an agreement with our insurance carrier on a claim of insurance coverage related to this litigation resulting in pre-tax income of $40 million that was recorded as a reduction to general and administrative expenses. We have also reached an agreement in principle with the plaintiffs to settle this litigation. We expect to finalize the settlement agreement in the second quarter of 2010. We do not believe that the ultimate resolution of this matter will have a material effect on our financial position or results of operations.

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.

33

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

16. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

In conjunction with the acquisition of Premcor Inc. on September 1, 2005, Valero Energy Corporation 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 March 31, 2010:

• 6.75% senior notes due February 2011,

• 6.125% senior notes due May 2011, and

• 6.75% senior notes due May 2014.

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.

34

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

Condensed Consolidating Balance Sheet as of March 31, 2010
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	882		$	–		$	1,005		$	–		$	1,887
Restricted cash		–			1			128			–			129
Receivables, net		–			34			3,913			–			3,947
Inventories		–			86			4,638			–			4,724
Income taxes receivable		11			–			58			(11	)		58
Deferred income taxes		–			–			175			–			175
Prepaid expenses and other		–			5			176			–			181
Assets held for sale and assets related to discontinued operations		–			211			8			–			219
Total current assets		893			337			10,101			(11	)		11,320
Property, plant and equipment, at cost		–			4,124			25,062			–			29,186
Accumulated depreciation		–			(416	)		(5,435	)		–			(5,851	)
Property, plant and equipment, net		–			3,708			19,627			–			23,335
Intangible assets, net		–			–			226			–			226
Investment in Valero Energy affiliates		6,107			4,093			(5	)		(10,195	)		–
Long-term notes receivable from affiliates		15,838			–			–			(15,838	)		–
Deferred income tax receivable		712			–			–			(712	)		–
Deferred charges and other assets, net		143			161			1,280			–			1,584
Total assets	$	23,693		$	8,299		$	31,229		$	(26,756	)	$	36,465
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	33		$	398		$	204		$	–		$	635
Accounts payable		41			117			5,828			–			5,986
Accrued expenses		182			90			230			–			502
Taxes other than income taxes		–			10			594			–			604
Income taxes payable		–			–			33			(11	)		22
Deferred income taxes		186			–			–			–			186
Liabilities related to discontinued operations		–			160			–			–			160
Total current liabilities		442			775			6,889			(11	)		8,095
Debt and capital lease obligations, less current portion		7,482			200			36			–			7,718
Long-term notes payable to affiliates		–			6,468			9,370			(15,838	)		–
Deferred income taxes		–			745			4,098			(712	)		4,131
Other long-term liabilities		1,103			116			636			–			1,855
Stockholders’ equity:
Common stock		7			–			2			(2	)		7
Additional paid-in capital		7,879			3,719			6,760			(10,479	)		7,879
Treasury stock		(6,688	)		–			–			–			(6,688	)
Retained earnings		13,036			(3,718	)		3,358			360			13,036
Accumulated other comprehensive income (loss)		432			(6	)		80			(74	)		432
Total stockholders’ equity		14,666			(5	)		10,200			(10,195	)		14,666
Total liabilities and stockholders’ equity	$	23,693		$	8,299		$	31,229		$	(26,756	)	$	36,465

35

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

Condensed Consolidating Balance Sheet as of December 31, 2009
(in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	78		$	–		$	747		$	–		$	825
Restricted cash		–			1			121			–			122
Receivables, net		–			24			3,749			–			3,773
Inventories		–			420			4,443			–			4,863
Income taxes receivable		858			–			888			(858	)		888
Deferred income taxes		–			–			180			–			180
Prepaid expenses and other		–			5			256			–			261
Assets held for sale and assets related to discontinued operations		–			216			8			–			224
Total current assets		936			666			10,392			(858	)		11,136
Property, plant and equipment, at cost		–			4,100			24,363			–			28,463
Accumulated depreciation		–			(401	)		(5,191	)		–			(5,592	)
Property, plant and equipment, net		–			3,699			19,172			–			22,871
Intangible assets, net		–			–			227			–			227
Investment in Valero Energy affiliates		6,456			3,807			68			(10,331	)		–
Long-term notes receivable from affiliates		14,181			–			–			(14,181	)		–
Deferred income tax receivable		809			–			–			(809	)		–
Deferred charges and other assets, net		133			67			1,195			–			1,395
Total assets	$	22,515		$	8,239		$	31,054		$	(26,179	)	$	35,629
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	33		$	–		$	204		$	–		$	237
Accounts payable		52			133			5,575			–			5,760
Accrued expenses		117			88			309			–			514
Taxes other than income taxes		–			19			706			–			725
Income taxes payable		–			–			953			(858	)		95
Deferred income taxes		253			–			–			–			253
Liabilities related to discontinued operations		–			225			–			–			225
Total current liabilities		455			465			7,747			(858	)		7,809
Debt and capital lease obligations, less current portion		6,236			895			32			–			7,163
Long-term notes payable to affiliates		–			5,924			8,257			(14,181	)		–
Deferred income taxes		–			760			4,112			(809	)		4,063
Other long-term liabilities		1,099			127			643			–			1,869
Stockholders’ equity:
Common stock		7			–			1			(1	)		7
Additional paid-in capital		7,896			3,719			6,887			(10,606	)		7,896
Treasury stock		(6,721	)		–			–			–			(6,721	)
Retained earnings		13,178			(3,644	)		3,262			382			13,178
Accumulated other comprehensive income (loss)		365			(7	)		113			(106	)		365
Total stockholders’ equity		14,725			68			10,263			(10,331	)		14,725
Total liabilities and stockholders’ equity	$	22,515		$	8,239		$	31,054		$	(26,179	)	$	35,629

36

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

Condensed Consolidating Statement of Income for the Three Months Ended March 31, 2010
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	3,788		$	21,473		$	(5,618	)	$	19,643
Costs and expenses:
Cost of sales		–			4,157			19,597			(5,618	)		18,136
Operating expenses		–			68			844			–			912
Retail selling expenses		–			–			173			–			173
General and administrative expenses		–			(39	)		136			–			97
Depreciation and amortization expense		–			34			323			–			357
Total costs and expenses		–			4,220			21,073			(5,618	)		19,675
Operating income (loss)		–			(432	)		400			–			(32	)
Equity in earnings (losses) of subsidiaries		(162	)		286			(74	)		(50	)		–
Other income (expense), net		272			(8	)		152			(405	)		11
Interest and debt expense:
Incurred		(157	)		(119	)		(276	)		405			(147	)
Capitalized		–			1			19			–			20
Income (loss) from continuing operations before income tax expense (benefit)		(47	)		(272	)		221			(50	)		(148	)
Income tax expense (benefit) (1)		66			(210	)		97			–			(47	)
Income (loss) from continuing operations		(113	)		(62	)		124			(50	)		(101	)
Loss from discontinued operations, net of income taxes		–			(12	)		–			–			(12	)
Net income (loss)	$	(113	)	$	(74	)	$	124		$	(50	)	$	(113	)

