Valero Energy (VLO) 10-Q 2010 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2010

OR

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

For the transition period from                                        to                                          

Commission file number 1-13175

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of October 26, 2010 was 566,210,629.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

INDEX

	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009		3
Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2010 and 2009		4
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009		5
Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 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		42
Item 3. Quantitative and Qualitative Disclosures About Market Risk		67
Item 4. Controls and Procedures		68
PART II – OTHER INFORMATION
Item 1. Legal Proceedings		69
Item 1A. Risk Factors		69
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)

	September 30,			December 31,
	2010			2009
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	2,352		$	825
Receivables, net		4,240			3,773
Inventories		4,804			4,863
Income taxes receivable		100			888
Deferred income taxes		184			180
Prepaid expenses and other		172			383
Assets held for sale		–			157
Assets related to discontinued operations		25			67
Total current assets		11,877			11,136
Property, plant and equipment, at cost		29,930			28,463
Accumulated depreciation		(6,340	)		(5,592	)
Property, plant and equipment, net		23,590			22,871
Intangible assets, net		224			227
Deferred charges and other assets, net		1,585			1,395
Total assets	$	37,276		$	35,629
LIABILITIES AND STOCKHOLDERS’EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	523		$	237
Accounts payable		6,096			5,760
Accrued expenses		548			514
Taxes other than income taxes		561			725
Income taxes payable		74			95
Deferred income taxes		322			253
Liabilities related to discontinued operations		89			225
Total current liabilities		8,213			7,809
Debt and capital lease obligations, less current portion		7,513			7,163
Deferred income taxes		4,430			4,063
Other long-term liabilities		1,720			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		7,839			7,896
Treasury stock, at cost; 107,172,932 and 108,798,847 common shares		(6,615	)		(6,721	)
Retained earnings		13,855			13,178
Accumulated other comprehensive income		314			365
Total stockholders’ equity		15,400			14,725
Total liabilities and stockholders’ equity	$	37,276		$	35,629

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Millions of Dollars, Except per Share Amounts)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Operating revenues (1)	$	22,210		$	18,573		$	63,628		$	49,277
Costs and expenses:
Cost of sales		20,023			17,212			57,479			44,430
Operating expenses:
Refining		817			772			2,405			2,355
Retail		192			182			552			522
Ethanol		96			59			267			102
General and administrative expenses		139			167			367			434
Depreciation and amortization expense		372			361			1,096			1,072
Asset impairment loss		–			58			2			199
Total costs and expenses		21,639			18,811			62,168			49,114
Operating income (loss)		571			(238	)		1,460			163
Other income (expense), net		18			8			30			(16	)
Interest and debt expense:
Incurred		(145	)		(150	)		(430	)		(387	)
Capitalized		26			19			68			92
Income (loss) from continuing operations before income tax expense (benefit)		470			(361	)		1,128			(148	)
Income tax expense (benefit)		178			(18	)		407			22
Income (loss) from continuing operations		292			(343	)		721			(170	)
Income (loss) from discontinued operations, net of income taxes		–			(286	)		41			(404	)
Net income (loss)	$	292		$	(629	)	$	762		$	(574	)
Earnings (loss) per common share:
Continuing operations	$	0.52		$	(0.61	)	$	1.27		$	(0.32	)
Discontinued operations		–			(0.51	)		0.07			(0.76	)
Total	$	0.52		$	(1.12	)	$	1.34		$	(1.08	)
Weighted-average common shares outstanding (in millions)		564			561			563			534
Earnings (loss) per common share – assuming dilution:
Continuing operations	$	0.51		$	(0.61	)	$	1.27		$	(0.32	)
Discontinued operations		–			(0.51	)		0.07			(0.76	)
Total	$	0.51		$	(1.12	)	$	1.34		$	(1.08	)
Weighted-average common shares outstanding – assuming dilution (in millions)		568			561			567			534
Dividends per common share	$	0.05		$	0.15		$	0.15		$	0.45
Supplemental information:
(1) Includes excise taxes on sales by our U.S. retail system	$	234		$	226		$	667		$	659

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

(Unaudited)

	Nine Months Ended September 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	762		$	(574	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense		1,096			1,156
Asset impairment loss		2			575
Gain on sale of Delaware City Refinery assets		(92	)		–
Noncash interest expense and other income, net		8			26
Stock-based compensation expense		32			35
Deferred income tax expense (benefit)		285			(302	)
Changes in current assets and current liabilities		592			1,154
Changes in deferred charges and credits and other operating activities, net		(63	)		(130	)
Net cash provided by operating activities		2,622			1,940
Cash flows from investing activities:
Capital expenditures		(1,226	)		(1,820	)
Deferred turnaround and catalyst costs		(410	)		(301	)
Purchase of ethanol plants		(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		15			23
Net cash used in investing activities		(1,661	)		(2,683	)
Cash flows from financing activities:
Non-bank debt:
Borrowings		1,244			998
Repayments		(517	)		(209	)
Accounts receivable sales program:
Proceeds from the 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		12			7
Common stock dividends		(85	)		(239	)
Debt issuance costs		(10	)		(8	)
Other financing activities, net		3			(5	)
Net cash provided by financing activities		547			1,343
Effect of foreign exchange rate changes on cash		19			65
Net increase in cash and temporary cash investments		1,527			665
Cash and temporary cash investments at beginning of period		825			940
Cash and temporary cash investments at end of period	$	2,352		$	1,605

See Condensed Notes to Consolidated Financial Statements.

5

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Net income (loss)	$	292		$	(629	)	$	762		$	(574	)
Other comprehensive income (loss):
Foreign currency translation adjustment		100			214			63			324
Pension and other postretirement benefits:
Net loss arising during the period, net of income tax benefit of $-, $-, $-, and $-		–			–			(21	)		–
Net gain reclassified into income, net of income tax expense of $2, $1, $2, and $1		(2	)		(1	)		(4	)		(1	)
Net loss on pension and other postretirement benefits		(2	)		(1	)		(25	)		(1	)
Derivative instruments designated and qualifying as cash flow hedges:
Net gain (loss) arising during the period, net of income tax (expense) benefit of $-, $(12), $1, and $(46)		–			24			(1	)		87
Net gain reclassified into income, net of income tax expense of $13, $29, $47, and $89		(24	)		(54	)		(88	)		(166	)
Net loss on cash flow hedges		(24	)		(30	)		(89	)		(79	)
Other comprehensive income (loss)		74			183			(51	)		244
Comprehensive income (loss)	$	366		$	(446	)	$	711		$	(330	)

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

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

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

These unaudited consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the three and nine months ended September 30, 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 nine months ended September 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 September 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 the shutdown refinery assets, excluding certain miscellaneous assets, and the 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 as of December 31, 2009. The miscellaneous assets excluded from the plan of sale and all

7

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

liabilities of the Delaware City Refinery have been presented in the consolidated balance sheets as assets and liabilities of discontinued operations as of September 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.

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 this guidance on 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. 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 this guidance on 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 plants. On January 13, 2010, we completed the acquisition of these plants, 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 plant located near Jefferson, Wisconsin from Renew Energy LLC (Renew) and made a $1 million advance payment towards the purchase of this plant. We completed the acquisition of this plant, 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. Because these acquisitions were not material to our results of operations, we have not presented pro forma results of operations for the nine months ended September 30, 2010 and three and nine months ended September 30, 2009, or actual results of operations from the acquisition dates through September 30, 2010. The consolidated statement of income for the nine months ended September 30, 2010 includes the results of the ASA and Renew acquisitions from 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.

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. The pro forma information (in millions, except per share amount) presented below for the nine months ended September 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.

Actual results of operations from acquired business from the closing dates through September 30, 2009:
Operating revenues	$	673
Net income		42
Consolidated pro forma results of operations for the nine months ended September 30, 2009:
Operating revenues		49,500
Loss from continuing operations		(177	)
Loss per common share from continuing operations – assuming dilution		(0.33	)

4. DISPOSITIONS

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, and 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. The terminal and pipeline assets associated with the refinery were not shut down and continued to be operated until the date of their sale as described below. 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 a terminalling agreement related to our continued use of those assets.

In the first quarter of 2010, our board of directors approved a plan of sale for our shutdown refinery assets, excluding certain miscellaneous assets, and the 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 receiving proceeds related to 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 statement of income for the nine months ended September 30, 2010.

The shutdown refinery assets and the associated terminal and pipeline assets that were sold on June 1, 2010 have been presented in the consolidated balance sheet as assets held for sale as of December 31, 2009. Certain miscellaneous assets and all liabilities of the shutdown refinery that were not sold are presented in the consolidated balance sheets as assets and liabilities related to discontinued operations as of September 30, 2010 and December 31, 2009 as follows (in millions).

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

	September 30,		December 31,
	2010		2009
Assets Held for Sale
Current assets:
Property, plant and equipment, net
Refinery	$	–	$	16
Terminal and pipeline		–		141
Current assets	$	–	$	157
Assets and Liabilities Related to Discontinued Operations
Current assets:
Receivables, net	$	6	$	6
Inventories		–		4
Deferred income taxes		19		57
Current assets	$	25	$	67
Current liabilities:
Accounts payable	$	5	$	36
Accrued expenses		84		189
Current liabilities	$	89	$	225

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010		2009			2010			2009
Operating revenues	$	–	$	916		$	–		$	1,961
Loss before income taxes		–		(454	)		(33	)		(663	)

Subsequent Disposition of Investment
In October 2010, we signed an agreement to sell our 50% interest in Cameron Highway Oil Pipeline Company (CHOPS) to Genesis Energy, L.P. for $330 million in cash proceeds. The sale was approved by our board of directors in October, and we expect the closing to occur before the end of 2010. Our investment in CHOPS was $274 million as of September 30, 2010.

11

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

5. IMPAIRMENTS

General
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. Those 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. We determined that there was no impairment of any of our refining operating assets as of December 31, 2009.

The economy and refining industry fundamentals have generally improved throughout 2010 compared to 2009, but refining industry fundamentals continue to be negatively impacted by the economic slowdown that began in 2008, and the refining industry outlook remains uncertain. Therefore, we continued to update our evaluation of potential impairments of our refining operating assets as of September 30, 2010, and we have determined that there continues to be no impairment of these assets. Our cash flow estimates are based on expected improvements in refined product prices resulting from the slowly improving economy. Estimates related to our Paulsboro and Aruba Refineries are particularly sensitive to assumptions regarding specific matters affecting those refineries, and those matters and our assumptions are described below. We believe that our estimates regarding expected cash flows are reasonable, but future cash flows will differ from our estimates and such differences may be material.

