Valero Energy (VLO) 10-Q 2007 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2007

OR

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

For the transition period from                                          to                             

Commission file number 1-13175

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one).

Large accelerated filer X Accelerated filer __ Non-accelerated filer __

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes __  No X

The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of October 31, 2007 was 550,436,386.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

INDEX

	Page
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2007 and December 31, 2006		3
Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2007 and 2006		4
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2007 and 2006		5
Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2007 and 2006		6
Condensed Notes to Consolidated Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Item 3. Quantitative and Qualitative Disclosures About Market Risk		50
Item 4. Controls and Procedures		55
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		55
Item 1A. Risk Factors		57
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		57
Item 6. Exhibits		58
SIGNATURE		59

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,
	2007			2006
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	3,109		$	1,590
Restricted cash		31			31
Receivables, net		6,463			4,384
Inventories		4,616			3,979
Income taxes receivable		-			32
Deferred income taxes		197			143
Prepaid expenses and other		238			145
Assets held for sale		-			1,527
Total current assets		14,654			11,831
Property, plant and equipment, at cost		25,077			23,421
Accumulated depreciation		(3,853	)		(3,241	)
Property, plant and equipment, net		21,224			20,180
Intangible assets, net		298			303
Goodwill		4,061			4,103
Deferred charges and other assets, net		1,624			1,336
Total assets	$	41,861		$	37,753
LIABILITIES AND STOCKHOLDERS’EQUITY
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	60		$	475
Accounts payable		8,145			6,841
Accrued expenses		608			507
Taxes other than income taxes		612			584
Income taxes payable		494			23
Deferred income taxes		323			363
Liabilities related to assets held for sale		-			67
Total current liabilities		10,242			8,860
Long-term debt and capital lease obligations, less current portion		6,854			4,619
Deferred income taxes		3,941			4,047
Other long-term liabilities		1,856			1,622
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 627,501,593 and 627,501,593 shares issued		6			6
Additional paid-in capital		7,366			7,779
Treasury stock, at cost; 79,121,102 and 23,738,162 common shares		(5,308	)		(1,396	)
Retained earnings		16,413			11,951
Accumulated other comprehensive income		491			265
Total stockholders’ equity		18,968			18,605
Total liabilities and stockholders’ equity	$	41,861		$	37,753

See Condensed Notes to Consolidated Financial Statements.

3

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Millions of Dollars, Except per Share Amounts)

(Unaudited)

		Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Operating revenues (1)	$	23,699		$	23,238		$	66,656		$	68,805
Costs and expenses:
Cost of sales		20,810			19,482			55,630			58,007
Refining operating expenses		1,036			889			2,955			2,684
Retail selling expenses		190			185			561			539
General and administrative expenses		152			136			474			458
Depreciation and amortization expense		343			285			1,002			819
Total costs and expenses		22,531			20,977			60,622			62,507
Operating income		1,168			2,261			6,034			6,298
Equity in earnings of NuStar Energy L.P.		—			13			—			35
Other income, net		145			143			157			138
Interest and debt expense:
Incurred		(148	)		(91	)		(347	)		(280	)
Capitalized		25			45			83			126
Minority interest in net income of consolidated subsidiary		—			(4	)		—			(4	)
Income from continuing operations before income tax expense		1,190			2,367			5,927			6,313
Income tax expense		342			808			1,929	��		2,107
Income from continuing operations		848			1,559			3,998			4,206
Income from discontinued operations, net of income tax expense		426			44			669			143
Net income		1,274			1,603			4,667			4,349
Preferred stock dividends		—			—			—			2
Net income applicable to common stock	$	1,274		$	1,603		$	4,667		$	4,347
Earnings per common share:
Continuing operations	$	1.54		$	2.56		$	7.00		$	6.85
Discontinued operations		0.77			0.07			1.17			0.23
Total	$	2.31		$	2.63		$	8.17		$	7.08
Weighted-average common shares outstanding (in millions)		551			609			571			613
Earnings per common share – assuming dilution:
Continuing operations	$	1.34		$	2.48		$	6.66		$	6.61
Discontinued operations		0.75			0.07			1.14			0.22
Total	$	2.09		$	2.55		$	7.80		$	6.83
Weighted-average common shares outstanding – assuming dilution (in millions)		564			628			587			636
Dividends per common share	$	0.12		$	0.08		$	0.36		$	0.22
Supplemental information:
(1) Includes excise taxes on sales by our U.S. retail system	$	207		$	197		$	606		$	587

See Condensed Notes to Consolidated Financial Statements.

4

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

(Unaudited)

	Nine Months Ended September 30,
	2007			2006
Cash flows from operating activities:
Net income	$	4,667		$	4,349
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		1,019			847
Gain on sale of Lima Refinery		(827	)		—
Gain on sale of interest in NuStar GP Holdings, LLC		—			(132	)
Stock-based compensation expense		58			70
Deferred income tax expense (benefit)		(75	)		175
Changes in current assets and current liabilities		(880	)		(129	)
Changes in deferred charges and credits and other, net		44			(84	)
Net cash provided by operating activities		4,006			5,096
Cash flows from investing activities:
Capital expenditures		(1,553	)		(2,331	)
Deferred turnaround and catalyst costs		(338	)		(464	)
Proceeds from sale of interest in NuStar GP Holdings, LLC		—			355
Investment in Cameron Highway Oil Pipeline Company, net		(212	)		(13	)
Proceeds from sale of Lima Refinery		2,428			—
Contingent payments in connection with acquisitions		(75	)		(101	)
Other investing activities, net		18			42
Net cash provided by (used in) investing activities		268			(2,512	)
Cash flows from financing activities:
Long-term notes:
Borrowings		2,245			—
Repayments		(413	)		(249	)
Bank credit agreements:
Borrowings		3,000			707
Repayments		(3,000	)		(706	)
Termination of interest rate swaps		—			(54	)
Purchase of treasury stock		(4,751	)		(1,818	)
Issuance of common stock in connection with employee benefit plans		130			103
Benefit from tax deduction in excess of recognized stock-based compensation cost		231			160
Common and preferred stock dividends		(205	)		(136	)
Other financing activities		(23	)		(4	)
Net cash used in financing activities		(2,786	)		(1,997	)
Effect of foreign exchange rate changes on cash		31			6
Net increase in cash and temporary cash investments		1,519			593
Cash and temporary cash investments at beginning of period		1,590			436
Cash and temporary cash investments at end of period	$	3,109		$	1,029

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 September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Net income	$	1,274		$	1,603		$	4,667		$	4,349
Other comprehensive income (loss):
Foreign currency translation adjustment		90			(2	)		251			70
Pension and other postretirement benefits net loss reclassified into income, net of income tax benefit of $1, $0, $3 and $0		1			-			4			-
Net gain (loss) on derivative instruments designated and qualifying as cash flow hedges:
Net gain (loss) arising during the period, net of income tax (expense) benefit of $(37), $(17), $10 and $(18)		69			32			(18	)		34
Net gain reclassified into income, net of income tax expense of $2, $1, $6 and $4		(4	)		(2	)		(11	)		(8	)
Net gain (loss) on cash flow hedges		65			30			(29	)		26
Other comprehensive income		156			28			226			96
Comprehensive income	$	1,430		$	1,631		$	4,893		$	4,445

See Condensed Notes to Consolidated Financial Statements.

6

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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, 2007 and 2006 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, 2007 are not necessarily indicative of the results that may be expected for the year ending December 31, 2007.

The consolidated balance sheet as of December 31, 2006 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, 2006. As discussed in Note 3, the assets and liabilities of the Lima Refinery, as well as inventory to be sold by our marketing and supply subsidiary associated with this transaction, as of December 31, 2006 have been reclassified as held for sale, and the results of operations of the Lima Refinery have been presented as discontinued operations in the consolidated statements of income for all periods presented.

On December 22, 2006, we sold our remaining ownership interest in NuStar GP Holdings, LLC (formerly Valero GP Holdings, LLC), which indirectly owned the general partner interest, the incentive distribution rights, and a 21.4% limited partner interest in NuStar Energy L.P. (formerly Valero L.P.). As a result, our consolidated statements of income reflect no equity in earnings of NuStar Energy L.P. subsequent to December 21, 2006.

Reclassifications
Previously reported amounts have been reclassified to present the operations of the Lima Refinery as discontinued operations as discussed above. In addition, operating revenues, cost of sales, and retail selling expenses reported in our consolidated statements of income for 2006 have been reclassified for certain credit card transactions. Commencing January 1, 2007, fees received from our distributors and dealers associated with certain credit card transactions processed on behalf of those distributors and dealers are being netted against third-party processing costs incurred on such transactions to better reflect the nature of the credit card transactions. These credit card reclassifications increased (decreased) amounts previously reported in 2006 as follows (in millions):

7

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

	Three Months			Nine Months
	Ended			Ended
	September 30, 2006			September 30, 2006
Operating revenues	$	(21	)	$	(55	)
Cost of sales		2			7
Retail selling expenses		(23	)		(62	)

2. ACCOUNTING PRONOUNCEMENTS

FASB Statement No. 155
In February 2006, the Financial Accounting Standards Board (FASB) issued Statement No. 155, “Accounting for Certain Hybrid Financial Instruments,” which amends Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This statement improves the financial reporting of certain hybrid financial instruments and simplifies the accounting for these instruments. In particular, Statement No. 155 (i) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, (ii) clarifies which interest-only and principal-only strips are not subject to the requirements of Statement No. 133, (iii) establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, (iv) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives, and (v) amends Statement No. 140 to eliminate the prohibition on a qualifying special-purpose entity holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. The adoption of Statement No. 155 on January 1, 2007 has not affected our financial position or results of operations.

FASB Statement No. 156
In March 2006, the FASB issued Statement No. 156, “Accounting for Servicing of Financial Assets,” which amends Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” Statement No. 156 requires the initial recognition at fair value of a servicing asset or servicing liability when an obligation to service a financial asset is undertaken by entering into a servicing contract. The adoption of Statement No. 156 on January 1, 2007 has not affected our financial position or results of operations.