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

37

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

Condensed Consolidating Statement of Income for the Three Months Ended March 31, 2009
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	2,238		$	13,704		$	(2,614	)	$	13,328
Costs and expenses:
Cost of sales		–			2,282			11,536			(2,614	)		11,204
Operating expenses		–			91			754			–			845
Retail selling expenses		–			–			169			–			169
General and administrative expenses		(2	)		1			146			–			145
Depreciation and amortization expense		–			36			314			–			350
Asset impairment loss		–			18			4			–			22
Total costs and expenses		(2	)		2,428			12,923			(2,614	)		12,735
Operating income (loss)		2			(190	)		781			–			593
Equity in earnings (losses) of subsidiaries		248			120			(105	)		(263	)		–
Other income (expense), net		255			(14	)		161			(403	)		(1	)
Interest and debt expense:
Incurred		(143	)		(115	)		(264	)		403			(119	)
Capitalized		–			6			33			–			39
Income (loss) from continuing operations before income tax expense (benefit)		362			(193	)		606			(263	)		512
Income tax expense (benefit) (1)		53			(143	)		238			–			148
Income (loss) from continuing operations		309			(50	)		368			(263	)		364
Loss from discontinued operations, net of income taxes		–			(55	)		–			–			(55	)
Net income (loss)	$	309		$	(105	)	$	368		$	(263	)	$	309

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

38

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

Condensed Consolidating Statement of Cash Flows for the Three Months Ended March 31, 2010
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	911		$	(126	)	$	197		$	–		$	982
Cash flows from investing activities:
Capital expenditures		–			(43	)		(339	)		–			(382	)
Deferred turnaround and catalyst costs		–			(71	)		(158	)		–			(229	)
Purchase of ethanol facilities		–			–			(260	)		–			(260	)
Net intercompany loans		(1,328	)		–			–			1,328			–
Return of investment		10			–			–			(10	)		–
Other investing activities, net		–			–			15			–			15
Net cash used in investing activities		(1,318	)		(114	)		(742	)		1,318			(856	)
Cash flows from financing activities:
Non-bank debt:
Borrowings		1,244			–			–			–			1,244
Repayments		–			(294	)		–			–			(294	)
Accounts receivable sales program:
Proceeds from sale of receivables		1,225			–			–			–			1,225
Repayments		(1,225	)		–			–			–			(1,225	)
Purchase of common stock for treasury		(1	)		–			–			–			(1	)
Issuance of common stock in connection with employee benefit plans		4			–			–			–			4
Benefit from tax deduction in excess of recognized stock-based compensation cost		2			–			–			–			2
Common stock dividends		(28	)		–			–			–			(28	)
Dividend to parent		–			–			(10	)		10			–
Debt issuance costs		(10	)		–			–			–			(10	)
Net intercompany borrowings		–			534			794			(1,328	)		–
Other financing activities		–			–			(1	)		–			(1	)
Net cash provided by financing activities		1,211			240			783			(1,318	)		916
Effect of foreign exchange rate changes on cash		–			–			20			–			20
Net increase in cash and temporary cash investments		804			–			258			–			1,062
Cash and temporary cash investments at beginning of period		78			–			747			–			825
Cash and temporary cash investments at end of period	$	882		$	–		$	1,005		$	–		$	1,887

39

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

Condensed Consolidating Statement of Cash Flows for the Three Months Ended March 31, 2009
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	135		$	(201	)	$	847		$	–		$	781
Cash flows from investing activities:
Capital expenditures		–			(140	)		(595	)		–			(735	)
Deferred turnaround and catalyst costs		–			(13	)		(154	)		–			(167	)
Advance payments related to purchase of ethanol facilities		–			–			(13	)		–			(13	)
Net intercompany loans		(588	)		–			–			588			–
Other investing activities, net		–			–			6			–			6
Net cash used in investing activities		(588	)		(153	)		(756	)		588			(909	)
Cash flows from financing activities:
Non-bank debt repayments		998			–			–			–			998
Accounts receivable sales program:
Proceeds from sale of receivables		–			–			100			–			100
Repayments		–			–			(100	)		–			(100	)
Issuance of common stock in connection with employee benefit plans		1			–			–			–			1
Benefit from tax deduction in excess of recognized stock-based compensation cost		1			–			–			–			1
Common stock dividends		(77	)		–			–			–			(77	)
Net intercompany borrowings		–			354			234			(588	)		–
Debt issuance costs		(7	)		–			–			–			(7	)
Other financing activities		(1	)		–			(1	)		–			(2	)
Net cash provided by financing activities		915			354			233			(588	)		914
Effect of foreign exchange rate changes on cash		–			–			(11	)		–			(11	)
Net increase in cash and temporary cash investments		462			–			313			–			775
Cash and temporary cash investments at beginning of period		215			–			725			–			940
Cash and temporary cash investments at end of period	$	677		$	–		$	1,038		$	–		$	1,715

40

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

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

This Form 10-Q, including without limitation our discussion below under the heading “Overview and Outlook,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “believe,” “expect,” “plan,” “intend,” “estimate,” “project,” “projection,” “predict,” “budget,” “forecast,” “goal,” “guidance,” “target,” “could,” “should,” “may,” and similar expressions.

These forward-looking statements include, among other things, statements regarding:

• future refining margins, including gasoline and distillate margins;

• future retail margins, including gasoline, diesel, home heating oil, and convenience store merchandise margins;

• future ethanol margins and the effect of the acquisition of certain ethanol plants 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;

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

• domestic and foreign demand for, and supplies of, crude oil and other feedstocks;

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

• the level of consumer demand, including seasonal fluctuations;

• refinery overcapacity or undercapacity;

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

41

• 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 may be lower than expected;

• earthquakes, hurricanes, tornadoes, and irregular weather, which can unforeseeably affect the price or availability of natural gas, refinery, ethanol, 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, including tax and environmental regulations, 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.

42

OVERVIEW AND OUTLOOK

For the first quarter of 2010, we reported a loss from continuing operations of $101 million, or $0.18 per share, compared to income from continuing operations of $364 million, or $0.70 per share, for the first quarter of 2009. The first quarter 2010 loss is primarily due to a $51 million operating loss in our refining segment, as compared to operating income of $693 million for the first quarter of 2009. The decline in refining operating income was primarily due to lower margins for most of the products we produce. We believe the economic slowdown has negatively impacted refined product margins by weakening the demand for those products and causing product inventories to build in the U.S. and throughout the world. There has also been a significant increase in worldwide refining capacity due in part to strong worldwide economic growth in 2004 through 2007. This increase in capacity has contributed to a further increase in the available supply of refined products.

