Valero Energy (VLO) 10-Q 2010 Q2 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 June 30, 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
(State or other jurisdiction of
incorporation or organization) 74-1828067
(I.R.S. Employer
Identification No.)

One Valero Way
San Antonio, Texas
(Address of principal executive offices)
78249
(Zip Code)

(210) 345-2000
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for shorter period that the registrant was required to submit and post such files). Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filerþ Accelerated filero Non-accelerated filero Smaller reporting companyo

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

The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of July 30, 2010 was 566,260,467.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

INDEX

	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009		3
Consolidated Statements of Income for the Three and Six Months Ended June 30, 2010 and 2009		4
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009		5
Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 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		65
Item 4. Controls and Procedures		66
PART II – OTHER INFORMATION
Item 1. Legal Proceedings		67
Item 1A. Risk Factors		68
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		70
Item 6. Exhibits		71
SIGNATURE		72
EX-12.01
EX-31.01
EX-31.02
EX-32.01
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

2

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

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

	June 30,			December 31,
	2010			2009
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	2,001		$	825
Restricted cash		13			122
Receivables, net		4,122			3,773
Inventories		4,767			4,863
Income taxes receivable		79			888
Deferred income taxes		171			180
Prepaid expenses and other		170			261
Assets held for sale and assets related to discontinued operations		25			224
Total current assets		11,348			11,136
Property, plant and equipment, at cost		29,439			28,463
Accumulated depreciation		(6,076	)		(5,592	)
Property, plant and equipment, net		23,363			22,871
Intangible assets, net		223			227
Deferred charges and other assets, net		1,543			1,395
Total assets	$	36,477		$	35,629
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	523		$	237
Accounts payable		5,856			5,760
Accrued expenses		440			514
Taxes other than income taxes		572			725
Income taxes payable		237			95
Deferred income taxes		184			253
Liabilities related to discontinued operations		102			225
Total current liabilities		7,914			7,809
Debt and capital lease obligations, less current portion		7,511			7,163
Deferred income taxes		4,270			4,063
Other long-term liabilities		1,731			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		7,833			7,896
Treasury stock, at cost; 107,249,003 and 108,798,847 common shares		(6,620	)		(6,721	)
Retained earnings		13,591			13,178
Accumulated other comprehensive income		240			365
Total stockholders’ equity		15,051			14,725
Total liabilities and stockholders’ equity	$	36,477		$	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						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Operating revenues (1)	$	21,775		$	17,376		$	41,418		$	30,704
Costs and expenses:
Cost of sales		19,320			16,014			37,456			27,218
Operating expenses		847			781			1,759			1,626
Retail selling expenses		187			171			360			340
General and administrative expenses		131			122			228			267
Depreciation and amortization expense		367			361			724			711
Asset impairment loss		2			119			2			141
Total costs and expenses		20,854			17,568			40,529			30,303
Operating income (loss)		921			(192	)		889			401	��
Other income (expense), net		1			(23	)		12			(24	)
Interest and debt expense:
Incurred		(138	)		(118	)		(285	)		(237	)
Capitalized		22			34			42			73
Income (loss) from continuing operations before income tax expense (benefit)		806			(299	)		658			213
Income tax expense (benefit)		276			(108	)		229			40
Income (loss) from continuing operations		530			(191	)		429			173
Income (loss) from discontinued operations, net of income taxes		53			(63	)		41			(118	)
Net income (loss)	$	583		$	(254	)	$	470		$	55
Earnings (loss) per common share:
Continuing operations	$	0.94		$	(0.36	)	$	0.76		$	0.33
Discontinued operations		0.10			(0.12	)		0.07			(0.22	)
Total	$	1.04		$	(0.48	)	$	0.83		$	0.11
Weighted-average common shares outstanding (in millions)		563			525			563			520
Earnings (loss) per common share – assuming dilution:
Continuing operations	$	0.93		$	(0.36	)	$	0.76		$	0.33
Discontinued operations		0.10			(0.12	)		0.07			(0.22	)
Total	$	1.03		$	(0.48	)	$	0.83		$	0.11
Weighted-average common shares outstanding – assuming dilution (in millions)		567			525			567			525
Dividends per common share	$	0.05		$	0.15		$	0.10		$	0.30
Supplemental information:
(1) Includes excise taxes on sales by our U.S. retail system	$	225		$	229		$	433		$	433

See Condensed Notes to Consolidated Financial Statements.

4

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

	Six Months Ended June 30,
	2010			2009
Cash flows from operating activities:
Net income	$	470		$	55
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		724			767
Asset impairment loss		2			159
Gain on sale of Delaware City Refinery assets		(92	)		–
Noncash interest expense and other income, net		4			15
Stock-based compensation expense		22			23
Deferred income tax expense (benefit)		83			(125	)
Changes in current assets and current liabilities		613			557
Changes in deferred charges and credits and other operating activities, net		(56	)		(44	)
Net cash provided by operating activities		1,770			1,407
Cash flows from investing activities:
Capital expenditures		(785	)		(1,351	)
Deferred turnaround and catalyst costs		(343	)		(249	)
Purchase of ethanol facilities		(260	)		(556	)
Proceeds from the sale of the Delaware City Refinery assets and associated terminal and pipeline assets		220			–
Minor acquisitions		–			(29	)
Other investing activities, net		11			11
Net cash used in investing activities		(1,157	)		(2,174	)
Cash flows from financing activities:
Non-bank debt:
Borrowings		1,244			998
Repayments		(517	)		(209	)
Accounts receivable sales program:
Proceeds from sale of receivables		1,225			500
Repayments		(1,325	)		(500	)
Proceeds from the sale of common stock, net of issuance costs		–			799
Issuance of common stock in connection with employee benefit plans		11			4
Common stock dividends		(57	)		(155	)
Debt issuance costs		(10	)		(8	)
Other financing activities, net		4			(1	)
Net cash provided by financing activities		575			1,428
Effect of foreign exchange rate changes on cash		(12	)		22
Net increase in cash and temporary cash investments		1,176			683
Cash and temporary cash investments at beginning of period		825			940
Cash and temporary cash investments at end of period	$	2,001		$	1,623

See Condensed Notes to Consolidated Financial Statements.

5

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Net income (loss)	$	583		$	(254	)	$	470		$	55
Other comprehensive income (loss):
Foreign currency translation adjustment		(138	)		191			(37	)		110
Pension and other postretirement benefits:
Net loss arising during the period, net of income tax benefit of $–, $–, $–, and $–		(21	)		–			(21	)		–
Net gain reclassified into income, net of income tax expense of $–, $–, $–, and $–		(1	)		–			(2	)		–
Net loss on pension and other postretirement benefits		(22	)		–			(23	)		–
Derivative instruments designated and qualifying as cash flow hedges:
Net gain (loss) arising during the period, net of income tax (expense) benefit of $–, $(2), $1, and $(34)		–			3			(1	)		63
Net gain reclassified into income, net of income tax expense of $17, $39, $34, and $60		(32	)		(72	)		(64	)		(112	)
Net loss on cash flow hedges		(32	)		(69	)		(65	)		(49	)
Other comprehensive income (loss)		(192	)		122			(125	)		61
Comprehensive income (loss)	$	391		$	(132	)	$	345		$	116

See Condensed Notes to Consolidated Financial Statements.

6

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

These unaudited consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the three and six months ended June 30, 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 and six months ended June 30, 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 June 30, 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 us 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, we review our 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 shutdown refinery and associated terminal and pipeline 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 June 30, 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 all 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 consolidated statements of income. These asset impairment losses resulted from the cancellation of certain capital projects classified as “construction in progress,” and for the three and six months ended June 30, 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 six months ended June 30, 2009. Asset impairment losses presented in the consolidated statements of cash flows for the six months ended June 30, 2009 includes asset impairment losses associated with the Delaware City Refinery, but such losses 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 (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.

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.

8

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

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

Current assets, primarily inventory	$	11
Property, plant and equipment		269
Identifiable intangible assets		1
Total consideration	$	281

Neither goodwill nor a gain from a bargain purchase was 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 and six months ended June 30, 2009 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 six months ended June 30, 2010 includes the results of the ASA and Renew acquisitions as of their 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.

The assets acquired and liabilities assumed were recognized at their acquisition-date fair values as determined by an independent 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 contingent assets or liabilities were acquired or assumed in the acquisition.

9

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

The consolidated statements of income include the results of operations of the ethanol plants commencing on their closing dates in the second quarter of 2009. Two of the acquired plants with closing dates subsequent to April 1, 2009 were not operating at the time of acquisition. Therefore, pro forma information for the three months ended June 30, 2009 is the same as our actual consolidated results of operations for that period. The pro forma information presented below for the six months ended June 30, 2009 assumes that the VeraSun Acquisition occurred on January 1, 2009 and that the purchase price was funded with proceeds from the issuance of $556 million of debt on January 1, 2009. The consolidated pro forma operating revenues, net income, and earnings per common share – assuming dilution of the combined entity are shown in the table below (in millions, except per share amount).

	Six Months Ended
	June 30, 2009
Consolidated pro forma:
Operating revenues	$	30,927
Income from continuing operations		166
Earnings per common share from continuing operations – assuming dilution		0.32

4. SALE OF DELAWARE CITY REFINERY ASSETS AND ASSOCIATED TERMINAL AND PIPELINE ASSETS

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 all 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 continued to be operated until the date of their sale. The results of their operations are reflected in continuing operations in the consolidated statements of income for all periods presented due to our post-closing participation in the terminalling agreement described below.

In the first quarter of 2010, our board of directors approved a plan of sale for our shutdown refinery assets and associated terminal and pipeline assets at Delaware City. Effective June 1, 2010, we sold these assets to wholly owned subsidiaries of PBF Energy Partners LP (PBF) for $220 million of cash proceeds. The sale resulted in a gain of $92 million related to the shutdown refinery assets and a gain of $3 million related to the terminal and pipeline assets. The gain on the sale of the shutdown refinery assets primarily resulted from the scrap value of the assets and the reversal of certain liabilities recorded in the fourth quarter of 2009 associated with the shutdown of the refinery, which we will not incur because of the sale. This gain is presented in “income (loss) from discontinued operations, net of income taxes” in the consolidated statements of income for the three and six months ended June 30, 2010.

The shutdown refinery assets and the associated terminal and pipeline assets were presented in the consolidated balance sheets within assets held for sale as of December 31, 2009. All other related assets and liabilities of the shutdown refinery that were not sold are presented as assets and liabilities related to discontinued operations as of June 30, 2010 and December 31, 2009 summarized as follows (in millions).

10

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

	June 30, 2010
			Assets and
			Liabilities
	Assets		Related to
	Held		Discontinued
	for Sale		Operations		Total
Current assets:
Receivables, net	$	–	$	6	$	6
Deferred income taxes		–		19		19
Current assets	$	–	$	25	$	25
Current liabilities:
Accounts payable	$	–	$	4	$	4
Accrued expenses		–		98		98
Current liabilities	$	–	$	102	$	102
	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	$	–	$	36	$	36
Accrued expenses		–		189		189
Current liabilities	$	–	$	225	$	225

Results of operations for the Delaware City Refinery prior to its sale, excluding the gain on the sale, are summarized as follows (in millions):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Operating revenues	$	–		$	549		$	–		$	1,045
Loss before income tax benefit		(7	)		(124	)		(33	)		(209	)

11

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

In connection with this sale, we entered 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 have agreed to purchase certain off-take products as prescribed in the agreement. The initial term of this agreement is for one year and shall automatically renew for 180-day periods until terminated by either party.