FASB Interpretation No. 48
In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes,” by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. If a tax position is more likely than not to be sustained upon examination, then an enterprise is required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The adoption of FIN 48 on January 1, 2007 did not materially affect our financial position or results of operations.

8

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

We have elected to classify any interest expense related to the underpayment of income taxes in “income tax expense” in our consolidated statements of income. Any penalties related to the underpayment of income taxes are recorded in the corresponding expense category in our consolidated statements of income.

EITF Issue No. 06-3
In June 2006, the FASB ratified its consensus on EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF No. 06-3). The scope of EITF No. 06-3 includes any tax assessed by a governmental authority that is imposed concurrent with or subsequent to a revenue-producing transaction between a seller and a customer. For taxes within the scope of this issue that are significant in amount, the consensus requires the following disclosures: (i) the accounting policy elected for these taxes and (ii) the amount of the taxes reflected gross in the income statement on an interim and annual basis for all periods presented. The disclosure of those taxes can be provided on an aggregate basis. We adopted the consensus on January 1, 2007. We present excise taxes on sales by our U.S. retail system on a gross basis with supplemental information regarding the amount of such taxes included in revenues provided in a footnote on the face of the income statement. All other excise taxes are presented on a net basis in the income statement.

FASB Statement No. 157
In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements.” Statement No. 157 defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measures. Statement No. 157 is effective for fiscal years beginning after November 15, 2007, with early adoption encouraged. The provisions of Statement No. 157 are to be applied on a prospective basis, with the exception of certain financial instruments for which retrospective application is required. The adoption of Statement No. 157 is not expected to materially affect our financial position or results of operations.

FASB Statement No. 159
In February 2007, the FASB issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” Statement No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Statement No. 159 is effective for fiscal years beginning after November 15, 2007, with early adoption permitted provided the entity also elects to apply the provisions of Statement No. 157. We do not expect the adoption of Statement No. 159 to have any material impact on our financial position or results of operations.

3. DISPOSITION OF LIMA REFINERY

On May 2, 2007, we entered into an agreement to sell our refinery in Lima, Ohio to Husky Refining Company (Husky), a wholly owned subsidiary of Husky Energy Inc. In addition, our marketing and supply subsidiary separately agreed to sell certain inventory amounts to Husky as part of this transaction. As a result, the assets and liabilities related to these transactions are presented as “assets held for sale” and “liabilities related to assets held for sale,” respectively, in the consolidated balance sheet as of December 31, 2006. In addition, the consolidated statements of income reflect the operations related to the Lima Refinery for the periods prior to the effective date of the sale in “income from discontinued operations, net of income tax expense.”

9

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

On July 3, 2007, we consummated the sale of our Lima Refinery to Husky with an effective date of July 1, 2007. Proceeds from the sale were approximately $2.4 billion, including approximately $550 million from the sale of working capital to Husky primarily related to the sale of inventory by our marketing and supply subsidiary. The sale resulted in a pre-tax gain of $827 million, or $426 million after tax, which is presented in “income from discontinued operations, net of income tax expense” in the consolidated statements of income for the three months and nine months ended September 30, 2007. In connection with the sale, we entered into a transition services agreement with Husky under which we agreed to provide certain accounting and administrative services to Husky beginning July 3, 2007, with the services terminating by July 31, 2008.

Financial information related to the assets and liabilities sold is summarized as follows (in millions):

	July 1,		December 31,
	2007		2006
Current assets (primarily inventory)	$	570	$	456
Property, plant and equipment, net		929		918
Goodwill		107		108
Deferred charges and other assets, net		46		45
Assets held for sale	$	1,652	$	1,527
Current liabilities, including current portion of capital lease obligation	$	15	$	29
Capital lease obligation, excluding current portion		38		38
Liabilities related to assets held for sale	$	53	$	67

		Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Operating revenues	$	—	$	1,060	$	2,231	$	3,181
Income before income tax expense		—		72		391		235

4. INVENTORIES

Inventories consisted of the following (in millions):

	September 30,		December 31,
	2007		2006
Refinery feedstocks	$	2,123	$	1,680
Refined products and blendstocks		2,245		2,056
Convenience store merchandise		80		85
Materials and supplies		168		158
Inventories	$	4,616	$	3,979

As of September 30, 2007 and December 31, 2006, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $5.2 billion and $2.9 billion, respectively.

10

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

5. INVESTMENT IN AND TRANSACTIONS WITH NUSTAR ENERGY L.P.

Our ownership interest in NuStar Energy L.P. as of June 30, 2006 was 23.4%, which was composed of a 2% general partner interest, incentive distribution rights, and a 21.4% limited partner interest. The limited partner interest was represented by 10,222,630 common units of NuStar Energy L.P., of which 9,599,322 were previously subordinated units that converted to common units on May 8, 2006 upon the termination of the subordination period in accordance with the terms of NuStar Energy L.P.’s partnership agreement.

Through the date of termination of the subordination period, NuStar Energy L.P. had issued common units to the public on three separate occasions, which had diluted our ownership percentage. These three issuances resulted in increases (or credits, known as SAB 51 credits due to the Securities and Exchange Commission Staff Accounting Bulletin that provides accounting guidance for such credits) in our proportionate share of NuStar Energy L.P.’s capital because, in each case, the issuance price per unit exceeded our carrying amount per unit at the time of issuance. We had not recognized any SAB 51 credits in our consolidated financial statements through March 31, 2006 and were not permitted to do so until the subordinated units converted to common units. In conjunction with the conversion of the subordinated units held by us to common units in the second quarter of 2006, we recognized the entire balance of $158 million in SAB 51 credits as an increase in our investment in NuStar Energy L.P. and $101 million after tax as an increase to “additional paid-in capital” in our consolidated balance sheet.

NuStar GP Holdings, LLC completed public offerings in July and December 2006 through which we sold all of our ownership interest in NuStar GP Holdings, LLC. As a result, we no longer owned any interest in NuStar Energy L.P. as of December 31, 2006. Financial information reported by NuStar Energy L.P. for the three months and nine months ended September 30, 2006 is summarized below (in millions):

	Three Months		Nine Months
	Ended		Ended
	September 30, 2006		September 30, 2006
Revenues	$	291	$	845
Operating income		55		158
Net income		41		112

Related-Party Transactions
Through December 31, 2006, we provided NuStar Energy L.P. with certain corporate functions for an annual fee as prescribed by a services agreement. Effective January 1, 2007, the services agreement was amended to provide for limited services. The amended services agreement provided for a termination date of December 31, 2010, unless we terminated the agreement earlier, in which case we were required to pay a termination fee of $13 million. In April, we notified NuStar Energy L.P. of our decision to terminate the services agreement. Accordingly, the $13 million termination fee was accrued and paid during the second quarter of 2007.

11

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

The following table summarizes the results of transactions with NuStar Energy L.P. for the three months and nine months ended September 30, 2006 (in millions):

	Three Months		Nine Months
	Ended		Ended
	September 30, 2006		September 30, 2006
Fees and expenses charged by us to NuStar Energy L.P.	$	32	$	89
Fees and expenses charged to us by NuStar Energy L.P.		69		194

6. DEBT

On February 1, 2007, we redeemed our 9.25% senior notes for $183 million, or 104.625% of stated value. These notes had a carrying amount of $187 million on the date of redemption, resulting in a gain of $4 million that was included in “other income, net” in the consolidated statement of income.

In April 2007, we repaid in full, at the scheduled maturity date, $230 million related to our 6.125% notes. Also in April 2007, we borrowed $3 billion under a 364-day term credit agreement with a financial institution to fund the accelerated share repurchase program discussed in Note 7. The term loan bore interest at LIBOR plus a margin, or an alternate base rate as defined under the term credit agreement. In May 2007, we repaid $500 million of the borrowings under the term credit agreement. The remaining balance of $2.5 billion was repaid in June 2007 using available cash and proceeds from our issuance of long-term notes described below.

On June 8, 2007, we issued $750 million of 6.125% notes due June 15, 2017 and $1.5 billion of 6.625% notes due June 15, 2037. Proceeds from the issuance of these notes totaled $2.25 billion, before deducting underwriting discounts of $18 million.

During the nine months ended September 30, 2007, we had no borrowings under our revolving credit facilities or our short-term uncommitted bank credit facilities.

7. STOCKHOLDERS’ EQUITY

Treasury Stock
During the nine months ended September 30, 2007 and 2006, we purchased 68.9 million and 30.8 million shares of our common stock at a cost of $4.8 billion and $1.8 billion, respectively. These purchases were made in connection with the administration of our employee benefit plans and the $6 billion common stock purchase program authorized by our board of directors, including the effect of the accelerated share repurchase program discussed below. During the nine months ended September 30, 2007, we issued 12.4 million shares from treasury at an average cost of $61.65 per share, and for the nine months ended September 30, 2006, we issued 13.2 million shares from treasury at an average cost of $55.29 per share, for our employee benefit plans.

12

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

Accelerated Share Repurchase Program
On April 25, 2007, our board of directors approved an amendment to our $2 billion common stock purchase program to increase the authorized purchases under the program to $6 billion. In conjunction with the increase in our common stock purchase program, we entered into an agreement with a financial institution to purchase $3 billion of our shares under an accelerated share repurchase program, and in late April 2007, 42.1 million shares were purchased under this agreement. As described in Note 6 above, the purchase of these shares was initially funded with a 364-day term credit agreement, which we subsequently replaced with longer-term financing. The cost of the shares purchased under this accelerated share repurchase program was to be adjusted at the expiration of the program, with the final purchase cost based on a discount to the average trading price of our common stock, weighted by the daily volume of shares traded, during the program period. Any adjustment to the cost could be paid in cash or stock, at our option.