We responded to this negative economic environment and its impact on our business by assessing the operating performance and profitability of our refining segment assets. This has resulted in a reduction in refinery utilization to optimize the profitability of each of our assets. In addition, this assessment led to our decision to shut down our Aruba Refinery temporarily in July 2009 and to shut down our Delaware City Refinery permanently in November 2009. We also have temporarily suspended construction activity on various capital projects and permanently cancelled other projects in order to reduce the use of cash for capital expenditures. Due to the shutdown of our Delaware City Refinery, we have reflected its results of operations as discontinued operations in our consolidated statements of income for both periods presented, and we have excluded our Delaware City Refinery from the “operating highlights” and “refining operating highlights” tables that follow this overview.

Last year, we concluded that the Aruba Refinery, which processes heavy sour crude oil, was temporarily uneconomical to operate due to a narrowing of the heavy sour crude oil differential. The heavy sour crude oil differential is the difference between the price of sweet crude oil and the price of heavy sour crude oil. This differential began to narrow in the first quarter of 2009 due to the decreased production of sour crude oil in response to lower worldwide demand for all types of crude oil. The heavy sour crude oil differential continued to narrow throughout 2009 and remained narrow during the first quarter of 2010 relative to the price of sweet crude oil. As a result, the Aruba Refinery remained shut during the first quarter of 2010, which contributed to our throughput volumes for the first quarter of 2010 being 254,000 barrels per day lower than the first quarter of 2009. In addition, the Government of Aruba’s (GOA) turnover tax introduced on January 1, 2007 further contributed to the uneconomical evaluation of the refinery. The settlement agreement signed by us and the GOA in February 2010 provides for the repeal of the turnover tax and a more stable overall tax regime. We anticipate that the settlement agreement will be approved by the Aruban Parliament and new laws enacted to implement the settlement agreement’s provisions prior to June 1, 2010. However, notwithstanding the settlement and new tax structure with the GOA, refining economics may not recover sufficiently to justify restarting this refinery.

In the second quarter of 2009, we entered the ethanol business through the acquisition of seven ethanol facilities, and we acquired three additional facilities in the first quarter of 2010. We entered the ethanol business because we believe that ethanol has become and will continue to be a part of the transportation fuel supply mix in the U.S. We believe that ethanol is a natural fit for us because we manufacture transportation fuels. During the first quarter of 2010, our ethanol segment generated operating income of $57 million. There are no comparative operating results for the first quarter of 2009 because this business was acquired after the first quarter of 2009. The ethanol business is dependent on margins between ethanol and corn feedstocks and can be impacted by U.S. government subsidies and biofuels (including ethanol) mandates.

43

Our retail segment generated operating income of $71 million for the first quarter of 2010, compared to operating income of $56 million for the first quarter of 2009. The first quarter 2010 results are primarily due to strong retail fuel margins.

We continued to focus on maintaining our financial strength and liquidity during the current challenging economic times, and as a result, we issued $1.25 billion in debt during the first quarter of 2010 at interest rates favorable to those on our existing debt. We used a portion of the proceeds to redeem our 7.50% senior notes for $294 million on March 15, 2010, and our 6.75% senior notes for $190 million on May 3, 2010; the remainder was used for general corporate purposes.

As 2010 progresses, we expect the U.S. and worldwide economies to continue to recover slowly, and we expect refined product demand to increase. The increase in anticipated refined product demand is expected to result in an increase in crude oil production, which we believe will result in the production of more sour crude oils and improved sour crude oil differentials. Thus far in 2010, sour crude oil differentials have improved somewhat from the very low first quarter 2009 levels. The expected increases in refined product demand and increases in sour crude oil production should favorably impact refined product margins. However, we expect that the current surplus and growth in global refining capacity will put pressure on refining margins and could result in continuing production constraints or refinery shutdowns in the refining industry. We will continue to optimize our refining assets based on market conditions.

During the remainder of 2010 and beyond, we will continue to monitor the progress and status of carbon emission legislation (e.g., cap-and-trade) and the increased regulation from the U.S. Environmental Protection Agency. Transportation (automobiles, aircraft, railroads, and shipping) and utility (electricity generation and residential heating) activities have significant carbon “footprints.” Our refined products are an energy source for many of these activities. As such, future regulatory and tax legislation over carbon emissions could have a significant impact on the supply, demand, and cost of our refined products, which could have a significant adverse affect on our business.

44

RESULTS OF OPERATIONS

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

First Quarter 2010 Compared to First Quarter 2009

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

	Three Months Ended March 31,
	2010 (a) (b)			2009 (b)			Change
Operating revenues	$	19,643		$	13,328		$	6,315
Costs and expenses:
Cost of sales		18,136			11,204			6,932
Operating expenses		912			845			67
Retail selling expenses		173			169			4
General and administrative expenses		97			145			(48	)
Depreciation and amortization expense:
Refining		311			316			(5	)
Retail		26			23			3
Ethanol		8			–			8
Corporate		12			11			1
Asset impairment loss (c)		–			22			(22	)
Total costs and expenses		19,675			12,735			6,940
Operating income (loss)		(32	)		593			(625	)
Other income (expense), net		11			(1	)		12
Interest and debt expense:
Incurred		(147	)		(119	)		(28	)
Capitalized		20			39			(19	)
Income (loss) from continuing operations before income tax expense (benefit)		(148	)		512			(660	)
Income tax expense (benefit)		(47	)		148			(195	)
Income (loss) from continuing operations		(101	)		364			(465	)
Loss from discontinued operations, net of income taxes (b)		(12	)		(55	)		43
Net income (loss)	$	(113	)	$	309		$	(422	)
Earnings (loss) per common share – assuming dilution:
Continuing operations	$	(0.18	)	$	0.70		$	(0.88	)
Discontinued operations		(0.02	)		(0.11	)		0.09
Total	$	(0.20	)	$	0.59		$	(0.79	)

See the footnote references on page 49.

45

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

	Three Months Ended March 31,
	2010			2009			Change
Refining (b):
Operating income (loss)	$	(51	)	$	693		$	(744	)
Throughput margin per barrel (d)	$	5.79		$	8.87		$	(3.08	)
Operating costs per barrel:
Refining operating expenses	$	4.41		$	4.00		$	0.41
Depreciation and amortization		1.65			1.49			0.16
Total operating costs per barrel	$	6.06		$	5.49		$	0.57
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		442			561			(119	)
Medium/light sour crude		464			568			(104	)
Acidic sweet crude		42			107			(65	)
Sweet crude		642			553			89
Residuals		137			118			19
Other feedstocks		128			161			(33	)
Total feedstocks		1,855			2,068			(213	)
Blendstocks and other		240			281			(41	)
Total throughput volumes		2,095			2,349			(254	)
Yields (thousand barrels per day):
Gasolines and blendstocks		1,032			1,053			(21	)
Distillates		659			809			(150	)
Petrochemicals		68			61			7
Other products (e)		357			423			(66	)
Total yields		2,116			2,346			(230	)
Retail – U.S.:
Operating income	$	33		$	25		$	8
Company-operated fuel sites (average)		989			1,004			(15	)
Fuel volumes (gallons per day per site)		4,942			4,984			(42	)
Fuel margin per gallon	$	0.139		$	0.117		$	0.022
Merchandise sales	$	272		$	266		$	6
Merchandise margin (percentage of sales)		29.0	%		30.4	%		(1.4	)%
Margin on miscellaneous sales	$	22		$	23		$	(1	)
Retail selling expenses	$	111		$	114		$	(3	)
Depreciation and amortization expense	$	18		$	17		$	1
Retail – Canada:
Operating income	$	38		$	31		$	7
Fuel volumes (thousand gallons per day)		3,078			3,260			(182	)
Fuel margin per gallon	$	0.299		$	0.250		$	0.049
Merchandise sales	$	52		$	39		$	13
Merchandise margin (percentage of sales)		31.5	%		29.9	%		1.6	%
Margin on miscellaneous sales	$	10		$	8		$	2
Retail selling expenses	$	62		$	55		$	7
Depreciation and amortization expense	$	8		$	6		$	2