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 strategic alternatives, including potential sales of our Aruba and Paulsboro Refineries to develop expected future cash flows for those refineries. We determined that there was no indication of impairment of our refining operating assets as of December 31, 2009.

While the economy and refining industry fundamentals improved during the first six months 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 June 30, 2010, and we determined that there was no indication of impairment. Our cash flow estimates are based on expected improvements in refined product prices resulting from an expected improvement in the U.S. and worldwide economies. We updated our assumptions related to matters specific to our Aruba and Paulsboro Refineries that impact their expected future cash flows, as further discussed below, because the sensitivity of our estimates is most significant with respect to 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.

Our Aruba Refinery was shut down in July 2009 because narrow heavy sour crude oil differentials made the refinery uneconomical to operate. In addition, various tax disputes with the Government of Aruba (GOA) created uncertainties with respect to the future economics of the refinery. As discussed in Note 15, we entered into a settlement agreement with the GOA on February 24, 2010, and that agreement became effective June 1, 2010. We also entered into a new tax regime in Aruba effective June 1, 2010, which resolved uncertainties regarding the tax environment in Aruba. In addition, heavy sour crude oil differentials began to widen in the first six months of 2010. Because of these positive developments, we commenced refinery-wide maintenance to prepare the refinery’s production units for potential restart by the end of the third quarter of 2010. We considered these positive developments in our updated impairment evaluation of the operating assets of the Aruba Refinery, and that evaluation indicated that there was no impairment. However, future decisions regarding the timing of a restart of the refinery that differ materially from our expectations or a decision to permanently shut down the refinery would have a significant impact on our cash flow estimates, and we could determine that the refinery’s operating assets are impaired. The Aruba Refinery had a net book value of $1.1 billion as of June 30, 2010; therefore, an impairment loss could be material to our results of operations.

12

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

We have continued to evaluate strategic alternatives for our Paulsboro Refinery, and we entered into negotiations related to a potential sale of the refinery in the second quarter of 2010. Negotiations are proceeding, but there is no certainty that we will sell the refinery. Our updated evaluation of a potential impairment of the operating assets of the Paulsboro Refinery considered the possibility of selling the refinery based on the facts and circumstances that existed as of June 30, 2010, and that evaluation indicated that there was no impairment. The Paulsboro Refinery had a net book value of $1.3 billion as of June 30, 2010; therefore, an 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.

6. INVENTORIES

Inventories consisted of the following (in millions):

	June 30,		December 31,
	2010		2009
Refinery feedstocks	$	2,572	$	2,124
Refined products and blendstocks		1,719		2,317
Ethanol feedstocks and products		187		141
Convenience store merchandise		96		96
Materials and supplies		193		185
Inventories	$	4,767	$	4,863

As of June 30, 2010 and December 31, 2009, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $4.3 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 $998 million, before deducting underwriting discounts and other issuance costs of $8 million.

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

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 $1.244 billion, before deducting underwriting discounts and other issuance costs of $10 million.

In March 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)” in the consolidated statements of income.

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In April 2010, we made scheduled debt repayments of $8 million related to our Series A 5.45%, Series B 5.40%, and Series C 5.40% industrial revenue bonds.

In May 2010, we redeemed our 6.75% senior notes with a maturity date of May 1, 2014 for $190 million, or 102.25% of stated value. These notes had a carrying amount of $187 million as of the redemption date, resulting in a $3 million dollar loss that was included in “other income (expense)” in the consolidated statements of income.

In June 2010, we made scheduled debt repayments of $25 million related to our 7.25% debentures.

Bank Credit Facilities

We have a revolving credit facility (the Revolver) that has a maturity date of November 2012. As of June 30, 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 June 30, 2010 and December 31, 2009, our debt-to-capitalization ratios, calculated in accordance with the terms of the Revolver, were 28.6% and 30.9%, respectively. We believe that we will remain in compliance with this covenant.

During the six months ended June 30, 2010, we had no borrowings or repayments under our Revolver or other revolving bank credit facilities. As of June 30, 2010 and December 31, 2009, we had no borrowings outstanding under these committed revolving bank credit facilities.

As of June 30, 2010 and December 31, 2009, we had $76 million and $259 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities and $225 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. $20 million and Cdn. $22 million of letters of credit outstanding as of June 30, 2010 and December 31, 2009 respectively.

In June 2010, we entered into a one-year committed revolving letter of credit facility under which we may obtain letters of credit of up to $300 million to support certain of our crude oil purchases. This agreement matures in June 2011.

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 2010 to extend the maturity date to June 2011. As of December 31, 2009, the amount of eligible receivables sold was $200 million. During the six months ended June 30, 2010, we sold $1.2 billion of eligible receivables and repaid $1.3 billion. As of June 30, 2010, the amount of eligible receivables sold was $100 million. Proceeds from the sale of receivables under this facility are reflected as debt in our consolidated balance sheets.

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Other Disclosures

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

	June 30,		December 31,
	2010		2009
Carrying amount	$	7,996	$	7,364
Fair value		9,360		8,228

8. STOCKHOLDERS’ EQUITY

Treasury Stock

No significant purchases of our common stock were made during the six months ended June 30, 2010 and 2009. During the six months ended June 30, 2010 and 2009, we issued 1.5 million shares and 0.5 million shares from treasury, respectively, for our employee benefit plans.

Common Stock Dividends

On July 29, 2010, our board of directors declared a regular quarterly cash dividend of $0.05 per common share payable on September 15, 2010 to holders of record at the close of business on August 18, 2010.

Common Stock Offering

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

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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 June 30,
	2010				2009
	Restricted		Common		Restricted		Common
	Stock		Stock		Stock		Stock
Earnings (loss) per common share from continuing operations:
Income (loss) from continuing operations			$	530			$	(191	)
Less dividends paid:
Common stock				29				77
Nonvested restricted stock				–				1
Undistributed earnings (loss)			$	501			$	(269	)
Weighted-average common shares outstanding		3		563		2		525
Earnings (loss) per common share from continuing operations:
Distributed earnings	$	0.05	$	0.05	$	0.15	$	0.15
Undistributed earnings (loss)		0.89		0.89		–		(0.51	)
Total earnings (loss) per common share from continuing operations	$	0.94	$	0.94	$	0.15	$	(0.36	)
Earnings (loss) per common share from continuing operations – assuming dilution:
Income (loss) from continuing operations			$	530			$	(191	)
Weighted-average common shares outstanding				563				525
Common equivalent shares (1):
Stock options				3				–
Performance awards and unvested restricted stock				1				–
Weighted-average common shares outstanding – assuming dilution				567				525
Earnings (loss) per common share from continuing operations – assuming dilution			$	0.93			$	(0.36	)

(1) Common equivalent shares were excluded from the computation of diluted loss per share for the three months ended June 30, 2009 because the effect of including such shares would be antidilutive.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Six Months Ended June 30,
	2010				2009
	Restricted		Common		Restricted		Common
	Stock		Stock		Stock		Stock
Earnings per common share from continuing operations:
Income from continuing operations			$	429			$	173
Less dividends paid:
Common stock				57				154
Nonvested restricted stock				–				1
Undistributed earnings			$	372			$	18
Weighted-average common shares outstanding		3		563		2		520
Earnings per common share from continuing operations:
Distributed earnings	$	0.10	$	0.10	$	0.30	$	0.30
Undistributed earnings		0.66		0.66		0.03		0.03
Total earnings per common share from continuing operations	$	0.76	$	0.76	$	0.33	$	0.33
Earnings per common share from continuing operations – assuming dilution:
Income from continuing operations			$	429			$	173
Weighted-average common shares outstanding				563				520
Common equivalent shares:
Stock options				3				4
Performance awards and unvested restricted stock				1				1
Weighted-average common shares outstanding – assuming dilution				567				525
Earnings per common share from continuing operations – assuming dilution			$	0.76			$	0.33

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table reflects potentially dilutive securities (in millions) 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. These potentially dilutive securities included common equivalent shares (primarily stock options), which were excluded due to the loss from continuing operations for the three months ended June 30, 2009, and stock options for which the exercise prices were greater than the average market price of the common shares during each respective reporting period.

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Common equivalent shares		–		5		–		–
Stock options		11		11		11		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):

	Six Months Ended June 30,
	2010			2009
Decrease (increase) in current assets:
Restricted cash	$	109		$	(10	)
Receivables, net		(394	)		(1,286	)
Inventories		102			172
Income taxes receivable		808			181
Prepaid expenses and other		15			11
Increase (decrease) in current liabilities:
Accounts payable		122			1,592
Accrued expenses		(145	)		(97	)
Taxes other than income taxes		(151	)		(41	)
Income taxes payable		147			35
Changes in current assets and current liabilities	$	613		$	557

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

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

There were no significant noncash investing or financing activities for the six months ended June 30, 2010 and 2009.

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

	Six Months Ended June 30,
	2010			2009
Interest paid in excess of amount capitalized	$	225		$	152
Income taxes paid (received), net		(797	)		(144	)

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):

	Six Months Ended June 30,
	2010			2009
Cash used in operating activities	$	(76	)	$	(134	)
Cash used in investing activities		–			(67	)

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 June 30, 2010 and December 31, 2009.

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	Fair Value Measurements Using
	Quoted		Significant
	Prices		Other		Significant
	in Active		Observable		Unobservable		Total as of
	Markets		Inputs		Inputs		June 30,
	(Level 1)		(Level 2)		(Level 3)		2010
Assets:
Commodity derivative contracts	$	27	$	169	$	–	$	196
Nonqualified benefit plans		95		–		10		105
Liabilities:
Commodity derivative contracts		17		7		–		24
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
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 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 value of which is provided by the insurer.

As of June 30, 2010 and December 31, 2009, cash received from brokers of $58 million and $64 million, respectively, resulting from the equity in broker accounts covered by master netting arrangements exceeding the minimum margin requirements for such accounts, is netted against the fair value of the commodity derivatives reflected in Level 1.Certain of our commodity derivative contracts under master netting arrangements include both asset and liability positions. We have elected to offset the fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty, including any related cash collateral asset or obligation.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following is a reconciliation of the beginning and ending balances (in millions) for fair value measurements developed using significant unobservable inputs for the three and six months ended June 30, 2010 and 2009.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Balance at beginning of period	$	10	$	24	$	10	$	13
Net unrealized gains included in earnings		–		14		–		25
Balance at end of period	$	10	$	38	$	10	$	38

Unrealized gains for the three and six months ended June 30, 2009, which are reported in “other income (expense), net” in the consolidated statements of income, relate to the 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. That agreement was settled in August 2009. These unrealized gains were offset by the recognition in “other income (expense), net” of losses on commodity 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.

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

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

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 June 30, 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 Contract
	Volumes by
Derivative Instrument	Year of Maturity
	2010
Crude oil and refined products:
Futures - short		17,796

Cash Flow Hedges

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

As of June 30, 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 Contract
	Volumes by
Derivative Instrument	Year of Maturity
	2010
Crude oil and refined products:
Swaps - long		21,300
Swaps - short		21,300

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

Economic Hedges

Economic hedges are hedges not designated as fair value or cash flow hedges that are used to (i) manage price volatility in certain refinery feedstock, refined product and corn inventories, and (ii) manage price volatility in certain forecasted refinery feedstock, refined 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 June 30, 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 Contract Volumes by
Derivative Instrument	Year of Maturity
	2010		2011
Crude oil and refined products:
Swaps - long		120,048		83,017
Swaps - short		118,363		83,005
Futures - long		334,198		3,118
Futures - short		327,138		3,035
Corn:
Futures - long		24,535		165
Futures - short		49,305		2,605

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

Trading Activities

Derivatives entered into for trading purposes 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 we perceive as opportunities to benefit our results of operations and cash flows, but for which there are no related physical transactions.