The accelerated share repurchase program was completed on July 23, 2007, resulting in an additional $94 million payment by us for the shares purchased. At that time, we elected to pay this additional amount in cash. This additional cash payment was deducted from reported net income in calculating earnings per common share from continuing operations assuming dilution for the three months and nine months ended September 30, 2007.

Common Stock Dividends
On October 25, 2007, our board of directors declared a regular quarterly cash dividend of $0.12 per common share payable on December 12, 2007 to holders of record at the close of business on November 7, 2007.

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

8. EARNINGS PER COMMON SHARE

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Earnings per common share from continuing operations:
Income from continuing operations	$	848	$	1,559	$	3,998	$	4,206
Less: Preferred stock dividends		-		-		-		2
Income from continuing operations applicable to common stock	$	848	$	1,559	$	3,998	$	4,204
Weighted-average common shares outstanding		551		609		571		613
Earnings per common share from continuing operations	$	1.54	$	2.56	$	7.00	$	6.85
Earnings per common share from continuing operations – assuming dilution:
Income from continuing operations	$	848	$	1,559	$	3,998	$	4,206
Less: Cash paid in final settlement of accelerated share repurchase program		94		-		94		-
Income from continuing operations assuming dilution	$	754	$	1,559	$	3,904	$	4,206
Weighted-average common shares outstanding		551		609		571		613
Effect of dilutive securities:
Stock options		11		17		14		19
Performance awards and other benefit plans		1		1		1		1
Mandatory convertible preferred stock and other		1		1		1		3
Weighted-average common shares outstanding – assuming dilution		564		628		587		636
Earnings per common share from continuing operations – assuming dilution	$	1.34	$	2.48	$	6.66	$	6.61

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

9. STATEMENTS OF CASH FLOWS

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

	Nine Months Ended September 30,
	2007			2006
Decrease (increase) in current assets:
Restricted cash	$	—		$	(1	)
Receivables, net		(1,999	)		(20	)
Inventories		(695	)		(624	)
Income taxes receivable		32			3
Prepaid expenses and other		(88	)		(113	)
Increase (decrease) in current liabilities:
Accounts payable		1,310			597
Accrued expenses		90			(20	)
Taxes other than income taxes		(4	)		(49	)
Income taxes payable		474			98
Changes in current assets and current liabilities	$	(880	)	$	(129	)

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 long-term debt and capital lease obligations, as well as the effect of certain noncash investing and financing activities discussed below;

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

• changes in assets held for sale and liabilities related to assets held for sale prior to the sale of the Lima Refinery are reflected in the line item to which the changes relate in the table above; and

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

There were no significant noncash investing or financing activities for the nine months ended September 30, 2007.

Noncash investing activities for the nine months ended September 30, 2006 included the pre-tax recognition of $158 million of SAB 51 credits related to our investment in NuStar Energy L.P. (as discussed in Note 5). Noncash investing activities also included adjustments to property, plant and equipment, goodwill, and certain current and noncurrent assets and liabilities resulting from adjustments to the purchase price allocation related to the acquisitions of Premcor Inc. (Premcor) and Ultramar Diamond Shamrock Corporation. Noncash financing activities for the nine months ended September 30, 2006 included the conversion of 3,164,151 shares of preferred stock into 6,271,327 shares of our common stock and the recognition of a $39 million capital lease obligation and related capital lease asset pertaining to certain facilities at the Lima Refinery.

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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 Lima Refinery have been combined with the cash flows from continuing operations within each category in the consolidated statement of cash flows for each period presented. Cash provided by operating activities related to our discontinued results of operations was $260 million and $170 million for the nine months ended September 30, 2007 and 2006, respectively. Cash used in investing activities related to the Lima Refinery was $14 million and $117 million for the nine months ended September 30, 2007 and 2006, respectively.

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

	Nine Months Ended September 30,
	2007		2006
Interest paid (net of amount capitalized)	$	152	$	165
Income taxes paid (net of tax refunds received)		1,813		1,759

10. PRICE RISK MANAGEMENT ACTIVITIES

The net gain (loss) recognized in income representing the amount of hedge ineffectiveness was as follows (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Fair value hedges	$	3		$	(2	)	$	1		$	(8	)
Cash flow hedges		(17	)		2			(23	)		7

The above amounts were included in “cost of sales” in the consolidated statements of income. 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.

For cash flow hedges, gains and losses reported in “accumulated other comprehensive income” in the consolidated balance sheets are reclassified into “cost of sales” when the forecasted transactions affect income. During the nine months ended September 30, 2007, we recognized in “accumulated other comprehensive income” unrealized after-tax losses of $18 million on certain cash flow hedges, primarily related to forward sales of distillates and associated forward purchases of crude oil, with $17 million of cumulative after-tax gains on cash flow hedges remaining in “accumulated other comprehensive income” as of September 30, 2007. We expect that the deferred gains as of September 30, 2007 will be reclassified into “cost of sales” over the next nine 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 nine months ended September 30, 2007 and 2006, there were no amounts reclassified from “accumulated other comprehensive income” into income as a result of the discontinuance of cash flow hedge accounting.

11. INCOME TAXES

As discussed in Note 2, on January 1, 2007, we adopted the provisions of FIN 48. We did not recognize a significant change in our liability for uncertain tax positions as a result of our implementation of FIN 48;

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

however, certain amounts previously reported in “deferred income taxes” were reclassified to “other long-term liabilities” in the consolidated balance sheet as of January 1, 2007. In accordance with the provisions of FIN 48, prior period amounts were not reclassified. The total amount of unrecognized tax benefits as of January 1, 2007 was $179 million of which $85 million, if recognized, would impact our effective rate. Accrued liabilities for interest and penalties related to unrecognized tax benefits were $43 million as of January 1, 2007. We anticipate that any matters resolved with tax authorities within the next 12 months will not result in a material change in our financial position or results of operations. As of September 30, 2007, we remain subject to examination in the U.S. federal and various state jurisdictions for the tax years from 1999 through 2006 and Canadian federal and various provincial jurisdictions for tax years from 2001 to 2006.

12. SEGMENT INFORMATION

Segment information for our two reportable segments, refining and retail, was as follows (in millions):

	Refining		Retail		Corporate			Total
Three months ended September 30, 2007:
Operating revenues from external customers	$	21,399	$	2,300	$	-		$	23,699
Intersegment revenues		1,610		-		-			1,610
Operating income (loss)		1,259		74		(165	)		1,168
Three months ended September 30, 2006:
Operating revenues from external customers		20,995		2,243		-			23,238
Intersegment revenues		1,547		-		-			1,547
Operating income (loss)		2,313		96		(148	)		2,261
Nine months ended September 30, 2007:
Operating revenues from external customers		60,131		6,525		-			66,656
Intersegment revenues		4,573		-		-			4,573
Operating income (loss)		6,362		183		(511	)		6,034
Nine months ended September 30, 2006:
Operating revenues from external customers		62,440		6,365		-			68,805
Intersegment revenues		4,459		-		-			4,459
Operating income (loss)		6,624		163		(489	)		6,298

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

	September 30,		December 31,
	2007		2006
Refining	$	36,302	$	34,275
Retail		1,980		1,826
Corporate		3,579		1,652
Total consolidated assets	$	41,861	$	37,753

17

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

The entire balance of goodwill as of September 30, 2007 and December 31, 2006 has been included in the total assets of the refining reportable segment. Assets held for sale related to the Lima Refinery were included in the refining reportable segment as of December 31, 2006.

13. EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost related to our defined benefit plans were as follows for the three months and nine months ended September 30, 2007 and 2006 (in millions):

							Other Postretirement
	Pension Plans						Benefit Plans
	2007			2006			2007			2006
Three months ended September 30:
Components of net periodic benefit cost:
Service cost	$	23		$	23		$	3		$	3
Interest cost		18			16			7			6
Expected return on plan assets		(21	)		(14	)		-			-
Amortization of:
Prior service cost (credit)		1			1			(2	)		(2	)
Net loss		2			3			2			2
Net periodic benefit cost before special charges		23			29			10			9
Charge for special termination benefits		5			-			-			-
Net periodic benefit cost	$	28		$	29		$	10		$	9
Nine months ended September 30:
Components of net periodic benefit cost:
Service cost	$	71		$	73		$	10		$	10
Interest cost		53			48			20			18
Expected return on plan assets		(63	)		(43	)		-			-
Amortization of:
Prior service cost (credit)		2			2			(7	)		(7	)
Net loss		7			10			5			5
Net periodic benefit cost before special charges		70			90			28			26
Charge for special termination benefits		12			-			1			-
Net periodic benefit cost	$	82		$	90		$	29		$	26

Although we had only $1 million of minimum required contributions to our qualified pension plans during 2007 under the Employee Retirement Income Security Act, we contributed $43 million to our qualified plans during the nine months ended September 30, 2007. For the nine months ended September 30, 2006, we contributed $143 million to our qualified pension plans.

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

14. COMMITMENTS AND CONTINGENCIES

Accounts Receivable Sales Facility
As of September 30, 2007, we had an accounts receivable sales facility with a group of third-party financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables, which matures in August 2008. During the third quarter of 2007, we reduced the amount of eligible receivables sold to the third-party financial institutions by $900 million. As a result, as of September 30, 2007 and December 31, 2006, the amount of eligible receivables sold to the third-party financial institutions was $100 million and $1 billion, respectively.

Contingent Earn-Out Agreements
In both June 2007 and July 2006, we made previously accrued payments of $25 million related to the Delaware City Refinery contingent earn-out agreement. The 2007 payment represented the final payment under that agreement. In both January 2007 and January 2006, we made previously accrued earn-out payments of $50 million related to the acquisition of the St. Charles Refinery. In the second quarter of 2006, we made a final earn-out contingency payment of $26 million to Salomon Inc in conjunction with our acquisition of Basis Petroleum, Inc.