See the footnote references on page 49.

46

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

	Three Months Ended March 31,
	2010		2009		Change
Ethanol (a):
Operating income	$	57		N/A	$	57
Ethanol production (thousand gallons per day)		2,534		N/A		2,534
Gross margin per gallon of ethanol production	$	0.63		N/A	$	0.63
Operating costs per gallon of ethanol production:
Ethanol operating expenses	$	0.35		N/A	$	0.35
Depreciation and amortization		0.03		N/A		0.03
Total operating costs per gallon of ethanol production	$	0.38		N/A	$	0.38

See the footnote references on page 49.

47

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

	Three Months Ended March 31,
	2010			2009			Change
Gulf Coast:
Operating income (loss)	$	(11	)	$	190		$	(201	)
Throughput volumes (thousand barrels per day)		1,137			1,315			(178	)
Throughput margin per barrel (d)	$	6.08		$	7.13		$	(1.05	)
Operating costs per barrel (c):
Refining operating expenses	$	4.44		$	4.02		$	0.42
Depreciation and amortization		1.74			1.51			0.23
Total operating costs per barrel	$	6.18		$	5.53		$	0.65
Mid-Continent:
Operating income (loss)	$	(11	)	$	173		$	(184	)
Throughput volumes (thousand barrels per day)		363			400			(37	)
Throughput margin per barrel (d)	$	5.34		$	9.98		$	(4.64	)
Operating costs per barrel (c):
Refining operating expenses	$	4.07		$	3.72		$	0.35
Depreciation and amortization		1.60			1.47			0.13
Total operating costs per barrel	$	5.67		$	5.19		$	0.48
Northeast (b):
Operating income	$	2		$	167		$	(165	)
Throughput volumes (thousand barrels per day)		333			358			(25	)
Throughput margin per barrel (d)	$	5.80		$	9.76		$	(3.96	)
Operating costs per barrel:
Refining operating expenses	$	4.27		$	3.37		$	0.90
Depreciation and amortization		1.47			1.20			0.27
Total operating costs per barrel	$	5.74		$	4.57		$	1.17
West Coast:
Operating income (loss)	$	(31	)	$	185		$	(216	)
Throughput volumes (thousand barrels per day)		262			276			(14	)
Throughput margin per barrel (d)	$	5.20		$	14.40		$	(9.20	)
Operating costs per barrel:
Refining operating expenses	$	4.97		$	5.10		$	(0.13	)
Depreciation and amortization		1.54			1.83			(0.29	)
Total operating costs per barrel	$	6.51		$	6.93		$	(0.42	)
Operating income (loss) for regions above	$	(51	)	$	715		$	(766	)
Asset impairment loss applicable to refining (c)		–			(22	)		22
Total refining operating income (loss)	$	(51	)	$	693		$	(744	)

See the footnote references on page 49.

48

Average Market Reference Prices and Differentials (g)
(dollars per barrel, except as noted)

	Three Months Ended March 31,
	2010		2009			Change
Feedstocks:
West Texas Intermediate (WTI) crude oil	$	78.67	$	42.97		$	35.70
WTI less sour crude oil at U.S. Gulf Coast (h)		3.10		1.71			1.39
WTI less Mars crude oil		2.94		(0.78	)		3.72
WTI less Maya crude oil		8.90		4.46			4.44
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		7.13		8.14			(1.01	)
No. 2 fuel oil less WTI		5.67		10.85			(5.18	)
Ultra-low-sulfur diesel less WTI		7.49		12.61			(5.12	)
Propylene less WTI		17.61		(6.49	)		24.10
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		6.71		8.58			(1.87	)
Low-sulfur diesel less WTI		6.70		11.64			(4.94	)
U.S. Northeast:
Conventional 87 gasoline less WTI		7.88		8.14			(0.26	)
No. 2 fuel oil less WTI		6.88		13.43			(6.55	)
Lube oils less WTI		34.32		67.10			(32.78	)
U.S. West Coast:
CARBOB 87 gasoline less WTI		10.58		19.13			(8.55	)
CARB diesel less WTI		8.43		13.70			(5.27	)
New York Harbor corn crush (dollars per gallon)		0.45		N/A			0.45

The following notes relate to references on pages 45 through 49.
(a)	The information presented for the three months ended March 31, 2010 includes the operations related to the acquisition of seven ethanol plants from VeraSun Energy Corporation in the second quarter of 2009 including plants located Albert City, Charles City, Fort Dodge, and Hartley, Iowa; Aurora, South Dakota; Welcome, Minnesota; and Albion, Nebraska. In addition, information presented for the three months ended March 31, 2010 includes operations related to two ethanol plants purchased on January 13, 2010 from ASA Ethanol Holdings, LLC located in Bloomingburg, Ohio and Linden, Illinois and one ethanol plant purchased on February 4, 2010 from Renew Energy LLC located in Jefferson, Wisconsin. The ethanol production volumes reflected for the three months ended March 31, 2010 are based on total production divided by 90 calendar days.
(b)	Due to the permanent shutdown of our refinery in Delaware City, Delaware during the fourth quarter of 2009, the results of operations of the Delaware City Refinery for both periods presented, as well as costs associated with the shutdown, are reflected as discontinued operations. All refining operating highlights, both consolidated and for the Northeast Region, exclude the Delaware City Refinery for both periods.
(c)	The asset impairment loss for the three months ended March 31, 2009 relates primarily to the permanent cancellation of certain capital projects classified as “construction in progress” as a result of the unfavorable impact of the economic slowdown on refining industry fundamentals. Losses resulting from the permanent cancellation of certain capital projects in 2009 have been reclassified from operating expenses and presented separately for comparability with the 2010 presentation. The asset impairment loss amounts are included in the refining segment operating income but are excluded from the regional operating income amounts and the consolidated and regional operating costs per barrel, resulting in an adjustment to the operating costs per barrel previously reported in 2009.
(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, 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 and Paulsboro Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.