Paulsboro Refinery
On September 24, 2010, we signed an agreement to sell our Paulsboro Refinery to PBF Holding Company LLC (PBF Holding), for $363 million plus net working capital, and our board of directors approved the sale on October 5, 2010. PBF Holding is related to the buyer of our recently sold Delaware City Refinery assets and associated terminal and pipeline assets, as discussed in Note 4. The proceeds will consist of a $180 million note secured by the Paulsboro Refinery, with the remaining amount, including net working capital, paid in cash. The note will mature one year from the closing date and will bear interest at LIBOR plus 700 basis points; however, PBF Holding may extend the note for an additional six months at its option, during which time the note will bear interest at LIBOR plus 900 basis points. Net working capital excludes crude oil, other feedstock and finished product inventories, as well as miscellaneous supplies inventories associated with the Paulsboro Refinery. We anticipate entering into a separate agreement to sell the crude oil, other feedstock and finished product inventories to PBF Holding.

A closing date has not been set and our ability to close the sale is conditioned upon, among other requirements, securing a modified emissions permit for a certain processing unit at the refinery from the New Jersey Department of Environmental Protection (NJDEP) and the U.S. Environmental Protection Agency (EPA). If these conditions are not met or waived by the parties on or before December 1, 2010, the agreement to sell the Paulsboro Refinery will automatically terminate on December 1, 2010. Due to the public comment process and regular administrative review, we believe that it is unlikely that we will obtain the modified permit prior to December 1, 2010. As such, there is significant uncertainty as to the eventual consummation of the sale to PBF Holding.

12

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

As of September 30, 2010, the Paulsboro Refinery was classified as “held and used” because our board of directors had not yet approved the plan of disposition of the refinery and because it was not probable that the sale of the Paulsboro Refinery would be consummated within a one-year period. However, because of the possibility that the refinery will be sold, as well as continuing depressed refining industry fundamentals, we evaluated the refinery for potential impairment as of September 30, 2010. We developed expected future cash flows for the refinery based on our assessment of the likelihood of selling the refinery to PBF Holding or continuing to operate it. Expected future cash flows associated with the continued operations of the refinery were developed using significant estimates and assumptions about the future operations of the refinery, including overall throughput volumes, types of crude oil processed, types of products produced, and prices for crude oil and refined products. Our assessment of the likelihood of selling the refinery to PBF Holding considered, among other factors, our belief that it is unlikely that we will obtain the modified permit from the NJDEP and the EPA before December 1, 2010, and we concluded that there is significant uncertainty of the sale to PBF Holding. Based on our assumptions, our tests indicated that the Paulsboro Refinery was not impaired as of September 30, 2010. However, if we sell the refinery to PBF Holding in accordance with the terms of the sale agreement, we will recognize a loss of approximately $920 million.

Aruba Refinery
Our Aruba Refinery was shut down in July 2009 because narrow sour crude oil differentials made the refinery uneconomical to operate. However, in the third quarter of 2010, we commenced refinery-wide maintenance to prepare the refinery’s production units for restart due to improved sour crude oil differentials and a general improvement in refining economics, and we expect the refinery to restart in December 2010. We considered these positive developments in our updated impairment evaluation of the Aruba Refinery, and that evaluation indicated that there was no impairment. The Aruba Refinery, however, is particularly sensitive to sour crude oil differentials, and our cash flow estimates are based on our expectation that such differentials will return to amounts experienced prior to the economic slowdown that began in 2008. This expectation is based on our belief that the economy will continue to improve and that the demand for refined products, and therefore crude oil, will increase and cause sour crude oil differentials to widen. Should differentials fail to widen or fail to widen to amounts experienced in prior years, our cash flows estimates will be negatively impacted and we could ultimately determine that the refinery is impaired. The Aruba Refinery had a net book value of $962 million as of September 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.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. INVENTORIES

Inventories consisted of the following (in millions):

	September 30,		December 31,
	2010		2009
Refinery feedstocks	$	2,650	$	2,124
Refined products and blendstocks		1,715		2,317
Ethanol feedstocks and products		144		141
Convenience store merchandise		97		96
Materials and supplies		198		185
Inventories	$	4,804	$	4,863

As of September 30, 2010 and December 31, 2009, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $4.9 billion and $4.5 billion, respectively.

7. DEBT

Non-Bank Debt
In March 2009, we issued $750 million of 9.375% notes due March 15, 2019 and $250 million of 10.5% notes due March 15, 2039. Proceeds from the issuance of these notes totaled $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.

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.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 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 September 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 September 30, 2010 and December 31, 2009, our debt-to-capitalization ratios, calculated in accordance with the terms of the Revolver, were 27.0% and 30.9%, respectively. We believe that we will remain in compliance with this covenant.

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

As of September 30, 2010 and December 31, 2009, we had $285 million and $259 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities and $215 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 September 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 nine months ended September 30, 2010, we sold $1.2 billion of eligible receivables and repaid $1.3 billion. As of September 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.

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

	September 30,		December 31,
	2010		2009
Carrying amount (excluding capital leases)	$	7,998	$	7,364
Fair value		9,595		8,228

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

8. STOCKHOLDERS’ EQUITY

Treasury Stock
No significant purchases of our common stock were made during the nine months ended September 30, 2010 and 2009. During the nine months ended September 30, 2010 and 2009, we issued 1.6 million shares and 0.9 million shares from treasury, respectively, for our employee benefit plans.

Common Stock Dividends
On November 3, 2010, our board of directors declared a regular quarterly cash dividend of $0.05 per common share payable on December 15, 2010 to holders of record at the close of business on November 17, 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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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. EARNINGS (LOSS) PER COMMON SHARE

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

	Three Months Ended September 30,
	2010				2009
	Restricted		Common		Restricted		Common
	Stock		Stock		Stock		Stock
Earnings (loss) per common share from continuing operations:
Income (loss) from continuing operations			$	292			$	(343	)
Less dividends paid:
Common stock				28				84
Nonvested restricted stock				–				–
Undistributed earnings (loss)			$	264			$	(427	)
Weighted-average common shares outstanding		3		564		2		561
Earnings (loss) per common share from continuing operations:
Distributed earnings	$	0.05	$	0.05	$	0.15	$	0.15
Undistributed earnings (loss)		0.47		0.47		–		(0.76	)
Total earnings (loss) per common share from continuing operations	$	0.52	$	0.52	$	0.15	$	(0.61	)
Earnings (loss) per common share from continuing operations – assuming dilution:
Income (loss) from continuing operations			$	292			$	(343	)
Weighted-average common shares outstanding				564				561
Common equivalent shares:
Stock options				3				–
Performance awards and unvested restricted stock				1				–
Weighted-average common shares outstanding – assuming dilution				568				561
Earnings (loss) per common share from continuing operations – assuming dilution			$	0.51			$	(0.61	)

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

	Nine Months Ended September 30,
	2010				2009
	Restricted		Common		Restricted		Common
	Stock		Stock		Stock		Stock
Earnings (loss) per common share from continuing operations:
Income (loss) from continuing operations			$	721			$	(170	)
Less dividends paid:
Common stock				85				238
Nonvested restricted stock				–				1
Undistributed earnings (loss)			$	636			$	(409	)
Weighted-average common shares outstanding		3		563		2		534
Earnings (loss) per common share from continuing operations:
Distributed earnings	$	0.15	$	0.15	$	0.44	$	0.45
Undistributed earnings (loss)		1.12		1.12		–		(0.77	)
Total earnings (loss) per common share from continuing operations	$	1.27	$	1.27	$	0.44	$	(0.32	)
Earnings (loss) per common share from continuing operations – assuming dilution:
Income (loss) from continuing operations			$	721			$	(170	)
Weighted-average common shares outstanding				563				534
Common equivalent shares:
Stock options				3				–
Performance awards and unvested restricted stock				1				–
Weighted-average common shares outstanding - assuming dilution				567				534
Earnings (loss) per common share from continuing operations – assuming dilution			$	1.27			$	(0.32	)

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 and nine months ended September 30, 2009, and stock options for which the exercise prices were greater than the average market price of our common shares during each respective reporting period.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
Common equivalent shares		–		4		–		4
Stock options		17		10		14		10

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

10. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended September 30,
	2010			2009
Decrease (increase) in current assets:
Receivables, net	$	(516	)	$	(966	)
Inventories		79			198
Income taxes receivable		787			137
Prepaid expenses and other		111			106
Increase (decrease) in current liabilities:
Accounts payable		358			1,466
Accrued expenses		(51	)		94
Taxes other than income taxes		(168	)		54
Income taxes payable		(8	)		65
Changes in current assets and current liabilities	$	592		$	1,154

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;

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

• 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;

• changes in assets and liabilities related to the discontinued operations of the Delaware City Refinery prior to its shutdown are reflected in the line items to which the changes relate in the table above; and

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

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

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

	Nine Months Ended September 30,
	2010			2009
Interest paid in excess of amount capitalized	$	(302	)	$	(232	)
Income taxes received, net		645			134

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

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):

	Nine Months Ended September 30,
	2010			2009
Cash used in operating activities	$	(76	)	$	(203	)
Cash used in investing activities		–			(119	)

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 (in millions) about our financial assets and liabilities measured and recorded at fair value on a recurring basis and indicate the fair value hierarchy of the inputs utilized by us to determine the fair values as of September 30, 2010 and December 31, 2009.