The following table summarizes the aggregate payments we have made through September 30, 2007 and payment limitations related to the following acquisitions (in millions):

	Aggregate
	Payments		Annual
	Made Through		Maximum		Aggregate
	September 30, 2007		Limit		Limit
St. Charles Refinery	$	150	$	50	$	175
Delaware City Refinery		50		25		50

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. Certain of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties.

Effective January 1, 2007, the Government of Aruba (GOA) enacted a turnover tax on revenues from the sale of goods produced and services rendered in Aruba. The turnover tax, which is 3% for on-island sales and services and 1% on export sales, is being assessed by the GOA on sales by our Aruba Refinery. However, due to a previous tax holiday that was granted to our Aruba Refinery by the GOA through December 31, 2010 as well as other reasons, we believe that exports by our Aruba Refinery should not be subject to this turnover tax. No amounts have been accrued on exports with respect to this turnover tax. We have commenced arbitration proceedings with the Netherlands Arbitration Institute pursuant to which we will seek to enforce our rights under the tax holiday.

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

Litigation
MTBE Litigation
As of November 1, 2007, we were named as a defendant in 82 active cases alleging liability related to MTBE contamination in groundwater. The plaintiffs are generally water providers, governmental authorities, and private water companies alleging that refiners and marketers of MTBE and gasoline containing MTBE are liable for manufacturing or distributing a defective product. We have been named in these lawsuits together with many other refining industry companies. We are being sued primarily as a refiner and marketer of MTBE and gasoline containing MTBE. We do not own or operate gasoline station facilities in most of the geographic locations in which damage is alleged to have occurred. The lawsuits generally seek individual, unquantified compensatory and punitive damages, injunctive relief, and attorneys’ fees. Although most of the cases are pending in federal court and consolidated for pre-trial proceedings in the U.S. District Court for the Southern District of New York (Multi-District Litigation Docket No. 1358,In re: Methyl-Tertiary Butyl Ether Products Liability Litigation), a recent ruling on jurisdiction from the U.S. Court of Appeals for the Second Circuit may result in a remand of many of the cases to state court. Three cases,State of New Hampshire, Riverview Water District,andCalifornia Water Services Company, have already been remanded to state courts in New Hampshire and California. We are involved in four cases that have been selected as “focus cases” for discovery and pre-trial motions. One of these, theSuffolk County Water Authoritycase, is scheduled for trial in March 2008. Activity in the “non-focus” cases is generally stayed. We believe that we have strong defenses to these claims and are vigorously defending the cases. We have recorded a loss contingency liability with respect to this matter in accordance with FASB Statement No. 5. However, due to the inherent uncertainty of litigation, we believe that it is reasonably possible (as defined in FASB Statement No. 5) that we may suffer a loss with respect to one or more of the lawsuits in excess of the amount accrued. We believe that such an outcome in any one of these lawsuits would not have a material adverse effect on our results of operations or financial position. However, we believe that an adverse result in all or a substantial number of these cases could have a material effect on our results of operations and financial position. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.

Retail Fuel Temperature Litigation
Along with several other defendants in the retail petroleum marketing business, as of November 1, 2007, we were named in 22 consumer class action lawsuits relating to fuel temperature. The complaints, filed in federal courts in several states, allege that because fuel volume increases with fuel temperature, the defendants have violated state consumer protection laws by failing to adjust the volume of fuel when the fuel temperature exceeded 60 degrees Fahrenheit. The complaints seek to certify classes of retail consumers who purchased fuel in various locations. The complaints seek an order compelling the installation of temperature correction devices as well as associated monetary relief. In June 2007, the federal lawsuits were consolidated into a multidistrict 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). We believe that we have several strong defenses to these lawsuits and intend to contest them. We have not recorded a loss contingency liability with respect to this matter, but due to the inherent uncertainty of litigation, we believe that it is reasonably possible (as defined in FASB Statement No. 5) that we may suffer a loss with respect to one or more of the lawsuits. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.

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

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

15. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

In conjunction with the acquisition of Premcor 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, 2007:

• 6.75% senior notes due February 2011,

• 6.125% senior notes due May 2011,

• 9.5% senior notes due February 2013,

• 6.75% senior notes due May 2014, and

• 7.5% senior notes due June 2015.

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

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

21

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

Condensed Consolidating Balance Sheet as of September 30, 2007
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	2,262		$	-		$	847		$	-		$	3,109
Restricted cash		23			2			6			-			31
Receivables, net		1			72			6,390			-			6,463
Inventories		-			390			4,226			-			4,616
Income taxes receivable		-			-			1			(1	)		-
Deferred income taxes		-			-			197			-			197
Prepaid expenses and other		-			7			231			-			238
Total current assets		2,286			471			11,898			(1	)		14,654
Property, plant and equipment, at cost		-			6,607			18,470			-			25,077
Accumulated depreciation		-			(366	)		(3,487	)		-			(3,853	)
Property, plant and equipment, net		-			6,241			14,983			-			21,224
Intangible assets, net		-			2			296			-			298
Goodwill		-			1,819			2,242			-			4,061
Investment in Valero Energy affiliates		7,636			1,006			1,288			(9,930	)		-
Long-term notes receivable from affiliates		16,708			-			-			(16,708	)		-
Deferred charges and other assets, net		215			369			1,240			(200	)		1,624
Total assets	$	26,845		$	9,908		$	31,947		$	(26,839	)	$	41,861
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	57		$	-		$	3		$	-		$	60
Accounts payable		68			220			7,857			-			8,145
Accrued expenses		164			51			393			-			608
Taxes other than income taxes		-			23			589			-			612
Income taxes payable		407			88			-			(1	)		494
Deferred income taxes		51			272			-			-			323
Total current liabilities		747			654			8,842			(1	)		10,242
Long-term debt and capital lease obligations, less current portion		5,526			1,287			41			-			6,854
Long-term notes payable to affiliates		-			6,489			10,219			(16,708	)		-
Deferred income taxes		806			-			3,335			(200	)		3,941
Other long-term liabilities		798			190			868			-			1,856
Stockholders’ equity:
Common stock		6			-			2			(2	)		6
Additional paid-in capital		7,366			100			3,395			(3,495	)		7,366
Treasury stock		(5,308	)		-			-			-			(5,308	)
Retained earnings		16,413			1,187			5,238			(6,425	)		16,413
Accumulated other comprehensive income		491			1			7			(8	)		491
Total stockholders’ equity		18,968			1,288			8,642			(9,930	)		18,968
Total liabilities and stockholders’ equity	$	26,845		$	9,908		$	31,947		$	(26,839	)	$	41,861

22

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

Condensed Consolidating Balance Sheet as of December 31, 2006
(in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	712		$	-		$	878		$	-		$	1,590
Restricted cash		22			2			7			-			31
Receivables, net		1			76			4,307			-			4,384
Inventories		-			377			3,602			-			3,979
Income taxes receivable		-			5			32			(5	)		32
Deferred income taxes		-			-			143			-			143
Prepaid expenses and other		-			12			133			-			145
Assets held for sale		-			977			550			-			1,527
Total current assets		735			1,449			9,652			(5	)		11,831
Property, plant and equipment, at cost		-			6,481			16,940			-			23,421
Accumulated depreciation		-			(231	)		(3,010	)		-			(3,241	)
Property, plant and equipment, net		-			6,250			13,930			-			20,180
Intangible assets, net		-			3			300			-			303
Goodwill		-			1,826			2,277			-			4,103
Investment in Valero Energy affiliates		2,114			705			101			(2,920	)		-
Long-term notes receivable from affiliates		20,920			-			-			(20,920	)		-
Deferred income taxes		-			111			-			(111	)		-
Deferred charges and other assets, net		196			184			956			-			1,336
Total assets	$	23,965		$	10,528		$	27,216		$	(23,956	)	$	37,753
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	285		$	187		$	3		$	-		$	475
Accounts payable		80			281			6,480			-			6,841
Accrued expenses		76			76			355			-			507
Taxes other than income taxes		-			19			565			-			584
Income taxes payable		21			-			7			(5	)		23
Deferred income taxes		91			272			-			-			363
Liabilities related to assets held for sale		-			67			-			-			67
Total current liabilities		553			902			7,410			(5	)		8,860
Long-term debt and capital lease obligations, less current portion		3,281			1,295			43			-			4,619
Long-term notes payable to affiliates		-			8,003			12,917			(20,920	)		-
Deferred income taxes		868			-			3,290			(111	)		4,047
Other long-term liabilities		658			227			737			-			1,622
Stockholders’ equity:
Common stock		6			-			2			(2	)		6
Additional paid-in capital		7,779			100			1,458			(1,558	)		7,779
Treasury stock		(1,396	)		-			-			-			(1,396	)
Retained earnings		11,951			-			1,322			(1,322	)		11,951
Accumulated other comprehensive income		265			1			37			(38	)		265
Total stockholders’ equity		18,605			101			2,819			(2,920	)		18,605
Total liabilities and stockholders’ equity	$	23,965		$	10,528		$	27,216		$	(23,956	)	$	37,753

23

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

Condensed Consolidating Statement of Income for the Three Months Ended September 30, 2007
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	-		$	6,008		$	24,546		$	(6,855	)	$	23,699
Costs and expenses:
Cost of sales		-			5,654			22,011			(6,855	)		20,810
Refining operating expenses		-			236			800			-			1,036
Retail selling expenses		-			-			190			-			190
General and administrative expenses		(6	)		20			138			-			152
Depreciation and amortization expense		-			77			266			-			343
Total costs and expenses		(6	)		5,987			23,405			(6,855	)		22,531
Operating income		6			21			1,141			-			1,168
Equity in earnings of subsidiaries		1,017			150			487			(1,654	)		-
Other income (expense), net		432			(20	)		193			(460	)		145
Interest and debt expense:
Incurred		(153	)		(137	)		(318	)		460			(148	)
Capitalized		-			2			23			-			25
Income from continuing operations before income tax expense (benefit)		1,302			16			1,526			(1,654	)		1,190
Income tax expense (benefit) (1)		28			(45	)		359			-			342
Income from continuing operations		1,274			61			1,167			(1,654	)		848
Income from discontinued operations, net of income tax expense		-			426			-			-			426
Net income	$	1,274		$	487		$	1,167		$	(1,654	)	$	1,274