49

(g)	The average market reference prices and differentials are based on posted prices from various pricing services. 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 increased 47% (or $6 billion) for the first quarter of 2010 compared to the first quarter of 2009 primarily as a result of higher refined product prices between the two periods. Operating income declined $625 million and income from continuing operations declined $465 million for the three months ended March 31, 2010 compared to amounts in the first quarter of 2009 primarily due to a $744 million decrease in refining segment operating income discussed below.

Refining

Results from operations of our refining segment decreased from operating income of $693 million for the first quarter of 2009 to an operating loss of $51 million for the first quarter of 2010 resulting from a 35% decrease in throughput margin per barrel ($3.08 per barrel) and an 11% decline in throughput volumes (254,000 barrels per day).

The decrease in the refining throughput margin per barrel for the first quarter of 2010 was primarily due to a significant decrease in gasoline and distillate margins in all of our refining regions. Changes in the margin that we receive for our products have a material impact on our results of operations. For example, the benchmark reference margin for U.S. Gulf Coast No. 2 fuel oil, which is a type of distillate, was $5.67 per barrel for the first quarter of 2010, compared to $10.85 per barrel for the first quarter of 2009, representing a decrease of $5.18 per barrel. Similar decreases in distillate margins were experienced in other regions. We estimate that the decrease in margin for distillates had a $400 million negative impact to our overall refining margin, quarter versus quarter, as we produced 659,000 barrels per day of distillates during the first quarter of 2010.

Similarly, the benchmark reference margin for U.S. Gulf Coast Conventional 87 gasoline was $7.13 per barrel for the first quarter of 2010, compared to $8.14 per barrel for the first quarter of 2009, representing a decrease of $1.01 per barrel. Conventional 87 gasoline benchmark reference margins decreased quarter versus quarter to an even greater extent in the Mid-Continent region ($1.87 per barrel decrease) and West Coast region ($8.55 per barrel decrease). We estimate that the decrease in gasoline margins had a $180 million negative impact to our overall refining margin, quarter versus quarter, as we produced 1.03 million barrels per day of gasoline during the first quarter of 2010.

Gasoline and distillate margins were lower in the first quarter of 2010 as compared to the first quarter of 2009 despite an increase in gasoline and distillate prices in the first quarter of 2010. The decrease in the margin for these products resulted from gasoline and distillate prices increasing at a slower rate than the increase in the price of crude oil. We believe that the increase in the prices of these and other refined products was constrained as compared to the increase in the price of crude oil due to weak demand caused by the economic slowdown and overall customer sensitivity to the absolute prices of these products.

The decrease in throughput volumes during 2010 compared to 2009 was due primarily to the temporary shutdown of our Aruba Refinery commencing in July 2009.

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Retail

Retail operating income was $71 million for the quarter ended March 31, 2010 compared to $56 million for the quarter ended March 31, 2009. This 27% increase was primarily due to improved retail fuel margins combined with lower selling expenses in our U.S. retail operations, partially offset by increased selling expenses in our Canadian retail operations attributable largely to a decrease in the Canadian dollar exchange rate relative to the U.S. dollar.

Ethanol

Ethanol operating income was $57 million for the three months ended March 31, 2010, which represents the operations of the seven ethanol plants acquired in the VeraSun Acquisition in the second quarter of 2009 and the three ethanol plants acquired in the ASA and Renew acquisitions in the first quarter of 2010, as described in Note 3 of Condensed Notes to Consolidated Financial Statements.

Corporate Expenses and Other

General and administrative expenses decreased $48 million from the first quarter of 2009 to the first quarter of 2010 due mainly to a $40 million insurance agreement related to certain litigation, as described in Note 15 of Condensed Notes to Consolidated Financial Statements.

“Other income (expense), net” for the first quarter of 2010 increased from the first quarter of 2009 primarily due to an increase in the market value of assets held by certain of our nonqualified defined benefit and defined contribution plans. These plan assets consist primarily of publicly traded securities.

Interest and debt expense increased from the first quarter of 2009 to the first quarter of 2010 due mainly to interest incurred on $1.0 billion of debt issued in March 2009 and $1.25 billion of debt issued in February 2010, as described in Note 7 of Condensed Notes to Consolidated Financial Statements.

Income tax expense decreased $195 million from the first quarter of 2009 to the first quarter of 2010 mainly as a result of lower operating income, partially offset by a $16 million charge in the first quarter of 2010 related to the non-deductibility of certain retiree prescription health care costs beginning in 2013 in connection with provisions of the recently passed health care reform legislation.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Three Months Ended March 31, 2010 and 2009
Net cash provided by operating activities for the three months ended March 31, 2010 was $982 million compared to $781 million for the three months ended March 31, 2009. The increase in cash generated from operating activities was primarily due to the receipt of a $923 million tax refund in March 2010. Changes in cash provided by or used for working capital during the first three months of 2010 and 2009 are shown in Note 10 of Condensed Notes to Consolidated Financial Statements.

The net cash generated from operating activities during the first three months of 2010, combined with $1.24 billion of proceeds from the issuance of $400 million of 4.50% notes due in February 2015 and $850 million of 6.125% notes due in February 2020 as discussed in Note 7 of Condensed Notes to Consolidated Financial Statements, were used mainly to:

• fund $611 million of capital expenditures and deferred turnaround and catalyst costs;

• pay common stock dividends of $28 million;

• redeem our 7.50% senior notes for $294 million;

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• purchase additional ethanol facilities for $260 million; and

• increase available cash on hand by $1.1 billion.

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

• fund $902 million of capital expenditures and deferred turnaround and catalyst costs;

• pay common stock dividends of $77 million;

• make a $13 million advance payment for the purchase of certain VeraSun ethanol plants; and

• increase available cash on hand by $775 million.

Cash flows related to the discontinued operations of the Delaware City Refinery have been combined with the cash flows from continuing operations within each category in the consolidated statements of cash flows for both periods presented and are summarized as follows (in millions):

	Three Month Ended March 31,
	2010			2009
Cash used in operating activities	$	(12	)	$	(42	)
Cash used in investing activities		–			(34	)

Capital Investments
During the three months ended March 31, 2010, we expended $382 million for capital expenditures and $229 million for deferred turnaround and catalyst costs. Capital expenditures for the three months ended March 31, 2010 included $173 million of costs related to environmental projects.

For 2010, we expect to incur approximately $2.0 billion for capital investments, including approximately $1.5 billion for capital expenditures (approximately $800 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 January 2010, we acquired two ethanol plants and inventories from ASA Ethanol Holdings, LLC for a total purchase price of $202 million. The plants are located in Linden, Indiana and Bloomingburg, Ohio. In February 2010, we acquired an additional ethanol plant located near Jefferson, Wisconsin from Renew Energy LLC plus certain receivables and inventories for a total purchase price of $79 million. Of the $281 million total purchase price paid for these acquisitions, $21 million was paid in the fourth quarter of 2009.