	Fair Value Measurements Using
	Quoted		Significant
	Prices		Other		Significant
	in Active		Observable		Unobservable		Total as of
	Markets		Inputs		Inputs		September 30,
	(Level 1)		(Level 2)		(Level 3)		2010
Assets:
Commodity derivative contracts	$	45	$	79	$	–	$	124
Nonqualified benefit plans		98		–		10		108
Liabilities:
Commodity derivative contracts		13		9		–		22
Nonqualified benefit plans		32		–		–		32

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

	Fair Value Measurements Using
	Quoted		Significant
	Prices		Other		Significant
	in Active		Observable		Unobservable		Total as of
	Markets		Inputs		Inputs		December 31,
	(Level 1)		(Level 2)		(Level 3)		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 September 30, 2010, cash collateral deposits of $29 million with brokers under master netting arrangements is included in the fair value of the commodity derivatives reflected in Level 1. As of December 31, 2009, cash received from brokers of $64 million, resulting from the equity in broker accounts covered by master netting arrangements exceeding the minimum margin requirements for such accounts, 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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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

	Earn-Out					Nonqualified
	Agreement					Benefit Plans
	2010		2009			2010		2009
Three months ended September 30:
Balance at beginning of period	$	–	$	38		$	10	$	–
Total losses included in earnings		–		(5	)		–		–
Settlement		–		(33	)		–		–
Balance at end of period	$	–	$	–		$	10	$	–
Nine months ended September 30:
Balance at beginning of period	$	–	$	13		$	10	$	–
Total gains included in earnings		–		20			–		–
Settlement		–		(33	)		–		–
Balance at end of period	$	–	$	–		$	10	$	–

For the three and nine months ended September 30, 2010, there were no unrealized gains or losses included in “total gains (losses) included in earnings” in the table above related to nonqualified benefit plan assets still held as of September 30, 2010.

For the three and nine months ended September 30, 2009, the amounts reflected in “total gains (losses) included in earnings” in the table above related to the earn-out agreement are reported in “other income (expense), net” in the consolidated statements of income. We entered into the earn-out agreement with Alon Refining Krotz Springs Inc. in connection with the sale of our Krotz Springs Refinery in 2008. We also entered into commodity derivative instruments to hedge the risk of changes in the fair value of the earn-out agreement, and the gains (losses) associated with these instruments are also reported in “other income (expense), net.”

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

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

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 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 September 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
	Year of Maturity
Derivative Instrument	2010
Crude oil and refined products:
Futures – long		32,560
Futures – short		47,123

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

Cash Flow Hedges
Cash flow hedges are used to hedge certain forecasted feedstock and 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 September 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
	Year of Maturity
Derivative Instrument	2010
Crude oil and refined products:
Swaps – long		10,650
Swaps – short		10,650

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 September 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
	Year of Maturity
Derivative Instrument	2010		2011		2012
Crude oil and refined products:
Swaps – long		70,768		110,222		–
Swaps – short		69,979		110,210		–
Futures – long		242,403		24,975		–
Futures – short		241,830		20,112		–
Options – long		6		2,410		–
Options – short		–		2,400		–
Corn:
Futures – long		9,120		375		–
Futures – short		30,135		20,865		420

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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 September 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
	Year of Maturity
Derivative Instrument	2010		2011
Crude oil and refined products:
Swaps – long		16,579		13,695
Swaps – short		16,579		13,695
Futures – long		76,004		6,766
Futures – short		76,950		6,782
Options – long		200		–
Options – short		150		–
Natural gas:
Futures – long		4,370		–
Futures – short		4,170		–

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 September 30, 2010, we had commitments to purchase $308 million of U.S. dollars. These commitments matured on or before October 22, 2010.

Fair Values of Derivative Instruments
The following tables provide information about the fair values of our derivative instruments as of September 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.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The tables below, however, are presented on a gross asset and gross liability basis, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts. In addition, in Note 11, we included cash collateral on deposit with or received from brokers in the fair value of the commodity derivatives; these cash amounts are not reflected in the tables below.

		Fair Value as of
		September 30, 2010
	Balance Sheet	Asset		Liability
	Location	Derivatives		Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	14	$	37
Futures	Accrued expenses		315		400
Swaps	Receivables, net		74		76
Swaps	Prepaid expenses and other		130		71
Swaps	Accrued expenses		7		8
Total		$	540	$	592
Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	40	$	66
Futures	Accrued expenses		3,205		3,069
Swaps	Receivables, net		214		171
Swaps	Prepaid expenses and other		459		474
Swaps	Accrued expenses		7		15
Options	Accrued expenses		–		5
Total		$	3,925	$	3,800
Total derivatives		$	4,465	$	4,392

26

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

		Fair Value as of
		December 31, 2009
	Balance Sheet	Asset		Liability
	Location	Derivatives		Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	1	$	2
Futures	Accrued expenses		13		37
Swaps	Receivables, net		308		271
Swaps	Prepaid expenses and other		579		415
Swaps	Accrued expenses		28		19
Total		$	929	$	744
Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	34	$	29
Futures	Accrued expenses		2,094		2,101
Swaps	Receivables, net		506		370
Swaps	Prepaid expenses and other		1,049		1,037
Swaps	Accrued expenses		46		62
Options	Accrued expenses		–		1
Total		$	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 September 30, 2010, we had net receivables related to derivative instruments of $6 million from counterparties in the refining industry and $38 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 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

27

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

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 nine months ended September 30, 2010 and 2009 (in millions), and the line items in the financial statements in which such gains and losses are reflected.

													Gain (Loss)
	Location of	Gain (Loss)					Gain (Loss)						Recognized in
Derivatives in	Gain (Loss)	Recognized in					Recognized in						Income for
Fair Value	Recognized in	Income on					Income on						Ineffective Portion
Hedging	Income on	Derivatives					Hedged Item						of Derivative
Relationships	Derivatives	2010		2009			2010			2009			2010			2009
Three months ended September 30:
Commodity contracts	Cost of sales	$	54	$	(5	)	$	(56	)	$	(3	)	$	(2	)	$	(8	)
Nine months ended September 30:
Commodity contracts	Cost of sales		253		(94	)		(247	)		87			6			(7	)

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 (Loss)						Gain
	Recognized in						Reclassified from				Gain
Derivatives in	OCI on					Location of Gain	Accumulated OCI into				Recognized in
Cash Flow	Derivatives					Recognized in	Income				Income on Derivatives
Hedging	(Effective Portion)					Income on	(Effective Portion)				(Ineffective Portion)
Relationships	2010			2009		Derivatives	2010		2009		2010		2009
Three months ended September 30:
Commodity contracts	$	–		$	36	Cost of sales	$	37	$	83	$	–	$	6
Nine months ended September 30:
Commodity contracts		(2	)		133	Cost of sales		135		255		–		5

For cash flow hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness. For the three and nine months ended September 30, 2010, cash flow hedges primarily related to forward sales of distillates and associated forward purchases of crude oil, with $28 million of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive income as of September 30, 2010. We expect that all of the deferred gains as of

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

September 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 nine months ended September 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.

		Amount of Gain (Loss)
Derivatives Designated as	Location of Gain (Loss)	Recognized in
Economic Hedges and Other	Recognized in Income on	Income on Derivatives
Derivative Instruments	Derivatives	2010			2009
Three months ended September 30:
Commodity contracts	Cost of sales	$	22		$	(68	)
Foreign currency contracts	Cost of sales		(5	)		(9	)
			17			(77	)
Earn-out agreement	Other income (expense)		–			(5	)
Earn-out hedge (commodity contracts)	Other income (expense)		–			1
			–			(4	)
Total		$	17		$	(81	)
Nine months ended September 30:
Commodity contracts	Cost of sales	$	(93	)	$	(30	)
Foreign currency contracts	Cost of sales		(2	)		(25	)
			(95	)		(55	)
Earn-out agreement	Other income (expense)		–			20
Earn-out hedge (commodity contracts)	Other income (expense)		–			(62	)
			–			(42	)
Total		$	(95	)	$	(97	)

		Amount of Gain
	Location of Gain	Recognized in Income on
Derivatives Designated as	Recognized in Income on	Derivatives
Trading Activities	Derivatives	2010		2009
Three months ended September 30:
Commodity contracts	Cost of sales	$	2	$	9
Nine months ended September 30:
Commodity contracts	Cost of sales		7		125

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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 September 30, 2010:
Operating revenues from external customers	$	19,006		$	2,360	$	844	$	–		$	22,210
Intersegment revenues		1,576			–		73		–			1,649
Operating income (loss)		571			105		47		(152	)		571
Three months ended September 30, 2009:
Operating revenues from external customers		16,016			2,147		410		–			18,573
Intersegment revenues		1,388			–		47		–			1,435
Operating income (loss)		(219	)		111		49		(179	)		(238	)
Nine months ended September 30, 2010:
Operating revenues from external customers		54,663			6,893		2,072		–			63,628
Intersegment revenues		4,675			–		184		–			4,859
Operating income (loss)		1,441			285		139		(405	)		1,460
Nine months ended September 30, 2009:
Operating revenues from external customers		42,856			5,748		673		–			49,277
Intersegment revenues		3,676			–		76		–			3,752
Operating income (loss)		331			232		71		(471	)		163

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

	September 30,		December 31,
	2010		2009
Refining	$	31,346	$	30,901
Retail		1,850		1,875
Ethanol		902		654
Corporate		3,178		2,199
Total consolidated assets	$	37,276	$	35,629

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

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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 nine months ended September 30, 2010 and 2009 (in millions):

							Other Postretirement
	Pension Plans						Benefit Plans
	2010			2009			2010			2009
Three months ended September 30:
Components of net periodic benefit cost:
Service cost	$	22		$	26		$	3		$	3
Interest cost		21			19			6			6
Expected return on plan assets		(28	)		(27	)		–			–
Amortization of:
Prior service cost (credit)		1			1			(5	)		(5	)
Net loss		–			3			1			2
Net periodic benefit cost	$	16		$	22		$	5		$	6
Nine months ended September 30:
Components of net periodic benefit cost:
Service cost	$	65		$	78		$	8		$	9
Interest cost		62			59			19			19
Expected return on plan assets		(84	)		(81	)		–			–
Amortization of:
Prior service cost (credit)		2			2			(15	)		(14	)
Net loss		1			8			3			5
Net periodic benefit cost	$	46		$	66		$	15		$	19

During the nine-month periods ended September 30, 2010 and 2009, we contributed $50 million and $72 million, respectively, to our qualified pension plans. We currently anticipate contributing $100 million to our qualified pension plans in December 2010.

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 nine months ended September 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.