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

24

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

Condensed Consolidating Statement of Income for the Three Months Ended September 30, 2006
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	-		$	6,335		$	22,834		$	(5,931	)	$	23,238
Costs and expenses:
Cost of sales		-			6,046			19,367			(5,931	)		19,482
Refining operating expenses		-			182			707			-			889
Retail selling expenses		-			-			185			-			185
General and administrative expenses		-			-			136			-			136
Depreciation and amortization expense		-			59			226			-			285
Total costs and expenses		-			6,287			20,621			(5,931	)		20,977
Operating income		-			48			2,213			-			2,261
Equity in earnings of subsidiaries		1,429			353			294			(2,076	)		-
Equity in earnings of NuStar Energy L.P.		-			-			13			-			13
Other income (expense), net		320			(82	)		365			(460	)		143
Interest and debt expense:
Incurred		(101	)		(152	)		(298	)		460			(91	)
Capitalized		-			18			27			-			45
Minority interest in net income of consolidated subsidiary		-			-			(4	)		-			(4	)
Income from continuing operations before income tax expense (benefit)		1,648			185			2,610			(2,076	)		2,367
Income tax expense (benefit) (1)		45			(65	)		828			-			808
Income from continuing operations		1,603			250			1,782			(2,076	)		1,559
Income from discontinued operations, net of income tax expense		-			44			-			-			44
Net income	$	1,603		$	294		$	1,782		$	(2,076	)	$	1,603

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

25

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

Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2007
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	-		$	16,960		$	65,812		$	(16,116	)	$	66,656
Costs and expenses:
Cost of sales		-			15,051			56,695			(16,116	)		55,630
Refining operating expenses		-			644			2,311			-			2,955
Retail selling expenses		-			-			561			-			561
General and administrative expenses		(6	)		27			453			-			474
Depreciation and amortization expense		-			227			775			-			1,002
Total costs and expenses		(6	)		15,949			60,795			(16,116	)		60,622
Operating income		6			1,011			5,017			-			6,034
Equity in earnings of subsidiaries		4,039			492			1,190			(5,721	)		-
Other income (expense), net		1,131			(151	)		629			(1,452	)		157
Interest and debt expense:
Incurred		(367	)		(442	)		(990	)		1,452			(347	)
Capitalized		-			4			79			-			83
Income from continuing operations before income tax expense		4,809			914			5,925			(5,721	)		5,927
Income tax expense (1)		142			214			1,573			-			1,929
Income from continuing operations		4,667			700			4,352			(5,721	)		3,998
Income from discontinued operations, net of income tax expense		-			490			179			-			669
Net income	$	4,667		$	1,190		$	4,531		$	(5,721	)	$	4,667

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

26

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

Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2006
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Operating revenues	$	-		$	18,220		$	67,859		$	(17,274	)	$	68,805
Costs and expenses:
Cost of sales		-			16,987			58,294			(17,274	)		58,007
Refining operating expenses		-			558			2,126			-			2,684
Retail selling expenses		-			-			539			-			539
General and administrative expenses		2			26			430			-			458
Depreciation and amortization expense		-			187			632			-			819
Total costs and expenses		2			17,758			62,021			(17,274	)		62,507
													��
Operating income (loss)		(2	)		462			5,838			-			6,298
Equity in earnings of subsidiaries		3,899			681			782			(5,362	)		-
Equity in earnings of NuStar Energy L.P.		-			-			35			-			35
Other income (expense), net		1,041			(86	)		943			(1,760	)		138
Interest and debt expense:
Incurred		(379	)		(548	)		(1,113	)		1,760			(280	)
Capitalized		-			46			80			-			126
Minority interest in net income of consolidated subsidiary		-			-			(4	)		-			(4	)
Income from continuing operations before income tax expense (benefit)		4,559			555			6,561			(5,362	)		6,313
Income tax expense (benefit) (1)		210			(84	)		1,981			-			2,107
Income from continuing operations		4,349			639			4,580			(5,362	)		4,206
Income from discontinued operations, net of income tax expense		-			143			-			-			143
Net income		4,349			782			4,580			(5,362	)		4,349
Preferred stock dividends		2			-			-			-			2
Net income applicable to common stock	$	4,347		$	782		$	4,580		$	(5,362	)	$	4,347

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

27

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, 2007
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG (1)			Subsidiaries (1)			Eliminations			Consolidated
Net cash provided by operating activities	$	1,049		$	69		$	2,888		$	-		$	4,006
Cash flows from investing activities:
Capital expenditures		-			(218	)		(1,335	)		-			(1,553	)
Deferred turnaround and catalyst costs		-			(44	)		(294	)		-			(338	)
Investment in Cameron Highway Oil Pipeline Company, net		-			-			(212	)		-			(212	)
Proceeds from sale of Lima Refinery		-			1,873			555			-			2,428
Contingent payments in connection with acquisitions		-			(25	)		(50	)		-			(75	)
Investments in subsidiaries		(2,742	)		(58	)		-			2,800			-
Return of investment		1,305			-			3			(1,308	)		-
Net intercompany loan repayments		4,538			-			-			(4,538	)		-
Other investing activities, net		-			4			14			-			18
Net cash provided by (used in) investing activities		3,101			1,532			(1,319	)		(3,046	)		268
Cash flows from financing activities:
Long-term notes:
Borrowings		2,245			-			-			-			2,245
Repayments		(230	)		(183	)		-			-			(413	)
Bank credit agreements:
Borrowings		3,000			-			-			-			3,000
Repayments		(3,000	)		-			-			-			(3,000	)
Purchase of treasury stock		(4,751	)		-			-			-			(4,751	)
Benefit from tax deduction in excess of recognized stock-based compensation cost		231			-			-			-			231
Dividends to parent		-			(3	)		(1,305	)		1,308			-
Capital contributions from parent		-			-			2,800			(2,800	)		-
Net intercompany loan repayments		-			(1,415	)		(3,123	)		4,538			-
Other financing activities, net		(95	)		-			(3	)		-			(98	)
Net cash used in financing activities		(2,600	)		(1,601	)		(1,631	)		3,046			(2,786	)
Effect of foreign exchange rate changes on cash		-			-			31			-			31
Net increase (decrease) in cash and temporary cash investments		1,550			-			(31	)		-			1,519
Cash and temporary cash investments at beginning of period		712			-			878			-			1,590
Cash and temporary cash investments at end of period	$	2,262		$	-		$	847		$	-		$	3,109

(1) The information presented herein excludes a $686 million noncash capital contribution of property and other assets, net of certain liabilities, from PRG to Lima Refining Company (included in “Other Non-Guarantor Subsidiaries”) on April 1, 2007, in anticipation of the sale of the Lima Refinery as discussed in Note 3.

28

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, 2006
(unaudited, in millions)

	Valero						Other Non-
	Energy						Guarantor
	Corporation			PRG			Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	823		$	349		$	3,924		$	-		$	5,096
Cash flows from investing activities:
Capital expenditures		-			(796	)		(1,535	)		-			(2,331	)
Deferred turnaround and catalyst costs		-			(146	)		(318	)		-			(464	)
Contingent payments in connection with acquisitions		-			(25	)		(76	)		-			(101	)
Proceeds from sale of interest in NuStar GP Holdings, LLC		-			-			355			-			355
Net intercompany loan repayments		1,755			-			-			(1,755	)		-
Other investing activities, net		-			(3	)		32			-			29
Net cash provided by (used in) investing activities		1,755			(970	)		(1,542	)		(1,755	)		(2,512	)
Cash flows from financing activities:
Long-term note repayments		(221	)		(28	)		-			-			(249	)
Bank credit agreements:
Borrowings		8			-			699			-			707
Repayments		(8	)		-			(698	)		-			(706	)
Termination of interest rate swaps		(54	)		-			-			-			(54	)
Purchase of treasury stock		(1,818	)		-			-			-			(1,818	)
Benefit from tax deduction in excess of recognized stock-based compensation cost		160			-			-			-			160
Net intercompany borrowings (repayments)		-			644			(2,399	)		1,755			-
Other financing activities, net		(35	)		-			(2	)		-			(37	)
Net cash provided by (used in) financing activities		(1,968	)		616			(2,400	)		1,755			(1,997	)
Effect of foreign exchange rate changes on cash		-			-			6			-			6
Net increase (decrease) in cash and temporary cash investments		610			(5	)		(12	)		-			593
Cash and temporary cash investments at beginning of period		11			5			420			-			436
Cash and temporary cash investments at end of period	$	621		$	-		$	408		$	-		$	1,029

29

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

FORWARD-LOOKING STATEMENTS

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

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

• anticipated levels of crude oil and refined product inventories;

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

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

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

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

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

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

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

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

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

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

• the level of consumer demand, including seasonal fluctuations;

• refinery overcapacity or undercapacity;

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

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

30

• 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;

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

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

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

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

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

• overall economic conditions.

Any one of these factors, or a combination of these factors, could materially affect our future results of operations and whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.

All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

31

OVERVIEW

In this overview, we describe some of the primary factors that we believe affected our operations in the third quarter and first nine months of 2007. Our profitability is substantially determined by the spread between the price of refined products and the price of crude oil, referred to as the “refined product margin.” Gasoline and distillate margins in the third quarter of 2007 were comparable to such margins in the third quarter of 2006 in all regions other than the West Coast region where such margins were significantly weaker. Compared to the second quarter of 2007, gasoline margins were significantly lower in the third quarter of 2007 due to the seasonal transition to lower gasoline demand and less restrictive gasoline specifications.