As of June 30, 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 Contract Volumes by
Derivative Instrument	Year of Maturity
	2010		2011
Crude oil and refined products:
Swaps - long		29,809		9,720
Swaps - short		29,384		9,720
Futures - long		50,291		3,296
Futures - short		50,602		3,079
Options - long		350		–
Options - short		400		–
Natural gas:
Futures - long		3,950		–
Futures - short		3,950		–

Interest Rate Risk

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

Foreign Currency Risk

We are exposed to exchange rate fluctuations on transactions related to our Canadian operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of June 30, 2010, we had commitments to purchase $325 million of U.S. dollars. These commitments matured on or before July 30, 2010.

Fair Values of Derivative Instruments

The following tables provide information about the fair values of our derivative instruments as of June 30, 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

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 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	June 30,		Balance Sheet	June 30,
	Location	2010		Location	2010
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	9	Receivables, net	$	6
Futures	Accrued expenses		442	Accrued expenses		520
Swaps	Receivables, net		114	Receivables, net		101
Swaps	Prepaid expenses and other		153	Prepaid expenses and other		70
Swaps	Accrued expenses		3	Accrued expenses		3
Total derivatives designated as hedging instruments		$	721		$	700
Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	24	Receivables, net	$	21
Futures	Accrued expenses		3,201	Accrued expenses		3,061
Swaps	Receivables, net		276	Receivables, net		195
Swaps	Prepaid expenses and other		638	Prepaid expenses and other		645
Swaps	Accrued expenses		3	Accrued expenses		11
Options	Accrued expenses		1	Accrued expenses		1
Total derivatives not designated as hedging instruments		$	4,143		$	3,934
Total derivatives		$	4,864		$	4,634

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

As of June 30, 2010, we had net receivables related to derivative instruments of $11 million from counterparties in the refining industry and $65 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

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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 Statements of Comprehensive Income

The following tables provide information about the gain or loss recognized in income and other comprehensive income on our derivative instruments for the three and six months ended June 30, 2010 and 2009 (in millions), and the line items in the financial statements in which such gains and losses are reflected.

													Gain or (Loss)
Derivatives in	Gain or (Loss)						Gain or (Loss)						Recognized in
Fair Value	Recognized in						Recognized in						Income for
Hedging	Income on						Income on						Ineffective Portion
Relationships	Derivatives						Hedged Item						of Derivative (1)
	Location	Amount					Location	Amount					Amount
		2010		2009				2010			2009		2010		2009
Three months ended June 30:
Commodity contracts	Cost of sales	$	216	$	(74	)	Cost of sales	$	(207	)	$	75	$	9	$	1
Six months ended June 30:
Commodity contracts	Cost of sales		199		(89	)	Cost of sales		(191	)		90		8		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.

	Gain or (Loss)					Gain or (Loss)
Derivatives in	Recognized in					Reclassified from					Gain or (Loss)
Cash Flow	OCI on					Accumulated OCI into					Recognized in
Hedging	Derivatives					Income					Income on Derivatives
Relationships	(Effective Portion)					(Effective Portion)					(Ineffective Portion) (1)
	Amount					Location	Amount				Location	Amount
	2010			2009			2010		2009			2010		2009
Three months ended June 30:
Commodity contracts (2)	$	–		$	5	Cost of sales	$	49	$	111	Cost of sales	$	–	$	(1	)
Six months ended June 30:
Commodity contracts (2)		(2	)		97	Cost of sales		98		172	Cost of sales		–		(1	)

(1)

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

(2)

For the three and six months ended June 30, 2010, cash flow hedges primarily related to forward sales of distillates and associated forward purchases of crude oil, with $52 million of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive income as of June 30, 2010. We expect that all of the deferred gains as of June 30, 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 and six months ended June 30, 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.

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

Derivatives Designated as	Location of Gain or (Loss)	Amount of Gain or (Loss)
Economic Hedges and Other	Recognized in Income on	Recognized in
Derivative Instruments	Derivatives	Income on Derivatives
		2010			2009
Three Months Ended June 30:
Commodity contracts	Cost of sales	$	(76	)	$	(58	)
Foreign currency contracts	Cost of sales		16			(22	)
			(60	)		(80	)
Alon earn-out agreement	Other income (expense)		–			14
Alon earn-out hedge (commodity contracts)	Other income (expense)		–			(48	)
			–			(34	)
Total		$	(60	)	$	(114	)
Six Months Ended June 30:
Commodity contracts	Cost of sales	$	(115	)	$	38
Foreign currency contracts	Cost of sales		3			(16	)
			(112	)		22
Alon earn-out agreement	Other income (expense)		–			25
Alon earn-out hedge (commodity contracts)	Other income (expense)		–			(63	)
			–			(38	)
Total		$	(112	)	$	(16	)

	Location of Gain or (Loss)	Amount of Gain or (Loss)
Derivatives Designated as	Recognized in Income on	Recognized in Income on
Trading Activities	Derivatives	Derivatives
		2010		2009
Three Months Ended June 30:
Commodity contracts	Cost of sales	$	8	$	25
Six Months Ended June 30:
Commodity contracts	Cost of sales		5		116

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 June 30, 2010:
Operating revenues from external customers	$	18,760		$	2,357	$	658	$	–		$	21,775
Intersegment revenues		1,591			–		56		–			1,647
Operating income (loss)		921			109		35		(144	)		921
Three months ended June 30, 2009:
Operating revenues from external customers		15,144			1,969		263		–			17,376
Intersegment revenues		1,281			–		29		–			1,310
Operating income (loss)		(143	)		65		22		(136	)		(192	)
Six months ended June 30, 2010:
Operating revenues from external customers		35,657			4,533		1,228		–			41,418
Intersegment revenues		3,099			–		111		–			3,210
Operating income (loss)		870			180		92		(253	)		889
Six months ended June 30, 2009:
Operating revenues from external customers		26,840			3,601		263		–			30,704
Intersegment revenues		2,288			–		29		–			2,317
Operating income (loss)		550			121		22		(292	)		401

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

	June 30,		December 31,
	2010		2009
Refining	$	31,010	$	30,901
Retail		1,836		1,875
Ethanol		949		654
Corporate		2,682		2,199
Total consolidated assets	$	36,477	$	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 and six months ended June 30, 2010 and 2009 (in millions):

							Other Postretirement
	Pension Plans						Benefit Plans
	2010			2009			2010			2009
Three months ended June 30:
Components of net periodic benefit cost:
Service cost	$	21		$	26		$	2		$	3
Interest cost		21			20			7			7
Expected return on plan assets		(28	)		(27	)		–			–
Amortization of:
Prior service cost (credit)		–			1			(5	)		(5	)
Net loss		1			2			1			1
Net periodic benefit cost	$	15		$	22		$	5		$	6
Six months ended June 30:
Components of net periodic benefit cost:
Service cost	$	43		$	52		$	5		$	6
Interest cost		41			40			13			13
Expected return on plan assets		(56	)		(54	)		–			–
Amortization of:
Prior service cost (credit)		1			1			(10	)		(9	)
Net loss		1			5			2			3
Net periodic benefit cost	$	30		$	44		$	10		$	13

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 six-month periods ended June 30, 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 expense presented in our consolidated statement of income for the six months ended June 30, 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 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 June 1, 2010, the GOA enacted a new tax regime applicable to refinery and terminal operations in Aruba. Under the new tax regime, we are subject to a profit tax rate of 7% and a dividend withholding tax rate of 0%. In addition, all imports and exports are exempt from turnover tax and throughput fees. Beginning June 1, 2012, we will also make a minimum annual tax payment of $10 million (payable in equal quarterly installments), with the ability to carry forward any excess tax prepayments to future tax years.

The new tax regime was the result of a settlement agreement entered into on February 24, 2010 between the GOA and us that set the parties’ proposed terms for settlement of a lengthy and complicated tax dispute between the parties. On May 30, 2010, the Aruban Parliament adopted several laws that implemented the provisions of the settlement agreement, which became effective June 1, 2010. Pursuant to the terms of the settlement agreement, we relinquished the provisions of the previous tax holiday regime. On June 4, 2010, we made a payment to the GOA of $118 million (primarily from restricted cash held in escrow) in consideration of a full release of all tax claims prior to June 1, 2010. This settlement resulted in an after-tax gain of $30 million recognized primarily as a reduction to interest expense of $8 million and an income tax benefit of $20 million for the quarter ended June 30, 2010.

Environmental Matter
On June 30, 2010, the U.S. Environmental Protection Agency (EPA) formally disapproved the flexible permits program submitted by the Texas Commission on Environmental Quality (TCEQ) in 1994 for inclusion in its clean-air implementation plan. The EPA determined that Texas’ flexible permit program did not meet several requirements under the federal Clean Air Act. Our Port Arthur, Texas City, Three Rivers, McKee and Corpus Christi East and West Refineries operate under flexible permits administered by the TCEQ. Accordingly, the permit status of these facilities has been called into question. Litigation regarding the EPA’s actions is anticipated. We are currently evaluating the impacts of this new regulatory action and cannot estimate the financial or operational impacts on our business. Depending on the final resolution, the EPA’s actions could result in material increased compliance costs for us, costly remedial actions, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

Litigation
Retail Fuel Temperature Litigation
As of July 31, 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

31

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

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. In May 2010, the court issued an order in response to the plaintiffs’ motion for class certification of only the Kansas cases. The court certified an “injunction class” covering nonmonetary relief but deferred ruling on a “damages class.” The defendants have filed a petition to appeal the certification order. 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.

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.

16. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

In conjunction with the acquisition of Premcor Inc. on September 1, 2005, Valero Energy Corporation has fully and unconditionally guaranteed the following debt of The Premcor Refining Group Inc. (PRG), a wholly owned subsidiary of Valero Energy Corporation, that was outstanding as of June 30, 2010:

• 6.75% senior notes due February 2011 and

• 6.125% senior notes due May 2011.

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.