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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 Government of Aruba (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 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 against the EPA regarding its actions has been brought by multiple stakeholders, including trade associations. 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 October 29, 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

32

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

because fuel volume increases with fuel temperature, the defendants have violated state consumer protection laws by failing to adjust the volume or price of fuel when the fuel temperature exceeded 60 degrees Fahrenheit. The complaints seek to certify classes of retail consumers who purchased fuel in various locations. The complaints seek an order compelling the installation of temperature correction devices as well as monetary relief. The federal lawsuits are consolidated into a multi-district litigation case in the U.S. District Court for the District of Kansas (Multi-District Litigation Docket No. 1840,In re: Motor Fuel Temperature Sales Practices Litigation). Discovery has commenced. In May 2010, the court issued an order in response to the plaintiffs’ motion for class certification of the Kansas cases. The court certified an “injunction class” covering nonmonetary relief but deferred ruling on a “damages class.” The defendants’ request to appeal the court’s certification order was recently denied. We now await the lower court’s plan of management for the docket. We believe that we have several strong defenses to these lawsuits and intend to contest them. We have not recorded a loss contingency liability with respect to this matter, but due to the inherent uncertainty of litigation, we believe that it is reasonably possible that we may suffer a loss with respect to one or more of the lawsuits. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.

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 September 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.

33

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

Condensed Consolidating Balance Sheet as of September 30, 2010
(Unaudited, In Millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	1,060		$	–		$	1,292		$	–		$	2,352
Receivables, net		–			34			4,206			–			4,240
Inventories		–			42			4,762			–			4,804
Income taxes receivable		–			–			100			–			100
Deferred income taxes		–			–			184			–			184
Prepaid expenses and other		–			7			165			–			172
Assets related to discontinued operations		–			25			–			–			25
Total current assets		1,060			108			10,709			–			11,877
Property, plant and equipment, at cost		–			4,215			25,715			–			29,930
Accumulated depreciation		–			(471	)		(5,869	)		–			(6,340	)
Property, plant and equipment, net		–			3,744			19,846			–			23,590
Intangible assets, net		–			–			224			–			224
Investment in Valero Energy affiliates		6,770			5,007			173			(11,950	)		–
Long-term notes receivable from affiliates		15,795			–			–			(15,795	)		–
Deferred income tax receivable		594			–			–			(594	)		–
Deferred charges and other assets, net		224			131			1,230			–			1,585
Total assets	$	24,443		$	8,990		$	32,182		$	(28,339	)	$	37,276
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	8		$	411		$	104		$	–		$	523
Accounts payable		–			80			6,016			–			6,096
Accrued expenses		184			134			230			–			548
Taxes other than income taxes		–			22			539			–			561
Income taxes payable		73			–			1			–			74
Deferred income taxes		322			–			–			–			322
Liabilities related to discontinued operations		–			89			–			–			89
Total current liabilities		587			736			6,890			–			8,213
Debt and capital lease obligations, less current portion		7,479			–			34			–			7,513
Long-term notes payable to affiliates		–			7,244			8,551			(15,795	)		–
Deferred income taxes		–			739			4,285			(594	)		4,430
Other long-term liabilities		977			98			645			–			1,720
Stockholders’ equity:
Common stock		7			–			1			(1	)		7
Additional paid-in capital		7,839			3,719			6,892			(10,611	)		7,839
Treasury stock		(6,615	)		–			–			–			(6,615	)
Retained earnings		13,855			(3,540	)		4,880			(1,340	)		13,855
Accumulated other comprehensive income (loss)		314			(6	)		4			2			314
Total stockholders’ equity		15,400			173			11,777			(11,950	)		15,400
Total liabilities and stockholders’ equity	$	24,443		$	8,990		$	32,182		$	(28,339	)	$	37,276

34

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
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		–			6			377			–			383
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

35

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

Condensed Consolidating Statement of Income for the Three Months Ended September 30, 2010
(Unaudited, In Millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	3,565		$	20,913		$	(2,268	)	$	22,210
Costs and expenses:
Cost of sales		–			3,940			18,351			(2,268	)		20,023
Operating expenses		–			113			992			–			1,105
General and administrative expenses		–			2			137			–			139
Depreciation and amortization expense		–			40			332			–			372
Asset impairment loss		–			–			–			–			–
Total costs and expenses		–			4,095			19,812			(2,268	)		21,639
Operating income (loss)		–			(530	)		1,101			–			571
Equity in earnings of subsidiaries		236			493			70			(799	)		–
Other income (expense), net		291			(6	)		193			(460	)		18
Interest and debt expense:
Incurred		(180	)		(131	)		(294	)		460			(145	)
Capitalized		–			2			24			–			26
Income (loss) from continuing operations before income tax expense (benefit)		347			(172	)		1,094			(799	)		470
Income tax expense (benefit)		55			(242	)		365			–			178
Income from continuing operations		292			70			729			(799	)		292
Income from discontinued operations, net of income taxes		–			–			–			–			–
Net income	$	292		$	70		$	729		$	(799	)	$	292

36

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

Condensed Consolidating Statement of Income for the Three Months Ended September 30, 2009
(Unaudited, In Millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	3,009		$	17,533		$	(1,969	)	$	18,573
Costs and expenses:
Cost of sales		–			3,514			15,667			(1,969	)		17,212
Operating expenses		–			57			956			–			1,013
General and administrative expenses		1			39			127			–			167
Depreciation and amortization expense		–			28			333			–			361
Asset impairment loss		–			11			47			–			58
Total costs and expenses		1			3,649			17,130			(1,969	)		18,811
Operating income (loss)		(1	)		(640	)		403			–			(238	)
Equity in earnings (losses) of subsidiaries		(650	)		358			(406	)		698			–
Other income (expense), net		309			(6	)		187			(482	)		8
Interest and debt expense:
Incurred		(176	)		(143	)		(313	)		482			(150	)
Capitalized		–			1			18			–			19
Loss from continuing operations before income tax expense (benefit)		(518	)		(430	)		(111	)		698			(361	)
Income tax expense (benefit)		111			(310	)		181			–			(18	)
Loss from continuing operations		(629	)		(120	)		(292	)		698			(343	)
Loss from discontinued operations, net of income taxes		–			(286	)		–			–			(286	)
Net loss	$	(629	)	$	(406	)	$	(292	)	$	698		$	(629	)

37

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

Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2010
(Unaudited, In Millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	10,757		$	62,882		$	(10,011	)	$	63,628
Costs and expenses:
Cost of sales		–			11,825			55,665			(10,011	)		57,479
Operating expenses		–			241			2,983			–			3,224
General and administrative expenses		–			(31	)		398			–			367
Depreciation and amortization expense		–			111			985			–			1,096
Asset impairment loss		–			–			2			–			2
Total costs and expenses		–			12,146			60,033			(10,011	)		62,168
Operating income (loss)		–			(1,389	)		2,849			–			1,460
Equity in earnings of subsidiaries		583			1,201			104			(1,888	)		–
Other income (expense), net		858			(30	)		535			(1,333	)		30
Interest and debt expense:
Incurred		(524	)		(375	)		(864	)		1,333			(430	)
Capitalized		–			4			64			–			68
Income (loss) from continuing operations before income tax expense (benefit)		917			(589	)		2,688			(1,888	)		1,128
Income tax expense (benefit)		155			(652	)		904			–			407
Income from continuing operations		762			63			1,784			(1,888	)		721
Income from discontinued operations, net of income taxes		–			41			–			–			41
Net income	$	762		$	104		$	1,784		$	(1,888	)	$	762

38

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

Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2009
(Unaudited, In Millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	–		$	8,155		$	49,003		$	(7,881	)	$	49,277
Costs and expenses:
Cost of sales		–			8,993			43,318			(7,881	)		44,430
Operating expenses		–			208			2,771			–			2,979
General and administrative expenses		2			40			392			–			434
Depreciation and amortization expense		–			95			977			–			1,072
Asset impairment loss		–			99			100			–			199
Total costs and expenses		2			9,435			47,558			(7,881	)		49,114
Operating income (loss)		(2	)		(1,280	)		1,445			–			163
Equity in earnings (losses) of subsidiaries		(728	)		692			(766	)		802			–
Other income (expense), net		853			(47	)		500			(1,322	)		(16	)
Interest and debt expense:
Incurred		(481	)		(385	)		(843	)		1,322			(387	)
Capitalized		–			12			80			–			92
Income (loss) from continuing operations before income tax expense (benefit)		(358	)		(1,008	)		416			802			(148	)
Income tax expense (benefit)		216			(646	)		452			–			22
Loss from continuing operations		(574	)		(362	)		(36	)		802			(170	)
Loss from discontinued operations, net of income taxes		–			(404	)		–			–			(404	)
Net loss	$	(574	)	$	(766	)	$	(36	)	$	802		$	(574	)

39

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

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2010
(Unaudited, In Millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	1,122		$	(813	)	$	2,313		$	–		$	2,622
Cash flows from investing activities:
Capital expenditures		–			(149	)		(1,077	)		–			(1,226	)
Deferred turnaround and catalyst costs		–			(74	)		(336	)		–			(410	)
Purchase of ethanol plants		–			–			(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		(1,285	)		–			–			1,285			–
Return of investment		10			–			–			(10	)		–
Other investing activities, net		–			–			15			–			15
Net cash used in investing activities		(1,275	)		(13	)		(1,648	)		1,275			(1,661	)
Cash flows from financing activities:
Non-bank debt:
Borrowings		1,244			–			–			–			1,244
Repayments		(33	)		(484	)		–			–			(517	)
Accounts receivable sales program:
Proceeds from the sale of receivables		–			–			1,225			–			1,225
Repayments		–			–			(1,325	)		–			(1,325	)
Issuance of common stock in connection with employee benefit plans		12			–			–			–			12
Common stock dividends		(85	)		–			–			–			(85	)
Dividend to parent		–			–			(10	)		10			–
Debt issuance costs		(10	)		–			–			–			(10	)
Net intercompany borrowings		–			1,310			(25	)		(1,285	)		–
Other financing activities, net		7			–			(4	)		–			3
Net cash provided by (used in) financing activities		1,135			826			(139	)		(1,275	)		547
Effect of foreign exchange rate changes on cash		–			–			19			–			19
Net increase in cash and temporary cash investments		982			–			545			–			1,527
Cash and temporary cash investments at beginning of period		78			–			747			–			825
Cash and temporary cash investments at end of period	$	1,060		$	–		$	1,292		$	–		$	2,352