On April 7, 2010, we entered into an agreement to sell the shutdown Delaware City Refinery assets and associated terminal and pipeline assets to wholly owned subsidiaries of PBF Energy Partners LP for $220 million in proceeds. The transaction is expected to close during the second quarter of 2010, subject to regulatory approvals, as well as finalization of certain agreements with the state of Delaware.

Contractual Obligations
As of March 31, 2010, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities.

In February 2010, we issued $400 million of 4.50% notes due in February 2015 and $850 million of 6.125% notes due in February 2020. Proceeds from the issuance of these notes totaled approximately $1.24 billion, before deducting underwriting discounts of $8 million.

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On March 15, 2010, we redeemed our 7.50% senior notes with a maturity date of June 15, 2015 for $294 million, or 102.5% of stated value. These notes had a carrying amount of $296 million as of the redemption date, resulting in a $2 million gain that was included in “other income (expense), net” in the consolidated statement of income.

In March 2010, we called for redemption our 6.75% senior notes with a maturity date of May 1, 2014 for $190 million, or 102.25% of stated value. The redemption date was May 3, 2010. These notes had a carrying amount of $187 million as of the redemption date, resulting in a loss on the redemption of approximately $3 million.

We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables, which matures in June 2010. As of March 31, 2010, the amount of eligible receivables sold to the third-party entities and financial institutions was $200 million. We anticipate that we will be able to renew this facility prior to its expiration in June 2010.

During the three months ended March 31, 2010, 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 March 31, 2010, 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 (negative outlook)
Fitch Ratings	BBB (negative outlook)

The rating agencies have placed a negative outlook on the ratings, which we believe is a result of the weak refining margin environment and general economic slowdown. 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 March 31, 2010, our committed lines of credit were as follows:

	Borrowing
	Capacity	Expiration
Letter of credit facility	$300 million	June 2010
Revolving credit facility (Revolver)	$2.4 billion	November 2012
Canadian revolving credit facility	Cdn. $115 million	December 2012

The Revolver has certain restrictive covenants, including a maximum debt-to-capitalization ratio of 60%. As of March 31, 2010, our debt-to-capitalization ratio, calculated in accordance with the terms of the Revolver, was 30.6%. We believe that we will remain in compliance with this covenant.

As of March 31, 2010, we had $242 million of letters of credit outstanding under our uncommitted short-term bank credit facilities and $329 million of letters of credit outstanding under our U.S. committed credit facilities. Under our Canadian committed revolving credit facility, we had Cdn. $22 million of letters of credit outstanding as of March 31, 2010. Our letters of credit expire during 2010 and 2011. We anticipate that we will be able to renew the letter of credit facility that will expire in June 2010.

Stock Purchase Programs
As of March 31, 2010, 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 15 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 initially was 3% for on-island sales and services (but has subsequently been reduced to 1.5%) and 1% on export sales, is being assessed by the GOA on sales by our Aruba Refinery. We disputed the GOA’s assessment of the turnover tax in arbitration proceedings with the Netherlands Arbitration Institute (NAI) pursuant to which we sought to enforce our rights under a tax holiday agreement related to the refinery and other agreements. 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 $115 million as of both March 31, 2010 and December 31, 2009, respectively, are reflected as restricted cash in our consolidated balance sheets. In addition to the turnover tax described above, the GOA has asserted other tax amounts including approximately

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$35 million related to various dividends. We 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, 2009, 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 uncertain timing of any final resolution of these claims as a result of the First Partial Award from the panel, we recorded a loss contingency accrual of approximately $140 million, including interest, with respect to both the dividend and turnover taxes.

Following the November ruling, we entered into settlement discussions with the GOA. On February 24, 2010, we signed a settlement agreement that details the parties’ proposed terms for settlement of these disputes and provides a framework for taxation of our operations in Aruba on a go-forward basis as our tax holiday was set to expire on December 31, 2010. Under the proposed settlement, we will make a payment to the GOA of $118 million in consideration of a full release of all tax claims prior to the effective date of the settlement, including the turnover tax disputed in the Netherlands Arbitration. The GOA will eliminate the turnover tax on exports as of the effective date of the settlement. In addition, we will agree to exit the tax holiday regime following the effective date of the settlement agreement and will enter into a new tax regime under which we will be subject to a net profit tax of less than 10% on an overall basis. Beginning on the second anniversary of the settlement agreement’s effective date, we will also begin to make an annual prepayment of taxes of $10 million, with the ability to carry forward any excess tax prepayments to future tax years. The proposed settlement will not be effective until the settlement agreement is approved by the Aruban Parliament and certain laws and regulations are modified and/or established to provide for the terms of the settlement. The parties anticipate that this will occur on or before June 1, 2010. If the settlement is not effective as of June 1, 2010, we both have the right to terminate the settlement agreement and return to arbitration and the on-island proceedings to continue litigation.

Other Matters Impacting Liquidity and Capital Resources
During the three months ended March 31, 2010, we contributed $50 million to our qualified pension plans. No additional contributions to the qualified pension plans are anticipated during 2010.

In April 2010, Somali pirates hijacked a South Korean supertanker off the East African coast with a cargo of crude oil that we took title to in March upon loading into the vessel, and the vessel and its cargo are currently in the possession of the Somali pirates. We paid our crude oil supplier for the cargo in April. We believe that we will regain possession of the cargo, and we do not anticipate this matter will have an adverse effect on our financial position, results of operations, or liquidity.

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.

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Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our refineries could require material additional expenditures to comply with environmental laws and regulations.

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

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Our critical accounting policies are disclosed in our annual report on Form 10-K for the year ended December 31, 2009.

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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks related to the volatility in the price of commodities, interest rates and foreign currency exchange rates, and we enter into derivative instruments to manage those risks. We also enter into derivative instruments to manage the price risk on other contractual derivatives into which we have entered. The only types of derivative instruments we enter into are those related to the various commodities we purchase or produce, interest rate swaps, and foreign currency exchange and purchase contracts as described below. All derivative instruments are recorded on our balance sheet as either assets or liabilities measured at their fair values.

COMMODITY PRICE RISK

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

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

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

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

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 corn inventories, and (ii) manage price volatility in certain forecasted refinery feedstock, product, and corn purchases, refined product sales, and natural gas purchases. 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 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.”

Trading Activities – Derivatives entered into for trading activities 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.

The following tables include all positions at the end of the reporting period with which we have market risk. Notional 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 corn). 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 corn). 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 notional contract volume, while the market value amount represents the period-end market price of the commodity being hedged multiplied by the derivative contract volume. The pre-tax fair value for futures, swaps, and options represents the fair value of the derivative contract. The pre-tax fair value for swaps represents the excess of the receive price over the pay price multiplied by the notional contract volumes. For futures and options, the pre-tax fair value represents (i) the excess of the market value amount over the contract amount for long positions, or (ii) the excess of the contract amount over the market value amount for short positions. Additionally, for futures and options, the weighted-average pay price represents the contract price for long positions and the weighted-average receive price represents the contract price for short positions. The weighted-average pay price and weighted-average receive price for options represents their strike price. The contract values, market values, and pre-tax fair values are stated in millions of dollars.