Since approximately 65% of our total crude oil throughput represents sour crude oil and acidic sweet crude oil feedstocks that are purchased at prices less than sweet crude oil, our profitability is also significantly affected by the spread between sweet crude oil and sour crude oil prices, referred to as the “sour crude oil differential.” Sour crude oil differentials relative to WTI crude oil for the third quarter of 2007 improved somewhat compared to second quarter 2007 levels but were significantly lower than the strong differentials in the third quarter of 2006. However, the sour crude oil differentials relative to light, sweet crude oils other than WTI in the third quarter of 2007 were comparable to those experienced in the third quarter of 2006.

On February 16, 2007, our McKee Refinery was shut down due to a fire originating in its propane deasphalting unit, which reduced operating income by approximately $325 million in the first nine months of 2007. The refinery recommenced operations on April 12 at a reduced throughput rate, with run rates by the end of September having increased to near full capacity. During the third quarter of 2007, operating results were unfavorably affected by the impact of Hurricane Humberto on the Port Arthur Refinery’s operations as well as operational issues at the Port Arthur, Aruba, and Ardmore Refineries.

Effective July 1, 2007, we consummated the sale of our refinery in Lima, Ohio to Husky Refining Company (Husky), a wholly owned subsidiary of Husky Energy Inc. The sales price was approximately $2.4 billion, including approximately $550 million from the sale of working capital to Husky primarily related to the sale of inventory by our marketing and supply subsidiary. The sale resulted in a pre-tax gain of $827 million. During the third quarter of 2007, we also recognized a pre-tax gain of $91 million related to a foreign currency exchange rate gain resulting from the repayment of a loan by a foreign subsidiary, and we made a $94 million cash payment in final settlement of an accelerated share repurchase program entered into in the second quarter of 2007 under which we purchased 42.1 million shares of our common stock.

We reported income from continuing operations of $848 million, or $1.34 per share, for the third quarter of 2007 compared to $1.6 billion, or $2.48 per share, for the third quarter of 2006. Income from continuing operations for the first nine months of 2007 was $4.0 billion, or $6.66 per share, compared to $4.2 billion, or $6.61 per share, for the first nine months of 2006. During the first nine months of 2007, we generated $4.0 billion of net cash from operating activities and purchased $4.8 billion of our common stock, including $3.1 billion under the accelerated share repurchase program discussed above.

32

RESULTS OF OPERATIONS

Third Quarter 2007 Compared to Third Quarter 2006

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

	Three Months Ended September 30,
	2007			2006 (a)			Change
Operating revenues (b)	$	23,699		$	23,238		$	461
Costs and expenses:
Cost of sales (b)		20,810			19,482			1,328
Refining operating expenses		1,036			889			147
Retail selling expenses (b)		190			185			5
General and administrative expenses		152			136			16
Depreciation and amortization expense:
Refining		307			252			55
Retail		23			21			2
Corporate		13			12			1
Total costs and expenses		22,531			20,977			1,554
Operating income		1,168			2,261			(1,093	)
Equity in earnings of NuStar Energy L.P. (c)		-			13			(13	)
Other income, net		145			143			2
Interest and debt expense:
Incurred		(148	)		(91	)		(57	)
Capitalized		25			45			(20	)
Minority interest in net income of consolidated subsidiary (c)		-			(4	)		4
Income from continuing operations before income tax expense		1,190			2,367			(1,177	)
Income tax expense		342			808			(466	)
Income from continuing operations		848			1,559			(711	)
Income from discontinued operations, net of income tax expense (a)		426			44			382
Net income	$	1,274		$	1,603		$	(329	)
Earnings per common share – assuming dilution:
Continuing operations	$	1.34		$	2.48		$	(1.14	)
Discontinued operations		0.75			0.07			0.68
Total	$	2.09		$	2.55		$	(0.46	)

See the footnote references on page 36.

33

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

	Three Months Ended September 30,
	2007			2006			Change
Refining (a):
Operating income	$	1,259		$	2,313		$	(1,054	)
Throughput margin per barrel (d)	$	9.94		$	13.17		$	(3.23	)
Operating costs per barrel:
Refining operating expenses	$	3.96		$	3.39		$	0.57
Depreciation and amortization		1.17			0.96			0.21
Total operating costs per barrel	$	5.13		$	4.35		$	0.78
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		594			619			(25	)
Medium/light sour crude		663			637			26
Acidic sweet crude		79			83			(4	)
Sweet crude		760			784			(24	)
Residuals		265			308			(43	)
Other feedstocks		181			134			47
Total feedstocks		2,542			2,565			(23	)
Blendstocks and other		302			287			15
Total throughput volumes		2,844			2,852			(8	)
Yields (thousand barrels per day):
Gasolines and blendstocks		1,324			1,369			(45	)
Distillates		932			911			21
Petrochemicals		84			79			5
Other products (e)		495			488			7
Total yields		2,835			2,847			(12	)
Retail – U.S.:
Operating income	$	54		$	80		$	(26	)
Company-operated fuel sites (average)		956			976			(20	)
Fuel volumes (gallons per day per site)		5,068			5,012			56
Fuel margin per gallon	$	0.197		$	0.275		$	(0.078	)
Merchandise sales	$	272		$	255		$	17
Merchandise margin (percentage of sales)		29.7	%		29.3	%		0.4	%
Margin on miscellaneous sales (b)	$	26		$	21		$	5
Retail selling expenses (b)	$	125		$	126		$	(1	)
Depreciation and amortization expense	$	15		$	15		$	-
Retail – Canada:
Operating income	$	20		$	16		$	4
Fuel volumes (thousand gallons per day)		3,180			3,136			44
Fuel margin per gallon	$	0.238		$	0.209		$	0.029
Merchandise sales	$	53		$	46		$	7
Merchandise margin (percentage of sales)		26.9	%		27.0	%		(0.1	)%
Margin on miscellaneous sales	$	9		$	9		$	-
Retail selling expenses	$	65		$	59		$	6
Depreciation and amortization expense	$	8		$	6		$	2

See the footnote references on page 36.

34

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

	Three Months Ended September 30,
	2007		2006		Change
Gulf Coast:
Operating income	$	763	$	1,377	$	(614	)
Throughput volumes (thousand barrels per day)		1,527		1,530		(3	)
Throughput margin per barrel (d)	$	10.49	$	13.92	$	(3.43	)
Operating costs per barrel:
Refining operating expenses	$	3.98	$	3.27	$	0.71
Depreciation and amortization		1.08		0.86		0.22
Total operating costs per barrel	$	5.06	$	4.13	$	0.93
Mid-Continent (a):
Operating income	$	233	$	364	$	(131	)
Throughput volumes (thousand barrels per day)		445		426		19
Throughput margin per barrel (d)	$	10.35	$	13.52	$	(3.17	)
Operating costs per barrel:
Refining operating expenses	$	3.52	$	3.28	$	0.24
Depreciation and amortization		1.15		0.97		0.18
Total operating costs per barrel	$	4.67	$	4.25	$	0.42
Northeast:
Operating income	$	147	$	311	$	(164	)
Throughput volumes (thousand barrels per day)		566		583		(17	)
Throughput margin per barrel (d)	$	8.21	$	10.61	$	(2.40	)
Operating costs per barrel:
Refining operating expenses	$	4.11	$	3.72	$	0.39
Depreciation and amortization		1.27		1.09		0.18
Total operating costs per barrel	$	5.38	$	4.81	$	0.57
West Coast:
Operating income	$	116	$	261	$	(145	)
Throughput volumes (thousand barrels per day)		306		313		(7	)
Throughput margin per barrel (d)	$	9.82	$	13.78	$	(3.96	)
Operating costs per barrel:
Refining operating expenses	$	4.24	$	3.49	$	0.75
Depreciation and amortization		1.45		1.23		0.22
Total operating costs per barrel	$	5.69	$	4.72	$	0.97

See the footnote references on page 36.

35

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

	Three Months Ended September 30,
	2007			2006		Change
Feedstocks:
West Texas Intermediate (WTI) crude oil	$	75.48		$	70.37	$	5.11
WTI less sour crude oil at U.S. Gulf Coast (h)		3.00			6.14		(3.14	)
WTI less Mars crude oil		5.93			7.50		(1.57	)
WTI less Alaska North Slope (ANS) crude oil		(1.01	)		1.43		(2.44	)
WTI less Maya crude oil		12.42			14.87		(2.45	)
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		12.20			12.00		0.20
No. 2 fuel oil less WTI		10.82			8.99		1.83
Ultra-low-sulfur diesel less WTI		16.23			17.07		(0.84	)
Propylene less WTI		8.75			13.08		(4.33	)
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		20.17			15.18		4.99
Low-sulfur diesel less WTI		22.41			22.89		(0.48	)
U.S. Northeast:
Conventional 87 gasoline less WTI		11.72			11.83		(0.11	)
No. 2 fuel oil less WTI		11.72			7.96		3.76
Lube oils less WTI		43.81			57.85		(14.04	)
U.S. West Coast:
CARBOB 87 gasoline less ANS		14.22			20.15		(5.93	)
CARB diesel less ANS		17.86			21.57		(3.71	)

The following notes relate to references on pages 33 through 36.