40

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

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2009
(Unaudited, In Millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(164	)	$	(1,216	)	$	3,320		$	–		$	1,940
Cash flows from investing activities:
Capital expenditures		–			(420	)		(1,400	)		–			(1,820	)
Deferred turnaround and catalyst costs		–			(41	)		(260	)		–			(301	)
Purchase of ethanol plants		–			–			(556	)		–			(556	)
Minor acquisitions		–			–			(29	)		–			(29	)
Net intercompany loan repayments		(1,099	)		–			–			1,099			–
Other investing activities, net		–			–			23			–			23
Net cash used in investing activities		(1,099	)		(461	)		(2,222	)		1,099			(2,683	)
Cash flows from financing activities:
Non-bank debt:
Borrowings		998			–			–			–			998
Repayments		(209	)		–			–			–			(209	)
Accounts receivable sales program:
Proceeds from the sale of receivables		–			–			500			–			500
Repayments		–			–			(500	)		–			(500	)
Proceeds from the sale of common stock, net of issuance costs		799			–			–			–			799
Common stock dividends		(239	)		–			–			–			(239	)
Net intercompany borrowings (repayments)		–			1,677			(578	)		(1,099	)		–
Other financing activities, net		(3	)		–			(3	)		–			(6	)
Net cash provided by (used in) financing activities		1,346			1,677			(581	)		(1,099	)		1,343
Effect of foreign exchange rate changes on cash		–			–			65			–			65
Net increase in cash and temporary cash investments		83			–			582			–			665
Cash and temporary cash investments at beginning of period		215			–			725			–			940
Cash and temporary cash investments at end of period	$	298		$	–		$	1,307		$	–		$	1,605

41

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

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

This Form 10-Q, including without limitation our discussion below under the heading “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, retail, and ethanol industry fundamentals.

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

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

• political and economic conditions in nations that 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;

42

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

• 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, such as those to be implemented under the California Global Warming Solutions Act (also known as AB32), 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 any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

43

OVERVIEW AND OUTLOOK

For the third quarter of 2010, we reported income from continuing operations of $292 million, or $0.51 per share, compared to a loss from continuing operations of $343 million, or $0.61 per share, for the third quarter of 2009. For the first nine months of 2010, we reported income from continuing operations of $721 million, or $1.27 per share, compared to a loss from continuing operations of $170 million, or $0.32 per share, for the first nine months of 2009. These results were primarily due to our refining segment operations, which generated operating income of $571 million in the third quarter of 2010 compared to an operating loss of $219 million in the third quarter of 2009. Refining segment operating income was $1.4 billion for the first nine months of 2010 and $331 million for the first nine 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 primarily due to an increase in the demand for diesel in South America and Europe. Refinery shutdowns and other factors have contributed to the increase in demand from South America, and declining inventories due to an improving economy has contributed to the demand from Europe. In addition, there has been an increase in the demand for diesel in the U.S. due to the improving economy. The demand for refined products, however, has not returned to levels experienced prior to the economic slowdown that began in 2008. Excess worldwide refinery capacity and high levels of refined product inventories continue to constrain 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. 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. Our Aruba Refinery has remained shut because it has been uneconomical to operate due to narrow sour crude oil differentials. However, in the third quarter of 2010, we commenced refinery-wide maintenance to prepare the refinery’s production units for restart due to improved sour crude oil differentials and a general improvement in refining economics, and we expect to restart the refinery in December 2010. There is no certainty, however, that refining economics will recover sufficiently to justify restarting the refinery or that sour crude oil differentials will remain at levels sufficient to justify operating the refinery in the future (see Note 5 of Condensed Notes to Consolidated Financial Statements for our discussion of the Aruba Refinery).

On September 24, 2010, we signed an agreement to sell our Paulsboro Refinery for $363 million plus net working capital, and our board of directors approved the sale on October 5, 2010. However, before the sale can close, we must obtain a modified emissions permit related to a certain processing unit at the refinery and meet other conditions on or before December 1, 2010, or the agreement to sell the refinery will automatically terminate unless these conditions are waived by the parties. We believe that it is unlikely that we will obtain the modified permit by December 1, 2010. However, if we eventually sell the refinery in accordance with the terms of the sale agreement, we will recognize a loss of approximately $920 million (see Note 5 of Condensed Notes to Consolidated Financial Statements for our discussion of the potential sale of our Paulsboro Refinery).

In the second quarter of 2009, we entered the ethanol business through the acquisition of seven ethanol plants, and we acquired three additional plants in the first quarter of 2010. We believe that ethanol is a natural fit for us because we manufacture transportation fuels. During the third quarter and first nine months of 2010, our ethanol segment generated operating income of $47 million and $139 million, respectively, compared to $49 million and $71 million for the third quarter and first nine months of 2009, respectively. The increase in ethanol operating income for the first nine months of 2010 compared to the

44

first nine months of 2009 is due primarily to a full nine months of operation of the seven ethanol plants acquired in 2009 and the addition of the three ethanol plants acquired in early 2010. Despite the addition of the three new plants in 2010, ethanol operating income for the third quarter of 2010 decreased slightly from the third quarter of 2009 due to a decline in the margin for ethanol. 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 $105 million for the third quarter of 2010 compared to operating income of $111 million for the third quarter of 2009. Retail operating income was $285 million for the first nine months of 2010, compared to $232 million for the comparable period in 2009. The 2010 results benefited from the blending of ethanol with the gasoline sold by our retail segment. Throughout most of 2010, ethanol was a lower cost product than gasoline, and blending the lower cost ethanol resulted in an increase in retail fuel margins. In September 2010, the price of ethanol exceeded the cost of gasoline; therefore, the benefit to retail fuel margins from blending ethanol may not occur for the fourth quarter of 2010.

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 accordingly. 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.

45

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.

Third Quarter 2010 Compared to Third Quarter 2009

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

	Three Months Ended September 30,
	2010			2009			Change
Operating revenues	$	22,210		$	18,573		$	3,637
Costs and expenses:
Cost of sales		20,023			17,212			2,811
Operating expenses:
Refining		817			772			45
Retail		192			182			10
Ethanol		96			59			37
General and administrative expenses		139			167			(28	)
Depreciation and amortization expense:
Refining		322			317			5
Retail		27			25			2
Ethanol		10			7			3
Corporate		13			12			1
Asset impairment loss (c)		–			58			(58	)
Total costs and expenses		21,639			18,811			2,828
Operating income (loss)		571			(238	)		809
Other income, net		18			8			10
Interest and debt expense:
Incurred		(145	)		(150	)		5
Capitalized		26			19			7
Income (loss) from continuing operations before income tax expense (benefit)		470			(361	)		831
Income tax expense (benefit)		178			(18	)		196
Income (loss) from continuing operations		292			(343	)		635
Income (loss) from discontinued operations, net of income taxes		–			(286	)		286
Net income (loss)	$	292		$	(629	)	$	921
Earnings (loss) per common share – assuming dilution:
Continuing operations	$	0.51		$	(0.61	)	$	1.12
Discontinued operations		–			(0.51	)		0.51
Total	$	0.51		$	(1.12	)	$	1.63

See the footnote references on page 50.

46

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

	Three Months Ended September 30,
	2010			2009			Change
Refining (b):
Operating income (loss) (c)	$	571		$	(219	)	$	790
Throughput margin per barrel (d)	$	7.87		$	5.08		$	2.79
Operating costs per barrel (c):
Operating expenses	$	3.76		$	3.76		$	–
Depreciation and amortization		1.48			1.55			(0.07	)
Total operating costs per barrel	$	5.24		$	5.31		$	(0.07	)
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		443			430			13
Medium/light sour crude		511			489			22
Acidic sweet crude		53			24			29
Sweet crude		733			670			63
Residuals		242			159			83
Other feedstocks		124			176			(52	)
Total feedstocks		2,106			1,948			158
Blendstocks and other		258			280			(22	)
Total throughput volumes		2,364			2,228			136
Yields (thousand barrels per day):
Gasolines and blendstocks		1,153			1,137			16
Distillates		829			708			121
Petrochemicals		77			71			6
Other products (e)		337			327			10
Total yields		2,396			2,243			153
Retail – U.S.:
Operating income	$	72		$	79		$	(7	)
Company-operated fuel sites (average)		990			998			(8	)
Fuel volumes (gallons per day per site)		5,204			4,963			241
Fuel margin per gallon	$	0.210		$	0.231		$	(0.021	)
Merchandise sales	$	322		$	315		$	7
Merchandise margin (percentage of sales)		29.6	%		28.7	%		0.9	%
Margin on miscellaneous sales	$	21		$	22		$	(1	)
Operating expenses	$	127		$	120		$	7
Depreciation and amortization expense	$	18		$	17		$	1
Retail – Canada:
Operating income	$	33		$	32		$	1
Fuel volumes (thousand gallons per day)		3,214			3,115			99
Fuel margin per gallon	$	0.263		$	0.263		$	0.000
Merchandise sales	$	66		$	58		$	8
Merchandise margin (percentage of sales)		31.1	%		28.6	%		2.5	%
Margin on miscellaneous sales	$	10		$	10		$	–
Operating expenses	$	65		$	62		$	3
Depreciation and amortization expense	$	9		$	8		$	1

See the footnote references on page 50.

47

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

	Three Months Ended September 30,
	2010		2009		Change
Ethanol (a):
Operating income	$	47	$	49	$	(2	)
Ethanol production (thousand gallons per day)		3,100		2,116		984
Gross margin per gallon of ethanol production	$	0.54	$	0.59	$	(0.05	)
Operating costs per gallon of ethanol production:
Operating expenses	$	0.34	$	0.31	$	0.03
Depreciation and amortization		0.03		0.03		0.00
Total operating costs per gallon of ethanol production	$	0.37	$	0.34	$	0.03

See the footnote references on page 50.