32

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

Condensed Consolidating Balance Sheet as of June 30, 2010
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	721		$	–		$	1,280		$	–		$	2,001
Restricted cash		–			1			12			–			13
Receivables, net		–			32			4,090			–			4,122
Inventories		–			59			4,708			–			4,767
Income taxes receivable		–			–			79			–			79
Deferred income taxes		–			–			171			–			171
Prepaid expenses and other		–			7			163			–			170
Assets held for sale and assets related to discontinued operations		–			25			–			–			25
Total current assets		721			124			10,503			–			11,348
Property, plant and equipment, at cost		–			4,161			25,278			–			29,439
Accumulated depreciation		–			(445	)		(5,631	)		–			(6,076	)
Property, plant and equipment, net		–			3,716			19,647			–			23,363
Intangible assets, net		–			–			223			–			223
Investment in Valero Energy affiliates		6,540			4,515			103			(11,158	)		–
Long-term notes receivable from affiliates		16,108			–			–			(16,108	)		–
Deferred income tax receivable		569			–			–			(569	)		–
Deferred charges and other assets, net		137			149			1,257			–			1,543
Total assets	$	24,075		$	8,504		$	31,733		$	(27,835	)	$	36,477
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	8		$	411		$	104		$	–		$	523
Accounts payable		1			82			5,773			–			5,856
Accrued expenses		144			85			211			–			440
Taxes other than income taxes		–			16			556			–			572
Income taxes payable		235			–			2			–			237
Deferred income taxes		184			–			–			–			184
Liabilities related to discontinued operations		–			102			–			–			102
Total current liabilities		572			696			6,646			–			7,914
Debt and capital lease obligations, less current portion		7,476			–			35			–			7,511
Long-term notes payable to affiliates		–			6,889			9,219			(16,108	)		–
Deferred income taxes		–			714			4,125			(569	)		4,270
Other long-term liabilities		976			102			653			–			1,731
Stockholders’ equity:
Common stock		7			–			1			(1	)		7
Additional paid-in capital		7,833			3,720			6,876			(10,596	)		7,833
Treasury stock		(6,620	)		–			–			–			(6,620	)
Retained earnings		13,591			(3,611	)		4,150			(539	)		13,591
Accumulated other comprehensive income (loss)		240			(6	)		28			(22	)		240
Total stockholders’ equity		15,051			103			11,055			(11,158	)		15,051
Total liabilities and stockholders’ equity	$	24,075		$	8,504		$	31,733		$	(27,835	)	$	36,477

33

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

34

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

Condensed Consolidating Statement of Income for the Three Months Ended June 30, 2010
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	3,404		$	20,496		$	(2,125	)	$	21,775
Costs and expenses:
Cost of sales		–			3,728			17,717			(2,125	)		19,320
Operating expenses		–			60			787			–			847
Retail selling expenses		–			–			187			–			187
General and administrative expenses		–			6			125			–			131
Depreciation and amortization expense		–			37			330			–			367
Asset impairment loss		–			–			2			–			2
Total costs and expenses		–			3,831			19,148			(2,125	)		20,854
Operating income (loss)		–			(427	)		1,348			–			921
Equity in earnings of subsidiaries		509			422			108			(1,039	)		–
Other income (expense), net		295			(16	)		190			(468	)		1
Interest and debt expense:
Incurred		(187	)		(125	)		(294	)		468			(138	)
Capitalized		–			1			21			–			22
Income (loss) from continuing operations before income tax expense (benefit)		617			(145	)		1,373			(1,039	)		806
Income tax expense (benefit) (1)		34			(200	)		442			–			276
Income from continuing operations		583			55			931			(1,039	)		530
Income from discontinued operations, net of income taxes		–			53			–			–			53
Net income	$	583		$	108		$	931		$	(1,039	)	$	583

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

35

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

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

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Elimination			Consolidated
Operating revenues	$	–		$	2,908		$	17,766		$	(3,298	)	$	17,376
Costs and expenses:
Cost of sales		–			3,197			16,115			(3,298	)		16,014
Operating expenses		–			60			721			–			781
Retail selling expenses		–			–			171			–			171
General and administrative expenses		3			–			119			–			122
Depreciation and amortization expense		–			31			330			–			361
Asset impairment loss		–			70			49			–			119
Total costs and expenses		3			3,358			17,505			(3,298	)		17,568
Operating income (loss)		(3	)		(450	)		261			–			(192	)
Equity in earnings (losses) of subsidiaries		(326	)		214			(255	)		367			–
Other income (expense), net		289			(27	)		152			(437	)		(23	)
Interest and debt expense:
Incurred		(162	)		(127	)		(266	)		437			(118	)
Capitalized		–			5			29			–			34
Loss from continuing operations before income tax expense (benefit)		(202	)		(385	)		(79	)		367			(299	)
Income tax expense (benefit) (1)		52			(193	)		33			–			(108	)
Loss from continuing operations		(254	)		(192	)		(112	)		367			(191	)
Loss from discontinued operations, net of income taxes		–			(63	)		–			–			(63	)
Net loss	$	(254	)	$	(255	)	$	(112	)	$	367		$	(254	)

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

36

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

Condensed Consolidating Statement of Income for the Six Months Ended June 30, 2010
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	7,192		$	41,969		$	(7,743	)	$	41,418
Costs and expenses:
Cost of sales		–			7,885			37,314			(7,743	)		37,456
Operating expenses		–			128			1,631			–			1,759
Retail selling expenses		–			–			360			–			360
General and administrative expenses		–			(33	)		261			–			228
Depreciation and amortization expense		–			71			653			–			724
Asset impairment loss		–			–			2			–			2
Total costs and expenses		–			8,051			40,221			(7,743	)		40,529
Operating income (loss)		–			(859	)		1,748			–			889
Equity in earnings of subsidiaries		347			708			34			(1,089	)		–
Other income (expense), net		567			(24	)		342			(873	)		12
Interest and debt expense:
Incurred		(344	)		(244	)		(570	)		873			(285	)
Capitalized		–			2			40			–			42
Income (loss) from continuing operations before income tax expense (benefit)		570			(417	)		1,594			(1,089	)		658
Income tax expense (benefit) (1)		100			(410	)		539			–			229
Income (loss) from continuing operations		470			(7	)		1,055			(1,089	)		429
Income from discontinued operations, net of income taxes		–			41			–			–			41
Net income	$	470		$	34		$	1,055		$	(1,089	)	$	470

(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 Six Months Ended June 30, 2009
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Elimination			Consolidated
Operating revenues	$	–		$	5,146		$	31,470		$	(5,912	)	$	30,704
Costs and expenses:
Cost of sales		–			5,479			27,651			(5,912	)		27,218
Operating expenses		–			151			1,475			–			1,626
Retail selling expenses		–			–			340			–			340
General and administrative expenses		1			1			265			–			267
Depreciation and amortization expense		–			67			644			–			711
Asset impairment loss		–			88			53			–			141
Total costs and expenses		1			5,786			30,428			(5,912	)		30,303
Operating income (loss)		(1	)		(640	)		1,042			–			401
Equity in earnings (losses) of subsidiaries		(78	)		334			(360	)		104			–
Other income (expense), net		544			(41	)		313			(840	)		(24	)
Interest and debt expense:
Incurred		(305	)		(242	)		(530	)		840			(237	)
Capitalized		–			11			62			–			73
Income (loss) from continuing operations before income tax expense (benefit)		160			(578	)		527			104			213
Income tax expense (benefit) (1)		105			(336	)		271			–			40
Income (loss) from continuing operation		55			(242	)		256			104			173
Loss from discontinued operations, net of income taxes		–			(118	)		–			–			(118	)
Net income (loss)	$	55		$	(360	)	$	256		$	104		$	55

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

38

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

Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2010
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	1,006		$	(525	)	$	1,289		$	–		$	1,770
Cash flows from investing activities:
Capital expenditures		–			(84	)		(701	)		–			(785	)
Deferred turnaround and catalyst costs		–			(73	)		(270	)		–			(343	)
Purchase of ethanol facilities		–			–			(260	)		–			(260	)
Proceeds from the sale of the Delaware City Refinery assets and associated terminal and pipeline assets		–			210			10			–			220
Net intercompany loan repayments		(1,534	)		–			–			1,534			–
Return of investment		10			–			–			(10	)		–
Other investing activities, net		–			–			11			–			11
Net cash provided by (used in) investing activities		(1,524	)		53			(1,210	)		1,524			(1,157	)
Cash flows from financing activities:
Non-bank debt:
Borrowings		1,244			–			–			–			1,244
Repayments		(33	)		(484	)		–			–			(517	)
Accounts receivable sales program:
Proceeds from sale of receivables		–			–			1,225			–			1,225
Repayments		–			–			(1,325	)		–			(1,325	)
Issuance of common stock in connection with employee benefit plans		11			–			–			–			11
Common stock dividends		(57	)		–			–			–			(57	)
Dividend to parent		–			–			(10	)		10			–
Debt issuance costs		(10	)		–			–			–			(10	)
Net intercompany borrowings		–			956			578			(1,534	)		–
Other financing activities, net		6			–			(2	)		–			4
Net cash provided by financing activities		1,161			472			466			(1,524	)		575
Effect of foreign exchange rate changes on cash		–			–			(12	)		–			(12	)
Net increase in cash and temporary cash investments		643			–			533			–			1,176
Cash and temporary cash investments at beginning of period		78			–			747			–			825
Cash and temporary cash investments at end of period	$	721		$	–		$	1,280		$	–		$	2,001

39

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

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

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(8	)	$	(819	)	$	2,234		$	–		$	1,407
Cash flows from investing activities:
Capital expenditures		–			(197	)		(1,154	)		–			(1,351	)
Deferred turnaround and catalyst costs		–			(20	)		(229	)		–			(249	)
Purchase of ethanol facilities		–			–			(556	)		–			(556	)
Minor acquisitions		–			–			(29	)		–			(29	)
Net intercompany loan repayments		(1,194	)		–			–			1,194			–
Other investing activities, net		–			–			11			–			11
Net cash used in investing activities		(1,194	)		(217	)		(1,957	)		1,194			(2,174	)
Cash flows from financing activities:
Non-bank debt:
Borrowings		998			–			–			–			998
Repayments		(209	)		–			–			–			(209	)
Accounts receivable sales program:
Proceeds from sale of receivables		–			–			500			–			500
Repayments		–			–			(500	)		–			(500	)
Proceeds from the sale of common stock, net of issuance costs		799			–			–			–			799
Issuance of common stock in connection with employee benefit plans		4			–			–			–			4
Common stock dividends		(155	)		–			–			–			(155	)
Debt issuance costs		(8	)		–			–			–			(8	)
Net intercompany borrowings		–			1,036			158			(1,194	)		–
Other financing activities, net		1			–			(2	)		–			(1	)
Net cash provided by financing activities		1,430			1,036			156			(1,194	)		1,428
Effect of foreign exchange rate changes on cash		–			–			22			–			22
Net increase in cash and temporary cash investments		228			–			455			–			683
Cash and temporary cash investments at beginning of period		215			–			725			–			940
Cash and temporary cash investments at end of period	$	443		$	–		$	1,180		$	–		$	1,623

40

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 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, crude oil, grain and other feedstocks, and refined products and ethanol;

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

• legislative or regulatory action, including the introduction or enactment of 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 second quarter of 2010, we reported income from continuing operations of $530 million, or $0.93 per share, compared to a loss from continuing operations of $191 million, or $0.36 per share, for the second quarter of 2009. For the first six months of 2010, we reported income from continuing operations of $429 million, or $0.76 per share, compared to $173 million, or $0.33 per share, for the first six months of 2009. These results were primarily due to our refining segment operations, which generated operating income of $921 million in the second quarter of 2010 and an operating loss of $143 million in the second quarter of 2009. Refining segment operating income was $870 million for the first six months of 2010 and $550 million for the first six months of 2009. The increase in refining operating income for both comparable periods (2010 vs. 2009) was primarily due to improved margins for the distillate products we produce and wider sour crude oil differentials. The sour crude oil differential is the difference between the price of sweet crude oil and the price of sour crude oil. We believe that the improved distillate margins are due to an increase in the demand for refined products resulting from the slowly improving U.S. and worldwide economies. This refined product demand, however, has not returned to levels experienced prior to the economic slowdown that began in 2008. In addition, we believe there is excess worldwide refinery capacity and refined product inventories remain high. These factors continue to constrain the margins for refined products.

In response to the worldwide economic slowdown, and as a result of our assessment of the operating performance and profitability of our refineries, we temporarily shut down our Aruba Refinery in July 2009 and permanently shut down our Delaware City Refinery in November 2009. 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 and the “operating highlights” and “refining operating highlights” tables that follow this overview. On June 1, 2010, we completed the sale of our shutdown Delaware City Refinery assets and associated terminal and pipeline assets for $220 million of cash proceeds. We are also evaluating strategic alternatives for our Paulsboro Refinery and have entered into negotiations to sell the refinery.