(a)	Effective July 1, 2007, we sold our Lima Refinery to Husky. Therefore, the results of operations of the Lima Refinery for the three months ended September 30, 2006 are reported as discontinued operations, and all refining operating highlights, both consolidated and for the Mid-Continent region, exclude the Lima Refinery for the three months ended September 30, 2006. The sale resulted in a pre-tax gain of $827 million ($426 million after tax) which is included in “Income from discontinued operations, net of income tax expense” for the three months ended September 30, 2007.
(b)	Certain amounts previously reported in 2006 for operating revenues, cost of sales, retail selling expenses, and margin on miscellaneous sales have been reclassified for comparability with amounts reported in 2007.
(c)	On December 22, 2006, we sold our remaining ownership interest in NuStar GP Holdings, LLC (formerly Valero GP Holdings, LLC), which indirectly owned the general partner interest, the incentive distribution rights, and a 21.4% limited partner interest in NuStar Energy L.P. (formerly Valero L.P.). As a result, the financial highlights reflect no equity in earnings of NuStar Energy L.P. or minority interest in net income of consolidated subsidiary subsequent to December 21, 2006.
(d)	Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.
(e)	Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
(f)	The regions reflected herein contain the following refineries: the Gulf Coast refining region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, Krotz Springs, St. Charles, Aruba, and Port Arthur Refineries; the Mid-Continent refining region includes the McKee, Ardmore, and Memphis Refineries; the Northeast refining region includes the Quebec City, Paulsboro, and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.
(g)	The average market reference prices and differentials, with the exception of the propylene and lube oil differentials, are based on posted prices from Platts Oilgram. The propylene differential is based on posted propylene prices in Chemical Market Associates, Inc. and the lube oil differential is based on Exxon Mobil Corporation postings provided by Independent Commodity Information Services-London Oil Reports. The average market reference prices and differentials are presented to provide users of the consolidated financial statements with economic indicators that significantly affect our operations and profitability.
(h)	The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.

36

General

Operating revenues increased 2% for the third quarter of 2007 compared to the third quarter of 2006 primarily as a result of higher refined product prices between the two periods. Operating income of $1.2 billion and income from continuing operations of $848 million for the three months ended September 30, 2007 decreased approximately 48% and 46%, respectively, from the corresponding amounts in the third quarter of 2006 primarily due to a $1.1 billion decrease in refining segment operating income. The refining segment operating income and income from continuing operations exclude the operations of the Lima Refinery which are classified as discontinued operations due to our sale of that refinery as discussed in Note 3 of Condensed Notes to Consolidated Financial Statements.

Refining

Operating income for our refining segment decreased 46% from the third quarter of 2006 to $1.3 billion for the third quarter of 2007, resulting mainly from a 25% decrease in throughput margin per barrel combined with a $202 million increase in refining operating expenses (including depreciation and amortization expense).

Total refining throughput margins for the third quarter of 2007 compared to the third quarter of 2006 were impacted by the following factors:

• Feedstock costs in the third quarter of 2007 were significantly higher than such costs in the third quarter of 2006 as sour crude oil feedstock prices increased more than the price of WTI crude oil and other light, sweet crude oils priced at a significant premium to WTI in the third quarter of 2007.

• Overall gasoline and distillate margins were essentially unchanged in the third quarter of 2007 compared to the third quarter of 2006, as lower margins in the West Coast region were offset by higher margins in the other refining regions. Refined product margins for the third quarter of 2007 were basically unchanged from the third quarter of 2006 due to comparable demand and production levels in the two periods.

• Margins on other refined products such as asphalt, No. 6 fuel oil, propylene, and lube oils decreased in the third quarter of 2007 compared to the third quarter of 2006 as prices for these products did not increase as much as prices for crude oil.

• During the third quarter of 2007, operating results were unfavorably affected by the impact of Hurricane Humberto on the Port Arthur Refinery’s operations as well as operational issues at the Port Arthur, Aruba, and Ardmore Refineries.

Refining operating expenses, excluding depreciation and amortization expense, were 17% higher for the quarter ended September 30, 2007 compared to the quarter ended September 30, 2006 due primarily to increases in employee compensation and related benefits and maintenance expense, as well as increased accruals for sales and use taxes. Refining depreciation and amortization expense increased 22% from the third quarter of 2006 to the third quarter of 2007 primarily due to the implementation of new capital projects and increased turnaround and catalyst amortization.

Retail

Retail operating income of $74 million for the quarter ended September 30, 2007 was approximately 23% lower than the $96 million reported for the quarter ended September 30, 2006. This decrease in operating income was mainly attributable to an approximate $0.08 per gallon decrease in average fuel margins in our U.S. retail operations.

37

Corporate Expenses and Other

General and administrative expenses, including corporate depreciation and amortization expense, increased $17 million from the third quarter of 2006 to the third quarter of 2007. This increase was primarily due to an increase in variable compensation expense.

Equity in earnings of NuStar Energy L.P. is not reflected in the third quarter of 2007 due to the sale of our remaining ownership interest in NuStar GP Holdings, LLC in December 2006.

“Other income, net” for the third quarter of 2007 included a $91 million pre-tax gain related to a foreign currency exchange rate gain resulting from the repayment of a loan by a foreign subsidiary and increased interest income related to our significantly higher cash balance during 2007. “Other income, net” for the third quarter of 2006 included a pre-tax gain of $132 million related to the sale of 40.6% of our ownership interest in NuStar GP Holdings, LLC in July 2006.

Interest and debt expense increased primarily due to the issuance of $2.25 billion of notes in June 2007 to fund the accelerated share repurchase program, increased interest on tax liabilities, and reduced capitalized interest due to a reduced balance of capital projects under construction.

Income tax expense decreased $466 million from the third quarter of 2006 to the third quarter of 2007 mainly as a result of lower operating income.

Income from discontinued operations, net of income tax expense, for the third quarter of 2007 represents the after-tax gain on the sale of our Lima Refinery effective July 1, 2007. The amount for the third quarter of 2006 reflects the income from operations of the Lima Refinery during that period.

38

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

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

	Nine Months Ended September 30,
	2007 (a)			2006 (a)			Change
Operating revenues (b)	$	66,656		$	68,805		$	(2,149	)
Costs and expenses:
Cost of sales (b)		55,630			58,007			(2,377	)
Refining operating expenses		2,955			2,684			271
Retail selling expenses (b)		561			539			22
General and administrative expenses		474			458			16
Depreciation and amortization expense:
Refining		902			726			176
Retail		63			62			1
Corporate		37			31			6
Total costs and expenses		60,622			62,507			(1,885	)
Operating income		6,034			6,298			(264	)
Equity in earnings of NuStar Energy L.P. (c)		-			35			(35	)
Other income, net		157			138			19
Interest and debt expense:
Incurred		(347	)		(280	)		(67	)
Capitalized		83			126			(43	)
Minority interest in net income of consolidated subsidiary (c)		-			(4	)		4
Income from continuing operations before income tax expense		5,927			6,313			(386	)
Income tax expense		1,929			2,107			(178	)
Income from continuing operations		3,998			4,206			(208	)
Income from discontinued operations, net of income tax expense		669			143			526
Net income		4,667			4,349			318
Preferred stock dividends		-			2			(2	)
Net income applicable to common stock	$	4,667		$	4,347		$	320
Earnings per common share – assuming dilution:
Continuing operations	$	6.66		$	6.61		$	0.05
Discontinued operations		1.14			0.22			0.92
Total	$	7.80		$	6.83		$	0.97

See the footnote references on page 42.

39

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

	Nine Months Ended September 30,
	2007			2006			Change
Refining (a):
Operating income	$	6,362		$	6,624		$	(262	)
Throughput margin per barrel (d)	$	13.39		$	13.07		$	0.32
Operating costs per barrel:
Refining operating expenses	$	3.87		$	3.50		$	0.37
Depreciation and amortization		1.18			0.94			0.24
Total operating costs per barrel	$	5.05		$	4.44		$	0.61
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		633			685			(52	)
Medium/light sour crude		643			611			32
Acidic sweet crude		83			67			16
Sweet crude		728			753			(25	)
Residuals		261			247			14
Other feedstocks		161			155			6
Total feedstocks		2,509			2,518			(9	)
Blendstocks and other		286			294			(8	)
Total throughput volumes		2,795			2,812			(17	)
Yields (thousand barrels per day):
Gasolines and blendstocks		1,283			1,347			(64	)
Distillates		919			884			35
Petrochemicals		83			78			5
Other products (e)		507			500			7
Total yields		2,792			2,809			(17	)
Retail – U.S.:
Operating income	$	115		$	104		$	11
Company-operated fuel sites (average)		959			987			(28	)
Fuel volumes (gallons per day per site)		5,019			4,937			82
Fuel margin per gallon	$	0.174		$	0.174		$	-
Merchandise sales	$	774		$	725		$	49
Merchandise margin (percentage of sales)		29.9	%		29.8	%		0.1	%
Margin on miscellaneous sales (b)	$	75		$	63		$	12
Retail selling expenses (b)	$	377		$	365		$	12
Depreciation and amortization expense	$	42		$	43		$	(1	)
Retail – Canada:
Operating income	$	68		$	59		$	9
Fuel volumes (thousand gallons per day)		3,231			3,178			53
Fuel margin per gallon	$	0.235		$	0.224		$	0.011
Merchandise sales	$	137		$	125		$	12
Merchandise margin (percentage of sales)		28.1	%		27.6	%		0.5	%
Margin on miscellaneous sales	$	27		$	24		$	3
Retail selling expenses	$	184		$	174		$	10
Depreciation and amortization expense	$	21		$	19		$	2

See the footnote references on page 42.

40

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

	Nine Months Ended September 30,
	2007		2006		Change
Gulf Coast:
Operating income	$	3,781	$	4,095	$	(314	)
Throughput volumes (thousand barrels per day)		1,532		1,543		(11	)
Throughput margin per barrel (d)	$	13.80	$	13.79	$	0.01
Operating costs per barrel:
Refining operating expenses	$	3.69	$	3.24	$	0.45
Depreciation and amortization		1.06		0.83		0.23
Total operating costs per barrel	$	4.75	$	4.07	$	0.68
Mid-Continent (a):
Operating income	$	807	$	887	$	(80	)
Throughput volumes (thousand barrels per day)		391		403		(12	)
Throughput margin per barrel (d)	$	13.10	$	12.36	$	0.74
Operating costs per barrel:
Refining operating expenses	$	4.17	$	3.34	$	0.83
Depreciation and amortization		1.36		0.97		0.39
Total operating costs per barrel	$	5.53	$	4.31	$	1.22
Northeast:
Operating income	$	959	$	781	$	178
Throughput volumes (thousand barrels per day)		572		560		12
Throughput margin per barrel (d)	$	11.22	$	10.24	$	0.98
Operating costs per barrel:
Refining operating expenses	$	3.83	$	4.04	$	(0.21	)
Depreciation and amortization		1.25		1.09		0.16
Total operating costs per barrel	$	5.08	$	5.13	$	(0.05	)
West Coast:
Operating income	$	815	$	861	$	(46	)
Throughput volumes (thousand barrels per day)		300		306		(6	)
Throughput margin per barrel (d)	$	15.84	$	15.56	$	0.28
Operating costs per barrel:
Refining operating expenses	$	4.48	$	3.98	$	0.50
Depreciation and amortization		1.42		1.26		0.16
Total operating costs per barrel	$	5.90	$	5.24	$	0.66

See the footnote references on page 42.