48

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

	Three Months Ended September 30,
	2010		2009			Change
Gulf Coast:
Operating income (loss)	$	388	$	(81	)	$	469
Throughput volumes (thousand barrels per day)		1,336		1,238			98
Throughput margin per barrel (d)	$	8.34	$	4.66		$	3.68
Operating costs per barrel (c):
Operating expenses	$	3.65	$	3.81		$	(0.16	)
Depreciation and amortization		1.54		1.57			(0.03	)
Total operating costs per barrel	$	5.19	$	5.38		$	(0.19	)
Mid-Continent:
Operating income	$	131	$	5		$	126
Throughput volumes (thousand barrels per day)		422		374			48
Throughput margin per barrel (d)	$	8.06	$	5.38		$	2.68
Operating costs per barrel (c):
Operating expenses	$	3.34	$	3.69		$	(0.35	)
Depreciation and amortization		1.33		1.53			(0.20	)
Total operating costs per barrel	$	4.67	$	5.22		$	(0.55	)
Northeast (b):
Operating income (loss)	$	17	$	(38	)	$	55
Throughput volumes (thousand barrels per day)		354		334			20
Throughput margin per barrel (d)	$	5.26	$	3.39		$	1.87
Operating costs per barrel (c):
Operating expenses	$	3.47	$	3.17		$	0.30
Depreciation and amortization		1.27		1.45			(0.18	)
Total operating costs per barrel	$	4.74	$	4.62		$	0.12
West Coast:
Operating income	$	35	$	67		$	(32	)
Throughput volumes (thousand barrels per day)		252		282			(30	)
Throughput margin per barrel (d)	$	8.66	$	8.51		$	0.15
Operating costs per barrel (c):
Operating expenses	$	5.42	$	4.35		$	1.07
Depreciation and amortization		1.74		1.58			0.16
Total operating costs per barrel	$	7.16	$	5.93		$	1.23
Operating income (loss) for regions above	$	571	$	(47	)	$	618
Asset impairment loss applicable to refining (c)		–		(58	)		58
Loss contingency accrual related to Aruba tax matter (g)		–		(114	)		114
Total refining operating income (loss)	$	571	$	(219	)	$	790

See the footnote references on page 50.

49

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

	Three Months Ended September 30,
	2010		2009		Change
Feedstocks:
West Texas Intermediate (WTI) crude oil	$	76.08	$	68.18	$	7.90
WTI less sour crude oil at U.S. Gulf Coast (i)		2.56		1.72		0.84
WTI less Mars crude oil		1.38		1.78		(0.40	)
WTI less Maya crude oil		8.47		5.02		3.45
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		6.93		7.85		(0.92	)
Ultra-low-sulfur diesel less WTI		11.69		6.97		4.72
Propylene less WTI		5.19		8.22		(3.03	)
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		9.20		8.11		1.09
Ultra-low-sulfur diesel less WTI		13.19		8.01		5.18
U.S. Northeast:
Conventional 87 gasoline less WTI		6.70		8.34		(1.64	)
No. 2 fuel oil less WTI		9.15		4.95		4.20
Lube oils less WTI		59.71		28.89		30.82
U.S. West Coast:
CARBOB 87 gasoline less WTI		16.50		18.00		(1.50	)
CARB diesel less WTI		14.64		9.29		5.35
New York Harbor corn crush (dollars per gallon)		0.43		0.54		(0.11	)

     The following notes relate to references on pages 46 through 50.

(a)	We acquired seven ethanol plants in the second quarter of 2009 and three ethanol plants in the first quarter of 2010. The information presented above includes the results of operations of those plants commencing on their respective acquisition closing dates. The ethanol plants acquired in 2009 were purchased from VeraSun Energy Corporation. Of the three plants acquired in the first quarter of 2010, two were purchased from ASA Ethanol Holdings, LLC (ASA) and the third was purchased from Renew Energy LLC (Renew). Ethanol production volumes reflected herein 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. 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 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 September 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. The asset impairment loss applicable to the refining business segment has been excluded from refining operating expenses in determining operating costs per barrel.
(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)	A loss contingency accrual of $140 million ($0.25 per share) was recorded in the third quarter of 2009 related to our dispute with the Government of Aruba regarding a turnover tax on export sales as well as other tax matters. The portion of the loss

50

	contingency accrual that relates to the turnover tax was recorded in cost of sales for the three months ended September 30, 2009, and therefore is included in refining operating income (loss) but has been excluded in determining throughput margin per barrel.
(h)	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.
(i)	The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.

General

Operating revenues increased 20% (or $3.6 billion) for the third quarter of 2010 compared to the third quarter of 2009 primarily as a result of higher refined product prices and higher throughput volumes between the two periods. Operating income increased $809 million and income from continuing operations before taxes increased $831 million for the third quarter of 2010 compared to amounts reported for the third quarter of 2009 primarily due to a $790 million increase in refining segment operating income discussed below.

Refining

Results of operations of our refining segment increased from an operating loss of $219 million for the third quarter of 2009 to operating income of $571 million for the third quarter of 2010. The $790 million increase is due to an overall improvement in operating results ($618 million), reduced asset impairment losses ($58 million), and no loss contingency accruals ($114 million). The asset impairment loss recorded during the third quarter of 2009 related to our decision to permanently cancel certain construction projects in response to the economic slowdown that began in 2008. We continue to evaluate our ongoing construction projects, but the number and significance of projects cancelled has substantially declined so far in 2010. The loss contingency accrual was recorded in the third quarter of 2009 and related to our dispute of a turnover tax on export sales in Aruba.

The $618 million improvement in operating results was primarily due to a 55% increase in throughput margin per barrel (a $2.79 per barrel increase between the comparable periods) combined with a 6% increase in total throughput volumes (a 136,000 barrel per day increase between the comparable periods). The increase in throughput margin per barrel was caused by a significant improvement in distillate margins, but that improvement was somewhat offset by a decline in gasoline margins in three of our four 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 ultra-low-sulfur diesel, which is a type of distillate, was $11.69 per barrel for the third quarter of 2010, compared to $6.97 per barrel for the third quarter of 2009, representing a favorable increase of $4.72 per barrel. Similar increases in distillate margins were experienced in other regions. We estimate that the increase in margin for distillates had a $411 million positive impact to our overall refining margin, quarter versus quarter, as we produced 829,000 barrels per day of distillates during the third quarter of 2010. Distillate margins were higher in the third quarter of 2010 as compared to the third 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.

The benchmark reference margin for U.S. Gulf Coast Conventional 87 gasoline (Gulf Coast 87 gasoline) was $6.93 per barrel for the third quarter of 2010, compared to $7.85 per barrel for the third quarter of 2009, representing an unfavorable decrease of $0.92 per barrel. Conventional 87 gasoline benchmark reference margins decreased quarter versus quarter to an even greater extent in the Northeast region

51

(a $1.64 per barrel unfavorable decrease), but the margins increased quarter versus quarter in the Mid-Continent region (a $1.09 per barrel favorable increase). We estimate that the overall decrease in gasoline margins had a $93 million negative impact to our overall refining margin, quarter versus quarter, as we produced 1.15 million barrels per day of gasoline during the third quarter of 2010. Gasoline margins were lower in the third quarter of 2010 as compared to the third quarter of 2009 despite an increase in gasoline prices in the third 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 customers increased the use of ethanol as a component in 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 typically 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 $8.47 per barrel to West Texas Intermediate crude oil, which is a type of sweet crude oil, during the third quarter of 2010. This compares to a discount of $5.02 per barrel during the third quarter of 2009, representing a favorable increase of $3.45 per barrel. We estimate that the wider discounts for all types of sour crude oil that we process had a $125 million positive impact to our overall refining margin, quarter versus quarter, as we processed 954,000 barrels per day of sour crude oils.

Retail

Retail operating income was $105 million for the third quarter of 2010 compared to $111 million for the third quarter of 2009. This 5% (or $6 million) decrease was primarily due to higher operating expenses of $10 million, which consisted of an increase in credit card fees of $3 million and maintenance expenses of $2 million in our U.S. retail operations and $3 million related to the strengthening of the Canadian dollar relative to the U.S. dollar in our Canadian retail operations.

Ethanol

Ethanol operating income was $47 million for the third quarter of 2010 compared to $49 million for the third quarter of 2009. The $2 million decrease in operating income resulted from a $35 million increase in gross margin, offset by a $37 million increase in operating expenses.

Ethanol gross margin increased from the third quarter of 2009 to the third quarter of 2010 due an increase in ethanol production (a 984,000 gallon per day increase between the comparable periods) resulting from the operation of three additional plants acquired in the first quarter of 2010. This increase, however, was negatively impacted by an 8% decrease in the gross margin per gallon of ethanol production (a $0.05 per gallon decrease between the comparable periods). The decrease in gross margin per gallon was primarily due to a decrease in the New York Harbor corn crush (Corn Crush), which is the benchmark reference margin for ethanol. The Corn Crush was $0.43 per gallon for the third quarter of 2010, compared to $0.54 per gallon for the third quarter of 2009, representing an unfavorable decrease of $0.11 per gallon.

The increase in operating expenses was due primarily to $28 million in operating expenses related to the operation of the three additional ethanol plants acquired in the first quarter of 2010.

Corporate Expenses and Other

General and administrative expenses decreased $28 million from the third quarter of 2009 to the third quarter of 2010 primarily due to litigation costs of $40 million in the third quarter of 2009.

52

“Other income, net” for the third quarter of 2010 increased $10 million from the third quarter of 2009 due mainly to the recognition of a $7 million gain from the dissolution and distribution from an entity in which we had a minor investment.

Interest and debt expense for the third quarter of 2010 decreased $12 million from the third quarter of 2009. This decrease is composed of a decrease in interest expense primarily due to a $6 million charge in the third quarter of 2009 to write-off a pro rata portion of unamortized fair value related to $76 million of 6.75% putable senior notes that were subsequently redeemed in the fourth quarter of 2009, and a $7 million increase in capitalized interest due to a corresponding increase in capital expenditures between the quarters.

Income tax expense increased $196 million from the third quarter of 2009 to the third quarter of 2010 mainly as a result of higher operating income.

The loss from discontinued operations of $286 million for the third quarter of 2009 represents the net loss from operations of our shutdown Delaware City Refinery. This refinery was sold in June 2010.

53

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

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

	Nine Months Ended September 30,
	2010			2009			Change
Operating revenues	$	63,628		$	49,277		$	14,351
Costs and expenses:
Cost of sales		57,479			44,430			13,049
Operating expenses:
Refining		2,405			2,355			50
Retail		552			522			30
Ethanol		267			102			165
General and administrative expenses		367			434			(67	)
Depreciation and amortization expense:
Refining		951			951			–
Retail		80			74			6
Ethanol		27			12			15
Corporate		38			35			3
Asset impairment loss (c)		2			199			(197	)
Total costs and expenses		62,168			49,114			13,054
Operating income		1,460			163			1,297
Other income (expense), net		30			(16	)		46
Interest and debt expense:
Incurred		(430	)		(387	)		(43	)
Capitalized		68			92			(24	)
Income (loss) from continuing operations before income tax expense		1,128			(148	)		1,276
Income tax expense		407			22			385
Income (loss) from continuing operations		721			(170	)		891
Income (loss) from discontinued operations, net of income taxes		41			(404	)		445
Net income (loss)	$	762		$	(574	)	$	1,336
Earnings (loss) per common share – assuming dilution:
Continuing operations	$	1.27		$	(0.32	)	$	1.59
Discontinued operations		0.07			(0.76	)		0.83
Total	$	1.34		$	(1.08	)	$	2.42

See the footnote references on page 58.