Our Aruba Refinery has remained shut since July 2009 primarily because it has been uneconomical to operate due to narrow heavy sour crude oil differentials. However, in June 2010, due to the recent widening of the heavy sour crude oil differentials and the overall improvement in refining economics, we commenced refinery-wide maintenance to prepare the refinery’s production units for potential restart by the end of the third quarter of 2010. This decision was also in response to our settlement of tax disputes with the Government of Aruba (GOA) effective June 1, 2010, which resolved uncertainties regarding our tax environment in Aruba. In connection with the settlement, we paid the GOA $118 million, consisting primarily of cash that had been escrowed in connection with those disputes. There is no certainty, however, that refining economics will recover sufficiently to justify restarting the 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 believe that ethanol is a natural fit for us because we manufacture transportation fuels. During the second quarter and first half of 2010, our ethanol segment generated operating income of $35 million and $92 million, respectively, compared to $22 million for the second quarter and first half 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.

Our retail segment generated operating income of $109 million for the second quarter of 2010 compared to operating income of $65 million for the second quarter of 2009. Retail operating income was $180 million for the first six months of 2010, compared to $121 million for the comparable period in 2009. The 2010 results benefited from the blending of ethanol with the gasoline sold by our retail

43

segment. Ethanol is currently a lower cost product than gasoline and this lower cost results in an increase in retail fuel margins.

To support our financial strength and liquidity, 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 in March 2010, and our 6.75% senior notes for $190 million in May 2010; the remainder was used for general corporate purposes.

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 continued improvement in sour crude oil differentials. The expected increases in refined product demand and sour crude oil production should favorably impact our 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 ongoing production constraints or refinery shutdowns in the refining industry. We will continue to optimize our refining assets based on market conditions.

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.

Second Quarter 2010 Compared to Second Quarter 2009

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

	Three Months Ended June 30,
	2010 (a) (b)			2009 (a) (b)			Change
Operating revenues	$	21,775		$	17,376		$	4,399
Costs and expenses:
Cost of sales		19,320			16,014			3,306
Operating expenses		847			781			66
Retail selling expenses		187			171			16
General and administrative expenses		131			122			9
Depreciation and amortization expense:
Refining		318			318			–
Retail		27			26			1
Ethanol		9			5			4
Corporate		13			12			1
Asset impairment loss (c)		2			119			(117	)
Total costs and expenses		20,854			17,568			3,286
Operating income (loss)		921			(192	)		1,113
Other income (expense), net		1			(23	)		24
Interest and debt expense:
Incurred		(138	)		(118	)		(20	)
Capitalized		22			34			(12	)
Income (loss) from continuing operations before income tax expense (benefit)		806			(299	)		1,105
Income tax expense (benefit)		276			(108	)		384
Income (loss) from continuing operations		530			(191	)		721
Income (loss) from discontinued operations, net of income taxes (b)		53			(63	)		116
Net income (loss)	$	583		$	(254	)	$	837
Earnings (loss) per common share – assuming dilution:
Continuing operations	$	0.93		$	(0.36	)	$	1.29
Discontinued operations		0.10			(0.12	)		0.22
Total	$	1.03		$	(0.48	)	$	1.51

See the footnote references on page 49.

45

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

	Three Months Ended June 30,
	2010			2009			Change
Refining (b):
Operating income (loss) (c)	$	921		$	(143	)	$	1,064
Throughput margin per barrel (d)	$	9.39		$	4.74		$	4.65
Operating costs per barrel (c):
Refining operating expenses	$	3.55		$	3.39		$	0.16
Depreciation and amortization		1.50			1.47			0.03
Total operating costs per barrel	$	5.05		$	4.86		$	0.19
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		472			451			21
Medium/light sour crude		522			550			(28	)
Acidic sweet crude		59			103			(44	)
Sweet crude		689			609			80
Residuals		211			226			(15	)
Other feedstocks		128			176			(48	)
Total feedstocks		2,081			2,115			(34	)
Blendstocks and other		256			277			(21	)
Total throughput volumes		2,337			2,392			(55	)
Yields (thousand barrels per day):
Gasolines and blendstocks		1,148			1,141			7
Distillates		780			775			5
Petrochemicals		76			70			6
Other products (e)		352			408			(56	)
Total yields		2,356			2,394			(38	)
Retail – U.S.:
Operating income	$	76		$	36		$	40
Company-operated fuel sites (average)		990			1,001			(11	)
Fuel volumes (gallons per day per site)		5,196			5,119			77
Fuel margin per gallon	$	0.220		$	0.125		$	0.095
Merchandise sales	$	316		$	307		$	9
Merchandise margin (percentage of sales)		28.9	%		28.6	%		0.3	%
Margin on miscellaneous sales	$	22		$	21		$	1
Retail selling expenses	$	122		$	115		$	7
Depreciation and amortization expense	$	18		$	18		$	–
Retail – Canada:
Operating income	$	33		$	29		$	4
Fuel volumes (thousand gallons per day)		3,098			3,093			5
Fuel margin per gallon	$	0.276		$	0.253		$	0.023
Merchandise sales	$	61		$	49		$	12
Merchandise margin (percentage of sales)		30.6	%		29.2	%		1.4	%
Margin on miscellaneous sales	$	9		$	7		$	2
Retail selling expenses	$	65		$	56		$	9
Depreciation and amortization expense	$	9		$	8		$	1

See the footnote references on page 49.

46

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

	Three Months Ended June 30,
	2010		2009		Change
Ethanol (a):
Operating income	$	35	$	22	$	13
Ethanol production (thousand gallons per day)		3,190		1,547		1,643
Gross margin per gallon of ethanol production	$	0.47	$	0.49	$	(0.02	)
Operating costs per gallon of ethanol production:
Ethanol operating expenses	$	0.31	$	0.30	$	0.01
Depreciation and amortization		0.03		0.03		–
Total operating costs per gallon of ethanol production	$	0.34	$	0.33	$	0.01

See the footnote references on page 49.

47

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

	Three Months Ended June 30,
	2010			2009			Change
Gulf Coast:
Operating income (loss)	$	650		$	(81	)	$	731
Throughput volumes (thousand barrels per day)		1,329			1,395			(66	)
Throughput margin per barrel (d)	$	10.28		$	3.94		$	6.34
Operating costs per barrel (c):
Refining operating expenses	$	3.34		$	3.17		$	0.17
Depreciation and amortization		1.57			1.41			0.16
Total operating costs per barrel	$	4.91		$	4.58		$	0.33
Mid-Continent:
Operating income	$	151		$	18		$	133
Throughput volumes (thousand barrels per day)		390			370			20
Throughput margin per barrel (d)	$	9.13		$	6.03		$	3.10
Operating costs per barrel (c):
Refining operating expenses	$	3.54		$	3.75		$	(0.21	)
Depreciation and amortization		1.36			1.72			(0.36	)
Total operating costs per barrel	$	4.90		$	5.47		$	(0.57	)
Northeast (b):
Operating income (loss)	$	24		$	(42	)	$	66
Throughput volumes (thousand barrels per day)		356			343			13
Throughput margin per barrel (d)	$	5.49		$	3.05		$	2.44
Operating costs per barrel (c):
Refining operating expenses	$	3.38		$	3.12		$	0.26
Depreciation and amortization		1.35			1.30			0.05
Total operating costs per barrel	$	4.73		$	4.42		$	0.31
West Coast:
Operating income	$	98		$	79		$	19
Throughput volumes (thousand barrels per day)		262			284			(22	)
Throughput margin per barrel (d)	$	10.55		$	9.03		$	1.52
Operating costs per barrel (c):
Refining operating expenses	$	4.87		$	4.37		$	0.50
Depreciation and amortization		1.57			1.61			(0.04	)
Total operating costs per barrel	$	6.44		$	5.98		$	0.46
Operating income (loss) for regions above	$	923		$	(26	)	$	949
Asset impairment loss applicable to refining (c)		(2	)		(117	)		115
Total refining operating income (loss)	$	921		$	(143	)	$	1,064

See the footnote references on page 49.

48

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

	Three Months Ended June 30,
	2010		2009			Change
Feedstocks:
West Texas Intermediate (WTI) crude oil	$	77.80	$	59.54		$	18.26
WTI less sour crude oil at U.S. Gulf Coast (h)		3.78		0.33			3.45
WTI less Mars crude oil		0.36		2.19			(1.83	)
WTI less Maya crude oil		9.75		4.57			5.18
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		10.22		10.57			(0.35	)
No. 2 fuel oil less WTI		9.21		3.84			5.37
Ultra-low-sulfur diesel less WTI		12.14		6.16			5.98
Propylene less WTI		6.11		(10.89	)		17.00
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		10.39		10.58			(0.19	)
Low-sulfur diesel less WTI		13.29		6.24			7.05
U.S. Northeast:
Conventional 87 gasoline less WTI		9.49		9.85			(0.36	)
No. 2 fuel oil less WTI		10.12		4.69			5.43
Lube oils less WTI		52.36		25.64			26.72
U.S. West Coast:
CARBOB 87 gasoline less WTI		16.50		18.07			(1.57	)
CARB diesel less WTI		14.45		7.92			6.53
New York Harbor corn crush (dollars per gallon)		0.36		0.29			0.07

The following notes relate to references on pages 45 through 49.
(a)	The information presented for the three months ended June 30, 2010 and 2009 includes the operations related to the acquisition of seven ethanol plants from VeraSun Energy Corporation (VeraSun) beginning on their respective closing dates in the second quarter of 2009 including plants located in 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 June 30, 2010 includes operations related to two ethanol plants purchased on January 13, 2010 from ASA Ethanol Holdings, LLC (ASA) located in Bloomingburg, Ohio and Linden, Illinois and one ethanol plant purchased on February 4, 2010 from Renew Energy LLC (Renew) located in Jefferson, Wisconsin. The ethanol production volumes reflected for the three months ended June 30, 2010 and 2009 are based on total production during each period divided by actual calendar days per period.
(b)	During the fourth quarter of 2009, we permanently shut down our refinery in Delaware City, Delaware, and wrote down the book value of the refinery assets to net realizable value. On June 1, 2010, we sold the shutdown refinery assets and the terminal and pipeline assets also located in Delaware City to PBF Energy Partners LP (PBF) for $220 million of cash proceeds. The results of operations of the shutdown refinery are reflected as discontinued operations for both periods presented. For the three months ended June 30, 2010, those results include a gain of $92 million ($58 million after taxes) on the sale of the refinery assets. The gain primarily resulted from the scrap value of the refinery assets and the reversal of certain liabilities recorded in the fourth quarter of 2009 associated with the shutdown of the refinery, which will not be incurred because of the sale. The terminal and pipeline assets previously associated with the refinery were not shut down and continued to be operated until the date of their sale. The results of operations of those assets, including an insignificant gain on sale, are reflected in continuing operations for both periods presented. All refining operating highlights, both consolidated and for the Northeast Region, exclude the Delaware City Refinery for both periods presented.
(c)	The asset impairment loss for the three months ended June 30, 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. This loss has 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.

49

(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.
(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 25% (or $4.4 billion) for the second quarter of 2010 compared to the second quarter of 2009 primarily as a result of higher refined product prices between the two periods. Operating income increased $1.1 billion and income from continuing operations increased $721 million for the second quarter of 2010 compared to amounts reported for the second quarter of 2009 primarily due to a $1.1 billion increase in refining segment operating income discussed below.

Refining

Results of operations of our refining segment increased from an operating loss of $143 million for the second quarter of 2009 to operating income of $921 million for the second quarter of 2010, resulting from a 98% increase in throughput margin per barrel (a $4.65 per barrel increase between the comparable periods) partially offset by a 2% decline in total throughput volumes (a 55,000 barrel per day decrease between the comparable periods). The increase in the refining throughput margin per barrel for the second quarter of 2010 was partially due to a significant improvement in distillate margins, but that improvement was somewhat offset by a decline in gasoline margins in all of our refining regions. Throughput margin per barrel also benefited from wider sour crude oil differentials. The impact of these factors on our throughput margin per barrel is described below.