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	March 31, 2010
	Notional		Wtd Avg		Wtd Avg							Pre-tax
	Contract		Pay		Receive		Contract		Market			Fair
	Volumes		Price		Price		Value		Value			Value
Fair Value Hedges:
Futures – short:
2010 (crude oil)		12,036		N/A	$	82.40	$	992	$	1,014		$	(22	)
Cash Flow Hedges:
Swaps – long:
2010 (crude oil)		11,925	$	60.67		84.96		N/A		290			290
2010 (distillate)		20,025		80.86		94.38		N/A		271			271
Swaps – short:
2010 (crude oil)		11,925		84.96		76.81		N/A		(97	)		(97	)
2010 (distillate)		20,025		94.38		77.72		N/A		(334	)		(334	)
Futures – long:
2010 (crude oil)		89		82.17		N/A		7		7			–
Economic Hedges:
Swaps – long:
2010 (crude oil)		82,679		80.87		84.66		N/A		313			313
2010 (distillate)		39,621		84.16		94.30		N/A		402			402
2010 (gasoline)		8,475		79.80		92.12		N/A		104			104
2011 (crude oil)		48,600		84.43		86.07		N/A		79			79
2011 (distillate)		5,850		88.76		97.77		N/A		53			53
2011 (gasoline)		4,950		84.26		93.64		N/A		46			46
Swaps – short:
2010 (crude oil)		63,691		84.68		75.50		N/A		(585	)		(585	)
2010 (distillate)		54,114		94.58		89.20		N/A		(291	)		(291	)
2010 (gasoline)		11,475		92.62		99.35		N/A		77			77
2011 (crude oil)		48,600		86.06		80.46		N/A		(272	)		(272	)
2011 (distillate)		5,850		97.77		108.16		N/A		61			61
2011 (gasoline)		4,950		93.64		101.69		N/A		40			40
Futures – long:
2010 (crude oil)		150,251		78.12		N/A		11,737		12,656			919
2010 (distillate)		63,635		84.74		N/A		5,392		6,037			645
2010 (gasoline)		26,501		93.82		N/A		2,486		2,559			73
2010 (corn)		6,070		3.68		N/A		22		21			(1	)
2011 (distillate)		66		91.19		N/A		6		6			–
2011 (corn)		150		4.21		N/A		1		1			–
Futures – short:
2010 (crude oil)		142,324		N/A		77.11		10,974		12,002			(1,028	)
2010 (distillate)		52,155		N/A		83.64		4,362		4,940			(578	)
2010 (gasoline)		45,238		N/A		94.24		4,263		4,361			(98	)
2010 (corn)		25,255		N/A		3.92		99		89			10
2011 (corn)		860		N/A		4.31		3		3			–
Options – long:
2010 (distillate)		6		80.75		N/A		1		1			–

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	March 31, 2010
	Notional		Wtd Avg		Wtd Avg								Pre-tax
	Contract		Pay		Receive		Contract			Market			Fair
	Volumes		Price		Price		Value			Value			Value
Trading Activities:
Swaps – long:
2010 (crude oil)		13,188	$	73.30	$	84.85		N/A		$	152		$	152
2010 (distillate)		19,853		80.95		93.95		N/A			258			258
2010 (gasoline)		9,330		72.27		93.00		N/A			193			193
2011 (crude oil)		2,565		79.30		86.00		N/A			17			17
2011 (distillate)		600		96.86		98.71		N/A			1			1
2011 (gasoline)		3,000		80.80		93.99		N/A			40			40
Swaps – short:
2010 (crude oil)		12,930		84.85		72.38		N/A			(161	)		(161	)
2010 (distillate)		19,886		94.05		81.28		N/A			(254	)		(254	)
2010 (gasoline)		9,555		92.95		77.65		N/A			(146	)		(146	)
2011 (crude oil)		2,250		85.98		84.10		N/A			(4	)		(4	)
2011 (distillate)		915		98.55		94.95		N/A			(3	)		(3	)
2011 (gasoline)		3,000		93.99		79.62		N/A			(43	)		(43	)
Futures – long:
2010 (crude oil)		20,561		80.51		N/A	$	1,655			1,734			79
2010 (distillate)		19,179		89.17		N/A		1,710			1,779			69
2010 (gasoline)		7,454		91.85		N/A		685			719			34
2010 (natural gas)		310		4.40		N/A		1			1			–
2011 (crude oil)		1,040		84.45		N/A		88			90			2
2011 (distillate)		10		95.91		N/A		1			1			–
Futures – short:
2010 (crude oil)		22,334		N/A		80.45		1,797			1,883			(86	)
2010 (distillate)		19,121		N/A		89.19		1,705			1,773			(68	)
2010 (gasoline)		7,307		N/A		91.60		669			705			(36	)
2010 (natural gas)		310		N/A		4.10		1			1			–
2011 (crude oil)		950		N/A		84.40		80			82			(2	)
2011 (distillate)		70		N/A		99.04		7			7			–
Options – long:
2010 (crude oil)		3,136		64.39		N/A		1			–			1
Options – short:
2010 (crude oil)		5,136		N/A		53.38		(1	)		–			(1	)
Total pre-tax fair value													$	119

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	December 31, 2009
	Notional		Wtd Avg		Wtd Avg							Pre-tax
	Contract		Pay		Receive		Contract		Market			Fair
	Volumes		Price		Price		Value		Value			Value
Fair Value Hedges:
Futures – short:
2010 (crude oil)		4,880		N/A	$	75.65	$	369	$	405		$	(36	)
Cash Flow Hedges:
Swaps – long:
2010 (crude oil)		15,900	$	60.46		82.29		N/A		347			347
2010 (distillate)		26,700		79.80		91.59		N/A		315			315
Swaps – short:
2010 (crude oil)		15,900		82.29		75.51		N/A		(108	)		(108	)
2010 (distillate)		26,700		91.59		77.60		N/A		(374	)		(374	)
Economic Hedges:
Swaps – long:
2010 (crude oil)		111,354		78.92		81.18		N/A		252			252
2010 (distillate)		53,316		83.56		91.34		N/A		415			415
2010 (gasoline)		10,650		79.33		88.26		N/A		95			95
2011 (crude oil)		36,850		85.09		85.75		N/A		24			24
2011 (distillate)		5,850		88.76		96.54		N/A		46			46
2011 (gasoline)		4,950		84.26		92.60		N/A		41			41
Swaps – short:
2010 (crude oil)		93,177		81.79		74.46		N/A		(683	)		(683	)
2010 (distillate)		70,488		91.70		88.90		N/A		(197	)		(197	)
2010 (gasoline)		10,650		88.26		102.59		N/A		153			153
2011 (crude oil)		36,850		85.73		79.89		N/A		(215	)		(215	)
2011 (distillate)		5,850		96.54		108.16		N/A		68			68
2011 (gasoline)		4,950		92.60		101.69		N/A		45			45
Futures – long:
2010 (crude oil)		118,841		73.98		N/A		8,792		9,598			806
2010 (distillate)		80,041		83.58		N/A		6,690		7,376			686
2010 (gasoline)		5,928		85.24		N/A		505		517			12
2010 (corn)		7,155		4.07		N/A		29		30			1
2011 (corn)		150		4.21		N/A		1		1			–
Futures – short:
2010 (crude oil)		130,676		N/A		74.68		9,759		10,603			(844	)
2010 (distillate)		60,958		N/A		82.08		5,003		5,611			(608	)
2010 (gasoline)		7,932		N/A		85.50		678		691			(13	)
2010 (corn)		23,250		N/A		4.13		96		97			(1	)
2011 (corn)		160		N/A		4.28		1		1			–
Options – long:
2010 (crude oil)		500		42.50		N/A		1		–			(1	)
2010 (distillate)		22		39.88		N/A		–		–			–
Options – short:
2010 (crude oil)		500		N/A		42.50		2		–			2