54

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

	Nine Months Ended September 30,
	2010			2009			Change
Refining (b):
Operating income (c)	$	1,441		$	331		$	1,110
Throughput margin per barrel (d)	$	7.76		$	6.23		$	1.53
Operating costs per barrel (c):
Refining operating expenses	$	3.89		$	3.71		$	0.18
Depreciation and amortization		1.54			1.50			0.04
Total operating costs per barrel	$	5.43		$	5.21		$	0.22
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		452			480			(28	)
Medium/light sour crude		499			536			(37	)
Acidic sweet crude		52			78			(26	)
Sweet crude		688			611			77
Residuals		197			168			29
Other feedstocks		127			171			(44	)
Total feedstocks		2,015			2,044			(29	)
Blendstocks and other		251			279			(28	)
Total throughput volumes		2,266			2,323			(57	)
Yields (thousand barrels per day):
Gasolines and blendstocks		1,111			1,110			1
Distillates		757			764			(7	)
Petrochemicals		74			67			7
Other products (e)		348			386			(38	)
Total yields		2,290			2,327			(37	)
Retail – U.S.:
Operating income	$	181		$	140		$	41
Company-operated fuel sites (average)		990			1,001			(11	)
Fuel volumes (gallons per day per site)		5,115			5,022			93
Fuel margin per gallon	$	0.191		$	0.157		$	0.034
Merchandise sales	$	910		$	888		$	22
Merchandise margin (percentage of sales)		29.2	%		29.2	%		–	%
Margin on miscellaneous sales	$	65		$	66		$	(1	)
Operating expenses	$	360		$	349		$	11
Depreciation and amortization expense	$	54		$	52		$	2
Retail – Canada:
Operating income	$	104		$	92		$	12
Fuel volumes (thousand gallons per day)		3,131			3,155			(24	)
Fuel margin per gallon	$	0.279		$	0.255		$	0.024
Merchandise sales	$	179		$	146		$	33
Merchandise margin (percentage of sales)		31.1	%		29.1	%		2.0	%
Margin on miscellaneous sales	$	29		$	25		$	4
Operating expenses	$	192		$	173		$	19
Depreciation and amortization expense	$	26		$	22		$	4

See the footnote references on page 58.

55

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

	Nine Months Ended September 30,
	2010		2009		Change
Ethanol (a):
Operating income	$	139	$	71	$	68
Ethanol production (thousand gallons per day)		2,943		1,229		1,714
Gross margin per gallon of ethanol production	$	0.54	$	0.55	$	(0.01	)
Operating costs per gallon of ethanol production:
Operating expenses	$	0.33	$	0.31	$	0.02
Depreciation and amortization		0.04		0.03		0.01
Total operating costs per gallon of ethanol production	$	0.37	$	0.34	$	0.03

See the footnote references on page 58.

56

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

	Nine Months Ended September 30,
	2010			2009			Change
Gulf Coast:
Operating income	$	1,027		$	28		$	999
Throughput volumes (thousand barrels per day)		1,268			1,316			(48	)
Throughput margin per barrel (d)	$	8.35		$	5.22		$	3.13
Operating costs per barrel (c):
Operating expenses	$	3.78		$	3.65		$	0.13
Depreciation and amortization		1.60			1.49			0.11
Total operating costs per barrel	$	5.38		$	5.14		$	0.24
Mid-Continent:
Operating income	$	271		$	197		$	74
Throughput volumes (thousand barrels per day)		392			381			11
Throughput margin per barrel (d)	$	7.59		$	7.18		$	0.41
Operating costs per barrel (c):
Operating expenses	$	3.63		$	3.72		$	(0.09	)
Depreciation and amortization		1.42			1.57			(0.15	)
Total operating costs per barrel	$	5.05		$	5.29		$	(0.24	)
Northeast (b):
Operating income	$	43		$	86		$	(43	)
Throughput volumes (thousand barrels per day)		347			345			2
Throughput margin per barrel (d)	$	5.51		$	5.46		$	0.05
Operating costs per barrel (c):
Operating expenses	$	3.69		$	3.22		$	0.47
Depreciation and amortization		1.36			1.32			0.04
Total operating costs per barrel	$	5.05		$	4.54		$	0.51
West Coast:
Operating income	$	102		$	331		$	(229	)
Throughput volumes (thousand barrels per day)		259			281			(22	)
Throughput margin per barrel (d)	$	8.14		$	10.59		$	(2.45	)
Operating costs per barrel (c):
Operating expenses	$	5.08		$	4.60		$	0.48
Depreciation and amortization		1.62			1.67			(0.05	)
Total operating costs per barrel	$	6.70		$	6.27		$	0.43
Operating income for regions above	$	1,443		$	642		$	801
Asset impairment loss applicable to refining (c)		(2	)		(197	)		195
Loss contingency accrual related to Aruba tax matter (g)		–			(114	)		114
Total refining operating income	$	1,441		$	331		$	1,110

See the footnote references on page 58.

57

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

	Nine Months Ended September 30,
	2010		2009			Change
Feedstocks:
WTI crude oil	$	77.52	$	56.90		$	20.62
WTI less sour crude oil at U.S. Gulf Coast (i)		3.15		1.25			1.90
WTI less Mars crude oil		1.56		1.06			0.50
WTI less Maya crude oil		9.04		4.68			4.36
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		8.09		8.85			(0.76	)
Ultra-low-sulfur diesel less WTI		10.44		8.58			1.86
Propylene less WTI		9.63		(3.05	)		12.68
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		8.77		9.09			(0.32	)
Ultra-low-sulfur diesel less WTI		11.06		8.63			2.43
U.S. Northeast:
Conventional 87 gasoline less WTI		8.02		8.78			(0.76	)
No. 2 fuel oil less WTI		8.71		7.68			1.03
Lube oils less WTI		48.80		40.54			8.26
U.S. West Coast:
CARBOB 87 gasoline less WTI		14.53		18.40			(3.87	)
CARB diesel less WTI		12.51		10.30			2.21
New York harbor corn crush (dollars per gallon)		0.41		0.38			0.03

The following notes relate to references on pages 54 through 58.

(a)	We acquired seven ethanol plants in the second quarter of 2009 and three ethanol plants in the first quarter of 2010. The information presented above includes the results of operations of those plants commencing on their respective acquisition closing dates. The ethanol plants acquired in 2009 were purchased from VeraSun Energy Corporation. Of the three plants acquired in the first quarter of 2010, two were purchased from ASA and the third was purchased from Renew. Ethanol production volumes reflected herein 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 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 nine months ended September 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 receiving proceeds related to 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 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. The asset impairment loss applicable to the refining business segment has been excluded from refining operating expenses in determining operating costs per barrel.
(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

58

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

General

Operating revenues increased 29% (or $14.4 billion) for the first nine months of 2010 compared to the first nine months of 2009 primarily as a result of higher refined product prices between the two periods. Operating income and income from continuing operations before taxes increased $1.3 billion and $1.3 billion, respectively, for the first nine months of 2010 compared to the amounts reported in the first nine months of 2009 primarily due to a $1.1 billion increase in refining segment operating income discussed below.

Refining

Operating income for our refining segment increased from $331 million for the first nine months of 2009 to $1.4 billion for the first nine months of 2010. The $1.1 billion increase is primarily due to an improvement in operating results ($801 million), reduced asset impairment loss ($195 million), and no loss contingency accruals ($114 million). The asset impairment loss recorded during the first nine months of 2009 related to our decision to permanently cancel certain construction projects in response to the economic slowdown that began in 2008. We continue to evaluate our ongoing construction projects, but the number and significance of projects cancelled has substantially declined so far in 2010. The loss contingency accrual recorded in the third quarter of 2009 related to our dispute of a turnover tax on export sales in Aruba.

The $801 million improvement in operating results was primarily due to a 25% increase in throughput margin per barrel (a $1.53 per barrel increase between the comparable periods). The increase in throughput margin per barrel was caused by a significant improvement in distillate margins and petrochemical (primarily propylene) margins, but those improvements were 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 ultra-low-sulfur diesel, which is a type of distillate, was $10.44 per barrel for the first nine months of 2010, compared to $8.58 per barrel for the first nine months of 2009, representing a favorable increase of $1.86 per barrel. Similar increases in distillate margins were experienced in other regions. We estimate that the increase in margin for distillates had a $290 million positive impact to our overall refining margin, nine months versus nine months, as we produced 757,000 barrels per day of distillates during the first nine months of 2010. Similarly, the benchmark reference margin for U.S. Gulf Coast propylene was $9.63 per barrel for the first nine months of 2010, compared to a negative margin of $3.05 per barrel for the first nine months of 2009, representing a favorable increase of $12.68 per barrel. We estimate that the increase in margin for petrochemicals (primarily propylene) had a $179 million positive impact on our refining margin, nine months versus nine months, as we produced 74,000 barrels per day of petrochemicals during the first nine

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months of 2010. Distillate and propylene margins were higher in the first nine months of 2010 as compared to the first nine months 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.

The benchmark reference margin for U.S. Gulf Coast Conventional 87 gasoline (Gulf Coast 87 gasoline) was $8.09 per barrel for the first nine months of 2010, compared to $8.85 per barrel for the first nine months of 2009, representing an unfavorable decrease of $0.76 per barrel. Conventional 87 gasoline benchmark reference margins decreased nine months versus nine months to an even greater extent in the West Coast region (a $3.87 per barrel unfavorable decrease). We estimate that the decrease in gasoline margins had a $420 million negative impact to our overall refining margin, nine months versus nine months, as we produced 1.11 million barrels per day of gasoline during the first nine months of 2010. Gasoline margins were lower in the first nine months of 2010 as compared to the first nine months of 2009 despite an increase in gasoline prices in the first nine months 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 customers increased the use of ethanol as a component in gasoline.