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 $9.21 per barrel for the second quarter of 2010, compared to $3.84 per barrel for the second quarter of 2009, representing a favorable increase of $5.37 per barrel. Similar increases in distillate margins were experienced in other regions. We estimate that the increase in margin for distillates had a $332 million positive impact to our overall refining margin, quarter versus quarter, as we produced 780,000 barrels per day of distillates during the second quarter of 2010. Distillate margins were higher in the second quarter of 2010 as compared to the second quarter of 2009 due to an increase in the industrial demand for these products resulting from the ongoing recovery of the U.S. and worldwide economies and exports.

Similarly, the benchmark reference margin for U.S. Gulf Coast Conventional 87 gasoline (Gulf Coast 87 gasoline) was $10.22 per barrel for the second quarter of 2010, compared to $10.57 per barrel for the second quarter of 2009, representing an unfavorable decrease of $0.35 per barrel. Conventional 87 gasoline benchmark reference margins decreased quarter versus quarter to an even greater extent in the West Coast region (a $1.57 per barrel unfavorable decrease). We estimate that the decrease in gasoline margins had a $159 million negative impact to our overall refining margin, quarter versus quarter, as we produced 1.15 million barrels per day of gasoline during the second quarter of 2010. Gasoline margins were lower in the second quarter of 2010 as compared to the second quarter of 2009 despite an increase in gasoline prices in the second quarter of 2010. We believe that the margins for gasoline were constrained due to continued weak consumer demand and high levels of inventory. In addition, our downstream

50

customers increased the use of ethanol as a component in transportation fuels because its price was cheaper than gasoline.

The cost of crude oil we process also has a material impact on our results of operations because many of our refineries have been designed to process sour crude oils, which we can purchase at a discount to sweet crude oils. For example, Maya crude oil, which is a type of sour crude oil, sold at a discount of $9.75 per barrel to West Texas Intermediate crude oil, which is a type of sweet crude oil, during the second quarter of 2010. This compares to a discount of $4.57 per barrel during the second quarter of 2009, representing a favorable increase of $5.18 per barrel. We estimate that the wider discounts for all types of sour crude oil that we process had a $204 million positive impact to our overall refining margin, quarter versus quarter, as we processed 994,000 barrels per day of sour crude oils.

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.

Retail

Retail operating income was $109 million for the second quarter of 2010 compared to $65 million for the second quarter of 2009. This 68% (or $44 million) increase was due to improved retail fuel margins of $51 million, partially offset by higher selling expenses of $16 million, $9 million of which relates to our Canadian retail operations.

Retail fuel margins benefited from the blending of ethanol with the gasoline sold by our retail segment. Ethanol is currently a lower cost product than gasoline and this lower cost results in an increase in retail fuel margins. For example, the Chicago Board of Trade (CBOT) price for a gallon of ethanol was $0.54 less than a gallon of Gulf Coast 87 gasoline for the second quarter of 2010, but there was no difference between the prices of these products for the second quarter of 2009. In addition, approximately 80% of the gasoline we sold during the second quarter of 2010 contained 10% ethanol.

The increase in selling expenses from our Canadian retail operations was due to the strengthening of the Canadian dollar relative to the U.S. dollar.

Ethanol

Ethanol operating income was $35 million for the second quarter of 2010 compared to $22 million for the second quarter of 2009. This increase of $13 million was primarily due to an increase in the number of ethanol plants we operate. As more fully described in Note 3 of Condensed Notes to Consolidated Financial Statements, we acquired three ethanol plants in the first quarter of 2010, and these plants generated $6 million of operating income during the second quarter of 2010.

Corporate Expenses and Other

General and administrative expenses, including depreciation and amortization expense, increased $10 million from the second quarter of 2009 to the second quarter of 2010 primarily due to a $6 million increase in environmental remediation costs at a non-operating site.

“Other income (expense), net” for the second quarter of 2010 increased $24 million from the second quarter of 2009 due mainly to a $34 million net loss in 2009 resulting from an increase of $14 million in the fair value of an earn-out agreement that was entered into in connection with the sale of our Krotz Springs Refinery in 2008, offset by a loss of $48 million related to commodity derivative instruments entered into to hedge the risk of changes in the fair value of the earn-out agreement.

51

Interest and debt expense for the second quarter of 2010 increased $32 million from the second quarter of 2009. This increase is composed of a $20 million increase in interest expense incurred primarily on $1.25 billion of debt issued in February 2010, as described in Note 7 of Condensed Notes to Consolidated Financial Statements, and a $12 million decrease in capitalized interest due to a corresponding reduction in capital expenditures between the quarters and the temporary suspension of activity on certain construction projects. We will not capitalize interest with respect to suspended construction projects until significant construction activities resume.

Income tax expense increased $384 million from the second quarter of 2009 to the second quarter of 2010 mainly as a result of higher operating income.

Income from discontinued operations of $53 million for the second quarter of 2010 represents a $58 million after-tax gain on the sale of the shutdown refinery assets at Delaware City, partially offset by a $5 million net loss from the refinery’s operations prior to the sale. The gain on the sale of the shutdown refinery assets primarily resulted from the scrap value of the assets and the reversal of certain liabilities recorded in the fourth quarter of 2009 associated with the shutdown of the refinery, which we will not incur because of the sale.

52

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

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

	Six Months Ended June 30,
	2010 (a) (b)			2009 (a) (b)			Change
Operating revenues	$	41,418		$	30,704		$	10,714
Costs and expenses:
Cost of sales		37,456			27,218			10,238
Operating expenses		1,759			1,626			133
Retail selling expenses		360			340			20
General and administrative expenses		228			267			(39	)
Depreciation and amortization expense:
Refining		629			634			(5	)
Retail		53			49			4
Ethanol		17			5			12
Corporate		25			23			2
Asset impairment loss (c)		2			141			(139	)
Total costs and expenses		40,529			30,303			10,226
Operating income		889			401			488
Other income (expense), net		12			(24	)		36
Interest and debt expense:
Incurred		(285	)		(237	)		(48	)
Capitalized		42			73			(31	)
Income from continuing operations before income tax expense		658			213			445
Income tax expense		229			40			189
Income from continuing operations		429			173			256
Income (loss) from discontinued operations, net of income taxes (b)		41			(118	)		159
Net income	$	470		$	55		$	415
Earnings (loss) per common share – assuming dilution:
Continuing operations	$	0.76		$	0.33		$	0.43
Discontinued operations		0.07			(0.22	)		0.29
Total	$	0.83		$	0.11		$	0.72

See the footnote references on page 57.

53

Operating Highlights

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

	Six Months Ended June 30,
	2010			2009			Change
Refining (b):
Operating income (c)	$	870		$	550		$	320
Throughput margin per barrel (d)	$	7.70		$	6.77		$	0.93
Operating costs per barrel (c):
Refining operating expenses	$	3.96		$	3.69		$	0.27
Depreciation and amortization		1.57			1.48			0.09
Total operating costs per barrel	$	5.53		$	5.17		$	0.36
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		457			505			(48	)
Medium/light sour crude		493			559			(66	)
Acidic sweet crude		51			105			(54	)
Sweet crude		666			582			84
Residuals		174			172			2
Other feedstocks		128			169			(41	)
Total feedstocks		1,969			2,092			(123	)
Blendstocks and other		248			279			(31	)
Total throughput volumes		2,217			2,371			(154	)
Yields (thousand barrels per day):
Gasolines and blendstocks		1,090			1,097			(7	)
Distillates		720			792			(72	)
Petrochemicals		72			65			7
Other products (e)		355			416			(61	)
Total yields		2,237			2,370			(133	)
Retail – U.S.:
Operating income	$	109		$	61		$	48
Company-operated fuel sites (average)		989			1,003			(14	)
Fuel volumes (gallons per day per site)		5,070			5,052			18
Fuel margin per gallon	$	0.181		$	0.121		$	0.060
Merchandise sales	$	588		$	573		$	15
Merchandise margin (percentage of sales)		28.9	%		29.5	%		(0.6	)%
Margin on miscellaneous sales	$	44		$	44		$	–
Retail selling expenses	$	233		$	229		$	4
Depreciation and amortization expense	$	36		$	35		$	1
Retail – Canada:
Operating income	$	71		$	60		$	11
Fuel volumes (thousand gallons per day)		3,088			3,176			(88	)
Fuel margin per gallon	$	0.287		$	0.252		$	0.035
Merchandise sales	$	113		$	88		$	25
Merchandise margin (percentage of sales)		31.0	%		29.5	%		1.5	%
Margin on miscellaneous sales	$	19		$	15		$	4
Retail selling expenses	$	127		$	111		$	16
Depreciation and amortization expense	$	17		$	14		$	3

See the footnote references on page 57.

54

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

	Six Months Ended June 30,
	2010		2009		Change
Ethanol (a):
Operating income	$	92	$	22	$	70
Ethanol production (thousand gallons per day)		2,864		778		2,086
Gross margin per gallon of ethanol production	$	0.54	$	0.49	$	0.05
Operating costs per gallon of ethanol production:
Ethanol operating expenses	$	0.33	$	0.30	$	0.03
Depreciation and amortization		0.03		0.03		–
Total operating costs per gallon of ethanol production	$	0.36	$	0.33	$	0.03

See the footnote references on page 57.

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

	Six Months Ended June 30,
	2010			2009			Change
Gulf Coast:
Operating income	$	639		$	109		$	530
Throughput volumes (thousand barrels per day)		1,234			1,355			(121	)
Throughput margin per barrel (d)	$	8.35		$	5.48		$	2.87
Operating costs per barrel (c):
Refining operating expenses	$	3.85		$	3.58		$	0.27
Depreciation and amortization		1.64			1.46			0.18
Total operating costs per barrel	$	5.49		$	5.04		$	0.45
Mid-Continent:
Operating income	$	140		$	191		$	(51	)
Throughput volumes (thousand barrels per day)		377			385			(8	)
Throughput margin per barrel (d)	$	7.32		$	8.07		$	(0.75	)
Operating costs per barrel (c):
Refining operating expenses	$	3.79		$	3.73		$	0.06
Depreciation and amortization		1.48			1.59			(0.11	)
Total operating costs per barrel	$	5.27		$	5.32		$	(0.05	)
Northeast (b):
Operating income	$	26		$	125		$	(99	)
Throughput volumes (thousand barrels per day)		344			351			(7	)
Throughput margin per barrel (d)	$	5.64		$	6.46		$	(0.82	)
Operating costs per barrel (c):
Refining operating expenses	$	3.81		$	3.25		$	0.56
Depreciation and amortization		1.40			1.25			0.15
Total operating costs per barrel	$	5.21		$	4.50		$	0.71
West Coast:
Operating income	$	67		$	264		$	(197	)
Throughput volumes (thousand barrels per day)		262			280			(18	)
Throughput margin per barrel (d)	$	7.89		$	11.66		$	(3.77	)
Operating costs per barrel (c):
Refining operating expenses	$	4.92		$	4.73		$	0.19
Depreciation and amortization		1.55			1.73			(0.18	)
Total operating costs per barrel	$	6.47		$	6.46		$	0.01
Operating income for regions above	$	872		$	689		$	183
Asset impairment loss applicable to refining (c)		(2	)		(139	)		137
Total refining operating income	$	870		$	550		$	320

See the footnote references on page 57.