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	December 31, 2009
	Notional		Wtd Avg		Wtd Avg							Pre-tax
	Contract		Pay		Receive		Contract		Market			Fair
	Volumes		Price		Price		Value		Value			Value
Trading Activities:
Swaps – long:
2010 (crude oil)		16,134	$	72.43	$	82.27		N/A	$	159		$	159
2010 (distillate)		23,718		79.88		91.01		N/A		264			264
2010 (gasoline)		11,830		72.19		89.06		N/A		199			199
2011 (crude oil)		1,950		77.45		85.45		N/A		16			16
2011 (gasoline)		3,000		80.80		92.84		N/A		36			36
Swaps – short:
2010 (crude oil)		16,191		82.26		72.30		N/A		(161	)		(161	)
2010 (distillate)		23,796		91.26		80.34		N/A		(260	)		(260	)
2010 (gasoline)		11,695		89.15		76.58		N/A		(147	)		(147	)
2011 (crude oil)		1,950		85.45		83.25		N/A		(4	)		(4	)
2011 (gasoline)		3,000		92.84		79.62		N/A		(40	)		(40	)
Futures – long:
2010 (crude oil)		17,544		77.38		N/A	$	1,358		1,421			63
2010 (distillate)		18,285		87.75		N/A		1,605		1,644			39
2010 (gasoline)		4,359		86.50		N/A		377		394			17
2010 (natural gas)		100		6.10		N/A		1		1			–
2011 (distillate)		10		95.91		N/A		1		1			–
Futures – short:
2010 (crude oil)		17,464		N/A		77.18		1,348		1,414			(66	)
2010 (distillate)		18,269		N/A		87.74		1,603		1,643			(40	)
2010 (gasoline)		4,431		N/A		85.73		380		397			(17	)
2010 (natural gas)		100		N/A		5.46		1		1			–
2011 (distillate)		10		N/A		95.91		1		1			–
Options – long:
2010 (crude oil)		250		45.00		N/A		–		–			–
Options – short:
2010 (crude oil)		1,250		N/A		41.67		5		2			3
Total pre-tax fair value												$	289

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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 March 31, 2010 and December 31, 2009.

	March 31, 2010
	Expected Maturity Dates
																There-						Fair
	2010			2011			2012			2013			2014			after			Total			Value
Debt:
Fixed rate	$	219		$	418		$	759		$	489		$	209		$	6,089		$	8,183		$	9,129
Average interest rate		6.8	%		6.4	%		6.9	%		5.5	%		4.8	%		7.1	%		6.9	%
Floating rate	$	200		$	–		$	–		$	–		$	–		$	–		$	200		$	200
Average interest rate		0.8	%		–	%		–	%		–	%		–	%		–	%		0.8	%

	December 31, 2009
	Expected Maturity Dates
																There-						Fair
	2010			2011			2012			2013			2014			after			Total			Value
Debt:
Fixed rate	$	33		$	418		$	759		$	489		$	395		$	5,126		$	7,220		$	8,028
Average interest rate		6.8	%		6.4	%		6.9	%		5.5	%		5.7	%		7.5	%		7.1	%
Floating rate	$	200		$	–		$	–		$	–		$	–		$	–		$	200		$	200
Average interest rate		0.9	%		–	%		–	%		–	%		–	%		–	%		0.9	%

FOREIGN CURRENCY RISK

As of March 31, 2010, we had commitments to purchase $189 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before April 16, 2010, resulting in a $1 million loss in the second quarter of 2010.

Item 4. Controls and Procedures

(a)	Evaluation of disclosure controls and procedures.
	Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of March 31, 2010.
(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, 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 15 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.

New Jersey Department of Environmental Protection (NJDEP)(Paulsboro Refinery). The NJDEP has issued four Administrative Order and Notice of Civil Administrative Penalty Assessments (Notices) to our Paulsboro Refinery since December 2009 relating to alleged excess air emissions and deviations reported for CCR catalyst samples and FCC scrubber monitoring. The Notices assess penalties of $210,200 in the aggregate. We have commenced discussions with the NJDEP to resolve these matters

South Coast Air Quality Management District (SCAQMD)(Wilmington Refinery). In our Form 10-K for the year ended December 31, 2009, we reported that we had 29 notices of violation (NOVs) issued by the SCAQMD from 2008 to 2009 for various alleged air regulation and air permit violations at our Wilmington Refinery and asphalt plant. In the first quarter of 2010, we completed the settlement of all of these NOVs with the SCAQMD.

Texas Commission on Environmental Quality (TCEQ)(McKee Refinery). In our Form 10-K for the year ended December 31, 2009, we reported that our McKee Refinery had received an agreed order from the TCEQ for a number of self-reported Title V permit deviations that occurred in 2008 and several emission events that occurred in 2009. We settled this matter with the TCEQ in April 2010.

TCEQ(Port Arthur Refinery). In our Form 10-K for the year ended December 31, 2009, we reported that our Port Arthur Refinery had received a proposed agreed order from the TCEQ relating to alleged multiple emissions events in 2008 and early 2009. In the first quarter of 2010, we settled this matter with the TCEQ.

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Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2009.

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)
January 2010		29,628	$	17.98		29,628		–	$3.46 billion
February 2010		17,015	$	18.60		17,015		–	$3.46 billion
March 2010		8,694	$	18.90		8,694		–	$3.46 billion
Total		55,337	$	18.31		55,337		–	$3.46 billion

(1)

The shares reported in this column represent purchases settled in the first quarter of 2010 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 $3 billion common stock purchase program, which is in addition to the $6 billion program. This $3 billion program has no expiration date.

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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 March 31, 2010, 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: May 7, 2010

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