For the first nine 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 nine months of 2009. For example, Maya crude oil, which is a type of sour crude oil, sold at a discount of $9.04 per barrel to West Texas Intermediate crude oil, which is a type of sweet crude oil, during the first nine months of 2010. This compared to a discount of $4.68 per barrel during the first nine months of 2009, representing a favorable increase of $4.36 per barrel. The benefit of this wider discount, however, was offset by a reduction of 65,000 barrels per day of sour crude oil that we processed during the first nine months of 2010 as compared to the first nine months of 2009. We estimate that the wider discounts for all types of sour crude oil that we process, offset by reduced throughput volumes, had a $375 million net positive impact to our overall refining margin, nine months versus nine months, as we processed 951,000 barrels per day of sour crude oils.

Favorable increases in the margins we received for all other products we produced had a $269 million favorable impact to the overall improvement in refining operating results.

Retail

Retail operating income was $285 million for the first nine months of 2010 compared to $232 million for the first nine months of 2009. This 23% (or $53 million) increase was primarily due to improved retail fuel margins of $67 million, partially offset by a $30 million increase in operating expenses, $19 million of which relates to our Canadian retail operations. The $11 million increase in U.S. operating expenses was due to increased credit card fees in our U.S. retail operations, and the $19 million increase in Canadian operating expenses was due to the strengthening of the Canadian dollar relative to the U.S. dollar.

Retail fuel margins benefited from the blending of ethanol with the gasoline sold by our retail segment. For substantially all of 2010, ethanol was a lower cost product than gasoline and this lower cost resulted in an increase in retail fuel margins. For example, the Chicago Board of Trade price for a gallon of ethanol was $0.34 less than a gallon of Gulf Coast 87 gasoline for the first nine months of 2010, compared to $0.06 higher than a gallon of Gulf Coast 87 gasoline for the first nine months of 2009. In addition, approximately 80% of the gasoline we sold during the first nine months of 2010 contained 10% ethanol as compared to approximately 65% of the gasoline sold during the first nine months of 2009. In September 2010, the price of ethanol exceeded the price of gasoline; therefore, the benefit to retail fuel margins from blending ethanol may not occur for the fourth quarter of 2010.

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Ethanol

Ethanol operating income was $139 million for the first nine months of 2010 compared to $71 million for the first nine months of 2009. The increase of $68 million was due to a full nine months of operation 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 in Note 3 of Condensed Notes to Consolidated Financial Statements.

Corporate Expenses and Other

General and administrative expenses decreased $67 million from the first nine months of 2009 to the first nine months of 2010 due mainly to a favorable settlement with an insurance company for $40 million recorded in 2010 which offset an increase in litigation costs of $40 million recorded in 2009.

“Other income (expense), net” for the first nine months of 2010 increased $46 million from the first nine months of 2009 primarily due to a $42 million net loss in 2009 resulting from an unfavorable change in fair value adjustments related to an earn-out agreement and associated derivative instruments that were entered into in connection with the sale of our Krotz Springs Refinery in 2008.

Interest and debt expense increased $67 million from the first nine months of 2009 to the first nine months of 2010. This increase is composed of a $43 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 $24 million decrease in capitalized interest due to a corresponding reduction in capital expenditures between the periods 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 $385 million from the first nine months of 2009 to the first nine months of 2010 due to higher operating income.

Income from discontinued operations of $41 million for the first nine 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 receiving proceeds related to 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.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Nine months Ended September 30, 2010 and 2009

Net cash provided by operating activities for the first nine months of 2010 was $2.6 billion compared to $1.9 billion for the first nine 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 nine 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 nine months of 2010, combined with $1.244 billion of net 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

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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 $1.6 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 $85 million;

• purchase additional ethanol plants for $260 million; and

• increase available cash on hand by $1.5 billion.

The net cash generated from operating activities during the first nine months of 2009, combined with $998 million of net 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 $2.1 billion of capital expenditures and deferred turnaround and catalyst costs;

• fund the VeraSun Acquisition for $556 million;

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

• pay common stock dividends of $239 million; and

• increase available cash on hand by $665 million.

Capital Investments

During the nine months ended September 30, 2010, we expended $1.2 billion for capital expenditures and $410 million for deferred turnaround and catalyst costs. Capital expenditures for the nine months ended September 30, 2010 included $575 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 $540 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 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 receiving proceeds related to 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 statement of income for the nine months ended September 30, 2010.

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Contractual Obligations

As of September 30, 2010, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities.

During 2010, the following activity occurred related to our non-bank debt:

• 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 for total net proceeds of $1.244 billion;

• 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, resulting in a $2 million gain;

• 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, resulting in a $3 million loss; and

• 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 September 30, 2010, the amount of eligible receivables sold was $100 million.

During the nine months ended September 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.

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

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Other Commercial Commitments

As of September 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 September 30, 2010, we had $285 million of letters of credit outstanding under our uncommitted short-term bank credit facilities and $215 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 September 30, 2010. Our letters of credit expire during 2010 and 2011.

Stock Purchase Programs

As of September 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. 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 in the quarter ended June 30, 2010.

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Other Matters Impacting Liquidity and Capital Resources

During the nine months ended September 30, 2010, we contributed $50 million to our qualified pension plans. We currently anticipate contributing $100 million to our qualified pension plans in December 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 ultimately 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.

While debate continues in the U.S. Congress regarding the regulation of greenhouse gases, discussions regarding the previously proposed federal “cap-and-trade” legislation appear to have stalled. The regulation of greenhouse gases at the federal level has now shifted to the U.S. Environmental Protection Agency (EPA), which will begin regulating greenhouse gases on January 2, 2011 under the Clean Air Act of 1990, as amended (Clean Air Act). According to statements by the EPA, any new construction or material expansions will require that, among other things, a greenhouse gas permit be issued at either or both the state or federal level in accordance with the Clean Air Act and regulations and will be required to undertake a technology review to determine appropriate controls to be implemented with the project in order to reduce greenhouse gas emissions. At this date, the EPA has not issued detailed regulations regarding what it considers to be appropriate controls for greenhouse gas emissions. Any such controls, however, could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

In addition, certain states have pursued the regulation of greenhouse gases at the state level. For example, in 2006, California enacted the California Global Warming Solutions Act, also known as AB 32. AB 32 directed the California Air Resources Board (CARB) to develop and issue regulations the goal of which are to reduce greenhouse gas emissions in California to 1990 levels by 2020. CARB has proposed a variety of regulations aimed at reaching this goal, including a Low Carbon Fuel Standard as well as a state-wide cap and trade program. While CARB has not yet issued detailed regulations on the cap and trade program, we believe it will require our California refineries to buy emission credits to offset

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greenhouse gases emitted from our refineries. It is unclear if and when CARB would require us to purchase emission credits for greenhouse gas emissions resulting from the fuels we sell in California as well. Unless deferred, AB 32 implementation will begin as soon as 2011. Complying with AB 32 could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of 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 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 against the EPA regarding its actions has been brought by multiple stakeholders, including trade associations. 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
September 30, 2010:
Gain (loss) in fair value due to:
10% increase in underlying commodity prices	$	(112	)	$	(8	)
10% decrease in underlying commodity prices		105			8
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 September 30, 2010.

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INTEREST RATE RISK

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

	September 30, 2010
	Expected Maturity Dates
																There-						Fair
	2010			2011			2012			2013			2014			after			Total			Value
Debt (excluding capital leases):
Fixed rate	$	–		$	418		$	759		$	489		$	209		$	6,089		$	7,964		$	9,495
Average interest rate		–	%		6.4	%		6.9	%		5.5	%		4.8	%		7.1	%		6.9	%
Floating rate	$	–		$	100		$	–		$	–		$	–		$	–		$	100		$	100
Average interest rate		–	%		0.8	%		–	%		–	%		–	%		–	%		0.8	%
	December 31, 2009
	Expected Maturity Dates
																There-						Fair
	2010			2011			2012			2013			2014			after			Total			Value
Debt (excluding capital leases):
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 September 30, 2010, we had commitments to purchase $308 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before October 22, 2010, resulting in a $4 million loss in the fourth 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 September 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 reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 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.

United States Environmental Protection Agency (EPA)(Corpus Christi West Refinery). In September 2010, the EPA issued a stipulated penalty demand of $120,885 to our Corpus Christi West Refinery pertaining to three 2008 acid gas flaring events that we self-reported. We resolved this matter by paying agreed upon penalties to the pertinent enforcement authorities.

Texas Commission on Environmental Quality (TCEQ)(Corpus Christi West Refinery). In our Annual Report on Form 10-K for the year ended December 31, 2009, we disclosed that we were negotiating with the TCEQ regarding a collection of enforcement actions pertaining to our Corpus Christi West Refinery which alleged excess air emissions, reporting errors, unauthorized tank emissions, and waste violations. In the third quarter of 2010, we settled these matters pursuant to two agreed orders with the TCEQ.

TCEQ(Corpus Christi East Refinery). In October 2010, we received a proposed agreed order from the TCEQ relating to unauthorized air emissions during a flaring event and excess air emissions from three plant boilers at our Corpus Christi East Refinery. The gross penalty demand is stated to be $416,500, but is subject to reduction to $333,200 under certain circumstances. We are evaluating the order and are considering our options in responding.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2009, and our quarterly report on Form 10-Q for the quarter ended June 30, 2010.

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

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

          (b) Use of Proceeds. Not applicable.

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

Period	Total		Average		Total Number of		Total Number of		Maximum Number (or
	Number of		Price		Shares Not		Shares Purchased		Approximate Dollar
	Shares		Paid per		Purchased as Part		as Part of		Value) of Shares that
	Purchased		Share		of Publicly		Publicly		May Yet Be Purchased
					Announced Plans		Announced Plans		Under the Plans or
					or Programs (1)		or Programs		Programs
									(at month end) (2)
July 2010		856	$	17.58		856		–	$3.46 billion
August 2010		2,932	$	16.94		2,932		–	$3.46 billion
September 2010		376	$	16.92		376		–	$3.46 billion
Total		4,164	$	17.07		4,164		–	$3.46 billion

(1)

The shares reported in this column represent purchases settled in the third 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 September 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: November 3, 2010

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