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

	Six Months Ended June 30,
	2010		2009			Change
Feedstocks:
WTI crude oil	$	78.24	$	51.26		$	26.98
WTI less sour crude oil at U.S. Gulf Coast (h)		3.44		1.02			2.42
WTI less Mars crude oil		1.65		0.70			0.95
WTI less Maya crude oil		9.33		4.51			4.82
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		8.68		9.36			(0.68	)
No. 2 fuel oil less WTI		7.44		7.34			0.10
Ultra-low-sulfur diesel less WTI		9.82		9.38			0.44
Propylene less WTI		11.86		(8.69	)		20.55
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		8.55		9.58			(1.03	)
Low-sulfur diesel less WTI		10.00		8.94			1.06
U.S. Northeast:
Conventional 87 gasoline less WTI		8.68		8.99			(0.31	)
No. 2 fuel oil less WTI		8.50		9.06			(0.56	)
Lube oils less WTI		43.34		46.37			(3.03	)
U.S. West Coast:
CARBOB 87 gasoline less WTI		13.54		18.60			(5.06	)
CARB diesel less WTI		11.44		10.81			0.63
New York harbor corn crush (dollars per gallon)		0.41		0.30			0.11

The following notes relate to references on pages 53 through 57.
(a)	The information presented for the six months ended June 30, 2010 and 2009 includes the operations related to the acquisition of seven ethanol plants from VeraSun beginning on their respective closing dates in the second quarter of 2009 including plants located in Albert City, Charles City, Fort Dodge, and Hartley, Iowa; Aurora, South Dakota; Welcome, Minnesota; and Albion, Nebraska. In addition, information presented for the six months ended June 30, 2010 includes operations related to two ethanol plants purchased on January 13, 2010 from ASA located in Bloomingburg, Ohio and Linden, Illinois and one ethanol plant purchased on February 4, 2010 from Renew located in Jefferson, Wisconsin. The ethanol production volumes reflected for the six months ended June 30, 2010 and 2009 are based on total production during the period divided by actual calendar days per period.
(b)	During the fourth quarter of 2009, we permanently shut down our refinery in Delaware City, Delaware, and wrote down the book value of the refinery assets to net realizable value. On June 1, 2010, we sold the shutdown refinery assets and the terminal and pipeline assets also located in Delaware City to PBF for $220 million of cash proceeds. The results of operations of the shutdown refinery are reflected as discontinued operations for both periods presented. For the six months ended June 30, 2010, those results include a gain of $92 million ($58 million after taxes) on the sale of the refinery assets. The gain primarily resulted from the scrap value of the refinery assets and the reversal of certain liabilities recorded in the fourth quarter of 2009 associated with the shutdown of the refinery, which will not be incurred because of the sale. The terminal and pipeline assets previously associated with the refinery were not shut down and continued to be operated until the date of their sale. The results of operations of those assets, including an insignificant gain on sale, are reflected in continuing operations for both periods presented. All refining operating highlights, both consolidated and for the Northeast Region, exclude the Delaware City Refinery for both periods presented.
(c)	The asset impairment loss for the six months ended June 30, 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. This loss has 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.

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(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.
(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 35% (or $10.7 billion) for the first six months of 2010 compared to the first six months of 2009 primarily as a result of higher refined product prices between the two periods. Operating income increased $488 million and income from continuing operations increased $256 million for the first six months of 2010 compared to the amounts reported in the first six months of 2009 primarily due to a $320 million increase in refining segment operating income discussed below.

Refining

Operating income for our refining segment increased from $550 million for the first six months of 2009 to $870 million for the first six months of 2010, primarily due to the decline of $137 million in asset impairment losses from $139 million for the first six months of 2009 to $2 million for the first six months of 2010. As discussed in the “Overview and Outlook” above, we responded in a number of ways to the economic slowdown that began in 2008, including the evaluation of all of our ongoing construction projects. This evaluation resulted in our decision to permanently cancel certain projects throughout 2009. While this evaluation process has continued into 2010, the number and significance of projects cancelled has substantially declined.

Changes in the margin that we receive for our refined products typically have a material impact on our results of operations. However, the difference in margins between the first six months of 2010 and 2009 was not significant. In addition, the cost of crude oil we process typically has a material impact on our results operations. For the first six months of 2010, the discount applicable to the price of sour crude oil as compared to the price of sweet crude oil was wider than the discount for the first six months of 2009. For example, Maya crude oil, which is a type of sour crude oil, sold at a discount of $9.33 per barrel to West Texas Intermediate crude oil, which is a type of sweet crude oil, during the first six months of 2010. This compared to a discount of $4.51 per barrel during the first six months of 2009, representing a favorable increase of $4.82 per barrel. The benefit of this wider discount, however, was offset by a reduction of 114,000 barrels per day of sour crude oil that we processed during the first six months of 2010 as compared to the first six months of 2009.

Retail

Retail operating income was $180 million for the first six months of 2010 compared to $121 million for the first six months of 2009. This 49% (or $59 million) increase was primarily due to improved retail fuel margins of $69 million offset by a $16 million increase in selling expenses in our Canadian retail operations.

Retail fuel margins benefited from the blending of ethanol with the gasoline sold by our retail segment. Ethanol is currently a lower cost product than gasoline and this lower cost results in an increase in retail fuel margins. For example, the CBOT price for a gallon of ethanol was $0.45 less than a gallon of

58

Gulf Coast 87 gasoline for the first six months of 2010, but a gallon of ethanol was $0.17 higher than a gallon of Gulf Coast 87 gasoline for the first six months of 2009. In addition, approximately 80% of the gasoline we sold during the first six months of 2010 contained 10% ethanol.

The increase in selling expenses from our Canadian retail operations was due to the strengthening of the Canadian dollar relative to the U.S. dollar.

Ethanol

Ethanol operating income was $92 million for the first six months of 2010 compared to $22 million for the first six months of 2009. The increase of $70 million was due to a full six months of operations of the seven ethanol plants acquired in the VeraSun Acquisition in the second quarter of 2009 and the addition of three ethanol plants acquired in the first quarter of 2010, as described more fully in Note 3 of Condensed Notes to Consolidated Financial Statements.

Corporate Expenses and Other

General and administrative expenses, including depreciation and amortization expense, decreased $37 million from the first six months of 2009 to the first six months of 2010 due mainly to a favorable settlement with an insurance company for $40 million. This settlement related to our claim of insurance coverage in connection with losses incurred in prior periods related to certain litigation.

“Other income (expense), net” for the first six months of 2010 increased $36 million from the first six months of 2009 primarily due to a $38 million net loss in 2009 resulting from an increase of $25 million in the fair value of an earn-out agreement that was entered into in connection with the sale of our Krotz Springs Refinery in 2008, offset by a loss of $63 million related to commodity derivative instruments entered into to hedge the risk of changes in the fair value of the earn-out agreement.

Interest and debt expense increased $79 million from the first six months of 2009 to the first six months of 2010. This increase is composed of a $48 million increase in interest incurred on $1.25 billion of debt issued in February 2010 and $1.0 billion of debt issued in March 2009 (see Note 7 of Condensed Notes to Consolidated Financial Statements) and a $31 million decrease in capitalized interest due to a corresponding reduction in capital expenditures between the quarters and the temporary suspension of activity on certain construction projects. We will not capitalize interest with respect to suspended construction projects until significant construction activities resume.

Income tax expense increased $189 million from the first six months of 2009 to the first six months of 2010 due to higher operating income.

Income from discontinued operations of $41 million for the first six months of 2010 represents a $58 million after-tax gain on the sale of the shutdown refinery assets at Delaware City, partially offset by a $17 million net loss from the refinery’s operations prior to the sale. The gain on the sale of the shutdown refinery assets primarily resulted from the scrap value of the assets and the reversal of certain liabilities recorded in the fourth quarter of 2009 associated with the shutdown of the refinery, which we will not incur because of the sale.

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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Six Months Ended June 30, 2010 and 2009

Net cash provided by operating activities for the first six months of 2010 was $1.8 billion compared to $1.4 billion for the first six months of 2009. The increase in cash generated from operating activities was primarily due to the receipt of a $923 million tax refund in 2010. Changes in cash provided by or used for working capital during the first six 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 six months of 2010, combined with $1.244 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, and $220 million of proceeds from the sale of the Delaware City Refinery assets and associated terminal and pipeline assets as discussed in Note 4 of Condensed Notes to Consolidated Financial Statements, were used mainly to:

• fund $1.1 billion of capital expenditures and deferred turnaround and catalyst costs;

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

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

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

• pay common stock dividends of $57 million;

• purchase additional ethanol facilities for $260 million; and

• increase available cash on hand by $1.2 billion.

The net cash generated from operating activities during the first six months of 2009, combined with $998 million of proceeds from the issuance of $1 billion of notes in March 2009 as discussed in Note 7 of Condensed Notes to Consolidated Financial Statements, and $799 million of net proceeds from the issuance of 46 million shares of common stock in June 2009 as discussed in Note 8 of Condensed Notes to Consolidated Financial Statements, were used mainly to:

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

• fund the VeraSun Acquisition for $556 million;

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

• pay common stock dividends of $155 million;

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

• increase available cash on hand by $683 million.

Capital Investments

During the six months ended June 30, 2010, we expended $785 million for capital expenditures and $343 million for deferred turnaround and catalyst costs. Capital expenditures for the six months ended June 30, 2010 included $369 million of costs related to environmental projects.

For 2010, we expect to incur approximately $2.3 billion for capital investments, including approximately $1.8 billion for capital expenditures (approximately $780 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 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 plus certain

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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.

Effective June 1, 2010, we sold the shutdown Delaware City Refinery assets and associated terminal and pipeline assets to PBF for $220 million of cash proceeds. The sale resulted in a gain of $92 million related to the shutdown refinery assets and a $3 million gain related to the terminal and pipeline assets. The gain on the sale of the shutdown refinery assets primarily resulted from the scrap value of the assets and the reversal of certain liabilities recorded in the fourth quarter of 2009 associated with the shutdown of the refinery, which we will not incur because of the sale. This gain is presented in “income (loss) from discontinued operations, net of income taxes” in the consolidated statements of income for the three and six months ended June 30, 2010.

Contractual Obligations

As of June 30, 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 $1.244 billion, before deducting underwriting discounts and other issuance costs of $10 million.

In March 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 statements of income.

In April 2010, we made scheduled debt repayments of $8 million related to our Series A 5.45%, Series B 5.40%, and Series C 5.40% industrial revenue bonds.

In May 2010, we redeemed our 6.75% senior notes with a maturity date of May 1, 2014 for $190 million, or 102.25% of stated value. These notes had a carrying amount of $187 million as of the redemption date, resulting in a $3 million dollar loss that was included in “other income (expense), net” in the consolidated statements of income.

In June 2010, we made scheduled debt repayments of $25 million related to our 7.25% debentures.

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 2011. As of June 30, 2010, the amount of eligible receivables sold was $100 million.

During the six months ended June 30, 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.

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

Other Commercial Commitments

As of June 30, 2010, our committed lines of credit were as follows:

	Borrowing
	Capacity	Expiration
Letter of credit facility	$300 million	June 2011
Revolving credit facility	$2.4 billion	November 2012
Canadian revolving credit facility	Cdn. $115 million	December 2012

As of June 30, 2010, we had $76 million of letters of credit outstanding under our uncommitted short-term bank credit facilities and $225 million of letters of credit outstanding under our U.S. committed revolving credit facilities. Under our Canadian committed revolving credit facility, we had Cdn. $20 million of letters of credit outstanding as of June 30, 2010. Our letters of credit expire during 2010 and 2011.

Stock Purchase Programs

As of June 30, 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

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 June 1, 2010, the GOA enacted a new tax regime applicable to refinery and terminal operations in Aruba. Under the new tax regime, we are subject to a profit tax rate of 7% and a dividend withholding tax rate of 0%. In addition, all imports and exports are exempt from turnover tax and throughput fees.

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Beginning June 1, 2012, we will also make a minimum annual tax payment of $10 million (payable in equal quarterly installments), with the ability to carry forward any excess tax prepayments to future tax years.

The new tax regime was the result of a settlement agreement entered into on February 24, 2010 between the GOA and us that set the parties’ proposed terms for settlement of a lengthy and complicated tax dispute between the parties. On May 30, 2010, the Aruban Parliament adopted several laws that implemented the provisions of the settlement agreement, which became effective June 1, 2010. Pursuant to the terms of the settlement agreement, we relinquished the provisions of the previous tax holiday regime. On June 4, 2010, we made a payment to the GOA of $118 million (primarily from restricted cash held in escrow) in consideration of a full release of all tax claims prior to June 1, 2010. This settlement resulted in an after-tax gain of $30 million recognized primarily as a reduction to interest expense of $8 million and an income tax benefit of $20 million for the quarter ended June 30, 2010.

Other Matters Impacting Liquidity and Capital Resources

During the six months ended June 30, 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. 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.

Financial Regulatory Reform

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Wall Street Reform Act). The Wall Street Reform Act, among many things, creates new regulations for companies that extend credit to consumers and requires most derivative instruments to be traded on exchanges and routed through clearinghouses. Rules to implement the Wall Street Reform Act are being finalized and therefore, the impact to our operations is not yet known. However, implementation could result in higher margin requirements, higher clearing costs, and more reporting requirements with respect to our derivative activities.

Environmental Matters

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

Currently, some of the proposed federal “cap-and-trade” legislation would require businesses that emit greenhouse gases to buy emission credits from the government, other businesses, or through an auction process. In addition, refiners would be obligated to purchase emission credits associated with the transportation fuels (gasoline, diesel, and jet fuel) sold and consumed in the United States. As a result of such a program, we would be required to purchase emission credits for greenhouse gas emissions resulting from our own operations as well as from the fuels we sell. Although it is not possible at this time to predict the final form of a cap-and-trade bill (or whether such a bill will be passed by Congress), any new federal restrictions on greenhouse gas emissions – including a cap-and-trade program – could

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result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

On June 30, 2010, the EPA formally disapproved the flexible permits program submitted by the TCEQ in 1994 for inclusion in its clean-air implementation plan. The EPA determined that Texas’ flexible permit program did not meet several requirements under the federal Clean Air Act. Our Port Arthur, Texas City, Three Rivers, McKee and Corpus Christi East and West Refineries operate under flexible permits administered by the TCEQ. Accordingly, the permit status of these facilities has been called into question. Litigation regarding the EPA’s actions is anticipated. We are currently evaluating the impacts of this new regulatory action and cannot estimate the financial or operational impacts on our business. Depending on the final resolution, the EPA’s actions could result in material increased compliance costs for us, costly remedial actions, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

Other

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 us 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 have already been reflected in the accompanying consolidated financial statements.

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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 enter into commodity derivative instruments, including swaps, futures, and options to hedge:

• inventories and firm commitments to purchase inventories generally for amounts by which our current year LIFO inventory levels differ from our previous year-end LIFO inventory levels and

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

We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations. We use swaps primarily to convert our floating price exposure to a fixed price. We also enter into certain commodity derivative instruments for trading purposes to take advantage of existing market conditions related to crude oil and refined products that we perceive as opportunities to benefit our results of operations and cash flows, but for which there are no related physical transactions.

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.

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

	Derivative Instruments Held For
	Non-Trading			Trading
	Purposes			Purposes
June 30, 2010:
Gain (loss) in fair value due to:
10% increase in underlying commodity prices	$	(85	)	$	–
10% decrease in underlying commodity prices		85			1
December 31, 2009:
Gain (loss) in fair value due to:
10% increase in underlying commodity prices		(6	)		(8	)
10% decrease in underlying commodity prices		6			–

See Note 12 of Condensed Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of June 30, 2010.

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INTEREST RATE RISK

The following table provides information about our debt instruments (dollars in millions), the fair value of which is sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented. We had no interest rate derivative instruments outstanding as of June 30, 2010 or December 31, 2009.

	June 30, 2010
	Expected Maturity Dates
																There-						Fair
	2010			2011			2012			2013			2014			after			Total			Value
Debt:
Fixed rate	$	–		$	418		$	759		$	489		$	209		$	6,089		$	7,964		$	9,260
Average interest rate		–	%		6.4	%		6.9	%		5.5	%		4.8	%		7.1	%		6.9	%
Floating rate	$	–		$	100		$	–		$	–		$	–		$	–		$	100		$	100
Average interest rate		–	%		0.9	%		–	%		–	%		–	%		–	%		0.9	%

	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 June 30, 2010, we had commitments to purchase $325 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before July 30, 2010, resulting in an $8 million loss in the third 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 June 30, 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, or our quarterly report on Form 10-Q for the quarter ended March 31, 2010.

     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.”

• Retail Fuel Temperature Litigation

• 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.

Bay Area Air Quality Management District (BAAQMD)(Benicia Refinery). In June 2010, our Benicia Refinery received two violation notices (VN’s) issued by the BAAQMD alleging excess emissions and public nuisance. The VN’s relate to emission events that occurred in the second quarter of 2010 in connection with certain operational issues concerning the refinery’s coker unit. No penalties were specified in these VN’s. We are evaluating our response to the VN’s.

Delaware Department of Natural Resources and Environmental Control (DDNREC)(Delaware City Refinery) (this matter was last disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009). We recently signed an agreement with the DDNREC to settle all then-outstanding air, water, and waste enforcement actions pertaining to the Delaware City Refinery. The settlement included all notices of violation and other open matters that we previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009.

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New Jersey Department of Environmental Protection (NJDEP)(Paulsboro Refinery) (this matter was last disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009). In March 2009 and August 2009, the NJDEP issued Notices of Revocation (Notices) to our Paulsboro Refinery alleging that the refinery exceeded emission limits for particulate matter and hydrogen cyanide. The first Notice relates to a fluid catalytic cracker (FCC) stack test conducted in 2007. The second Notice relates to an FCC stack test conducted in February 2009. The Notices assess penalties of $40,000 and $285,000, respectively, and direct the refinery either to perform a new stack test or submit an application to modify the permit limits. We continue our discussions with the NJDEP to resolve this matter, and we continue to work with the NJDEP on additional stack testing. We have filed appeals on both Notices, and our request for a stay on both Notices has been granted. A compliance order staying the Notices as they relate to excess emissions of hydrogen cyanide pending revision of the applicable emission limit was issued in May 2010. A parallel compliance order to address the Notices as they relate to emissions of particulate matter is being negotiated with the NJDEP.

State of Ohio, Office of the Attorney General, Environmental Enforcement(The Premcor Refining Group Inc. former Clark retail sites) (this matter was last disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009). In June 2008, the Attorney General’s office of the State of Ohio issued a penalty demand to our wholly owned subsidiary, The Premcor Refining Group Inc., for alleged environmental violations arising from a predecessor’s operation or ownership of underground storage tanks at several sites. We have settled this matter with the Attorney General’s office, and have finalized the terms of the consent orders (one for each county) for final resolution.

Item 1A. Risk Factors

Our risk factor entitled “Compliance with and changes in environmental laws, including proposed climate change laws and regulations, could adversely affect our performance,” as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009, is hereby amended and restated as follows.

Compliance with and changes in environmental laws, including proposed climate change laws and regulations, could adversely affect our performance.

The principal environmental risks associated with our operations are emissions into the air and releases into the soil, surface water, or groundwater. Our operations 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 gasoline and diesel fuels. If we violate or fail to comply with these laws and regulations, we could be fined or otherwise sanctioned. Because environmental laws and regulations are becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, such as those relating to greenhouse gas emissions and climate change (e.g., California’s AB-32 “Global Warming Solutions Act,” the U.S. House of Representatives’ “American Clean Energy and Security Act of 2009,” the U.S. Senate Committee on Environment and Public Works’ “Clean Energy Jobs and American Power Act of 2009,” initiatives and rulemaking following the U.S. Environmental Protection Agency’s 2009 “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act”), the level of expenditures required for environmental matters could increase in the future. In particular, under certain permitting activities, the self-executing provisions of the Clean Air Act following the EPA’s endangerment finding and subsequent rule-making, lead to environmental controls review for greenhouse gas emissions beginning January 2, 2011. This and future legislative action and regulatory initiatives could result in changes to operating permits, additional remedial actions, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we sell, and decreased demand for our products that cannot be assessed with certainty at this time.

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Some of the proposed federal “cap-and-trade” legislation would require businesses that emit greenhouse gases to buy emission credits from the government, other businesses, or through an auction process. In addition, refiners would be obligated to purchase emission credits associated with the transportation fuels (gasoline, diesel, and jet fuel) sold and consumed in the United States. As a result of such a program, we would be required to purchase emission credits for greenhouse gas emissions resulting from our own operations as well as from the fuels we sell. Although it is not possible at this time to predict the final form of a cap-and-trade bill (or whether such a bill will be passed by Congress), any new federal restrictions on greenhouse gas emissions – including a cap-and-trade program – could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

On June 30, 2010, the EPA formally disapproved the long-standing “flexible permitting” rules that the TCEQ uses as part of the state’s air quality program. Although the program has been in place since 1994, the EPA now claims that the Texas program did not meet several requirements under the federal Clean Air Act. Our Port Arthur, Texas City, Three Rivers, McKee, Corpus Christi East and West refineries have these so-called “flex” permits. Accordingly, the permit status of these facilities has been called into question. Litigation regarding the EPA’s actions is anticipated. We are currently evaluating the impacts of this new regulatory action and cannot estimate the financial or operational impacts on our business. Depending on the final resolution, the EPA’s action could result in material increased compliance costs for us, costly remedial actions, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

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

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

          (b) Use of Proceeds. Not applicable.

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

Period	Total		Average		Total Number of		Total Number of		Maximum Number (or
	Number of		Price		Shares Not		Shares Purchased		Approximate Dollar
	Shares		Paid per		Purchased as Part		as Part of		Value) of Shares that
	Purchased		Share		of Publicly		Publicly		May Yet Be Purchased
					Announced Plans		Announced Plans		Under the Plans or
					or Programs (1)		or Programs		Programs
									(at month end)(2)
April 2010		14,416	$	20.64		14,416		–	$ 3.46 billion
May 2010		587	$	20.59		587		–	$ 3.46 billion
June 2010		3,905	$	17.56		3,905		–	$ 3.46 billion
Total		18,908	$	20.00		18,908		–	$ 3.46 billion

(1) The shares reported in this column represent purchases settled in the second 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. This program is in addition to the $6 billion program. This $3 billion program has no expiration date.

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Item 6. Exhibits

Exhibit No.	Description
*12.01	Statements of Computations of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Fixed Charges and Preferred Stock Dividends.
*31.01	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer.
*31.02	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer.
*32.01	Section 1350 Certifications (as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).
**101	The following materials from Valero Energy Corporation’s Form 10-Q for the quarter ended June 30, 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 Comprehensive Income, and (v) Condensed Notes to Consolidated Financial Statements.

*	Filed herewith.
**	Submitted electronically herewith.

In accordance with Rule 406T 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: August 6, 2010

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