41

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

	Nine Months Ended September 30,
	2007		2006		Change
Feedstocks:
WTI crude oil	$	66.12	$	68.02	$	(1.90	)
WTI less sour crude oil at U.S. Gulf Coast (h)		4.00		7.12		(3.12	)
WTI less Mars crude oil		4.52		7.29		(2.77	)
WTI less ANS crude oil		0.15		1.82		(1.67	)
WTI less Maya crude oil		11.55		15.39		(3.84	)
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		17.12		13.34		3.78
No. 2 fuel oil less WTI		11.86		9.87		1.99
Ultra-low-sulfur diesel less WTI (i)		18.61		N.A.		N.A.
Propylene less WTI		13.88		10.25		3.63
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		22.13		14.10		8.03
Low-sulfur diesel less WTI		22.78		18.96		3.82
U.S. Northeast:
Conventional 87 gasoline less WTI		16.63		11.84		4.79
No. 2 fuel oil less WTI		12.83		9.57		3.26
Lube oils less WTI		53.62		51.53		2.09
U.S. West Coast:
CARBOB 87 gasoline less ANS		27.18		22.82		4.36
CARB diesel less ANS		23.52		23.56		(0.04	)

The following notes relate to references on pages 39 through 42.

(a)	Effective July 1, 2007, we sold our Lima Refinery to Husky. Therefore, the results of operations of the Lima Refinery prior to its sale are reported as discontinued operations and all refining operating highlights, both consolidated and for the Mid-Continent region, exclude the Lima Refinery. The sale resulted in a pre-tax gain of $827 million ($426 million after tax) which is included in “Income from discontinued operations, net of income tax expense” for the nine months ended September 30, 2007.
(b)	Certain amounts previously reported in 2006 for operating revenues, cost of sales, retail selling expenses, and margin on miscellaneous sales have been reclassified for comparability with amounts reported in 2007.
(c)	On December 22, 2006, we sold our remaining ownership interest in NuStar GP Holdings, LLC (formerly Valero GP Holdings, LLC), which indirectly owned the general partner interest, the incentive distribution rights, and a 21.4% limited partner interest in NuStar Energy L.P. (formerly Valero L.P.). As a result, the financial highlights reflect no equity in earnings of NuStar Energy L.P. or minority interest in net income of consolidated subsidiary subsequent to December 21, 2006.
(d)	Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.
(e)	Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
(f)	The regions reflected herein contain the following refineries: the Gulf Coast refining region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, Krotz Springs, St. Charles, Aruba, and Port Arthur Refineries; the Mid-Continent refining region includes the McKee, Ardmore, and Memphis Refineries; the Northeast refining region includes the Quebec City, Paulsboro, and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.
(g)	The average market reference prices and differentials, with the exception of the propylene and lube oil differentials, are based on posted prices from Platts Oilgram. The propylene differential is based on posted propylene prices in Chemical Market Associates, Inc. and the lube oil differential is based on Exxon Mobil Corporation postings provided by Independent Commodity Information Services-London Oil Reports. The average market reference prices and differentials are presented to provide users of the consolidated financial statements with economic indicators that significantly affect our operations and profitability.
(h)	The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.

42

(i) The market reference differential for ultra-low-sulfur diesel was not available prior to May 1, 2006, and therefore no market reference differential information is presented for the nine months ended September 30, 2006.

General

Operating revenues decreased 3% for the first nine months of 2007 compared to the first nine months of 2006 primarily as a result of lower sales volumes between the two periods, partially offset by an increase in refined product prices. Operating income decreased $264 million, or 4%, and income from continuing operations decreased $208 million, or 5%, from the nine months ended September 30, 2006 to the nine months ended September 30, 2007 primarily due to a $262 million decrease in refining segment operating income. The refining segment operating income and income from continuing operations exclude the operations of the Lima Refinery which are classified as discontinued operations due to our sale of that refinery as discussed in Note 3 of Condensed Notes to Consolidated Financial Statements.

Refining

Operating income for our refining segment decreased 4% from the first nine months of 2006 to $6.4 billion for the first nine months of 2007, resulting mainly from a $447 million increase in refining operating expenses (including depreciation and amortization expense) and a 17,000 barrel-per-day decrease in throughput volumes, partially offset by a 2% increase in throughput margin per barrel.

Total refining throughput margins for the first nine months of 2007 compared to the first nine months of 2006 were impacted by the following factors:

• Overall, gasoline and distillate margins improved in all of our refining regions in the first nine months of 2007 compared to the margins in the first nine months of 2006. The increase in refined product margins for the first nine months of 2007 was primarily due to a decline in refined product inventory levels resulting from unplanned refinery outages, lower imports, more stringent product specifications and regulations, and heavy industry turnaround activity, as well as moderately stronger demand.

• Sour crude oil feedstock differentials to WTI crude oil during the first nine months of 2007 were lower than the differentials in the first nine months of 2006. However, other light, sweet crude oils priced at a premium to WTI in the first nine months of 2007; thus, sour crude oil feedstock differentials relative to those other light, sweet crude oils in the first nine months of 2007 were comparable to the wide differentials experienced in the first nine months of 2006. These wide differentials are attributable to continued ample supplies of sour crude oils and heavy sour residual fuel oils on the world market. Differentials on sour crude oil feedstocks also continued to benefit from increased demand for sweet crude oil resulting from lower sulfur specifications for gasoline and diesel and a global increase in refined product demand.

• Margins on other refined products such as propylene, petroleum coke, and sulfur improved from the first nine months of 2006 to the first nine months of 2007 due to a decrease in the price of crude oil between the periods.

• Throughput volumes declined by 17,000 barrels per day in the first nine months of 2007 compared to the first nine months of 2006 due mainly to a reduction in throughput volumes at our McKee Refinery as a result of a fire originating in its propane deasphalting unit in February 2007.

Refining operating expenses, excluding depreciation and amortization expense, were 10% higher for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006 due primarily to increases in employee compensation and related benefits and maintenance expense, as well as increased accruals for sales and use taxes. Refining depreciation and amortization expense increased 24% from the first nine months of 2006 to the first nine months of 2007 primarily due to the

43

implementation of new capital projects, increased turnaround and catalyst amortization, and the write-off of costs related to the McKee Refinery as a result of the fire discussed above.

Retail

Retail operating income of $183 million for the nine months ended September 30, 2007 was approximately 12% higher than the $163 million reported for the nine months ended September 30, 2006. This increase in operating income was attributable to increased in-store sales in our U.S. and Canadian retail operations and improved fuel margins in our Canadian retail operations, partially offset by higher selling expenses related mainly to retail reorganization expenses.

Corporate Expenses and Other

General and administrative expenses, including corporate depreciation and amortization expense, increased $22 million from the first nine months of 2006 to the first nine months of 2007. This increase was primarily due to 2007 executive retirement expenses, a $13 million termination fee paid in 2007 for the cancellation of our services agreement with NuStar Energy L.P., and increased charitable contributions, partially offset by 2006 expenses attributable to Premcor headquarters personnel that were not incurred in the first nine months of 2007.

Equity in earnings of NuStar Energy L.P. is not reflected in the first nine months of 2007 due to the sale of our remaining ownership interest in NuStar GP Holdings, LLC in December 2006.

“Other income, net” for the first nine months of 2007 included a $91 million pre-tax gain related to a foreign currency exchange rate gain resulting from the repayment of a loan by a foreign subsidiary and increased interest income related to our significantly higher cash balance during 2007. “Other income, net” for the first nine months of 2006 included a pre-tax gain of $132 million related to the sale of 40.6% of our ownership interest in NuStar GP Holdings, LLC in July 2006.

Interest and debt expense increased primarily due to the issuance of $2.25 billion of notes in June 2007 to fund the accelerated share repurchase program, increased interest on tax liabilities, and reduced capitalized interest due to a reduced balance of capital projects under construction.

Income tax expense decreased $178 million from the first nine months of 2006 to the first nine months of 2007 mainly as a result of lower pre-tax income.

Income from discontinued operations, net of income tax expense, increased $526 million from the first nine months of 2006 to the first nine months of 2007 due primarily to the $426 million after-tax gain on the sale of the Lima Refinery in July 2007 combined with an 87% increase in Lima Refinery’s throughput margin per barrel, from $9.32 per barrel for the nine months ended September 30, 2006 to $17.41 per barrel for the six months ended June 30, 2007, prior to its sale.

OUTLOOK

Since the end of the third quarter of 2007, U.S. refined product margins have seasonally declined. However, U.S. light product inventories, on a days-of-supply basis, remain low relative to prior years. In addition, margins on other refined products such as asphalt and petroleum coke have declined as prices for such products have not increased as much as the price of WTI crude oil. Regarding feedstocks, sour crude oil differentials relative to sweet crude oils have improved significantly compared to the third quarter of 2007 and are expected to remain favorable through the fourth quarter due to ample supplies of sour crude oil and continued strong global demand for sweet crude oil.

44

On February 16, 2007, our McKee Refinery experienced a fire originating in its propane deasphalting unit. The refinery recommenced operations on April 12, 2007 at approximately 50% of capacity. Throughput rates at the McKee Refinery increased to near full capacity by the end of the third quarter of 2007 and are expected to reach full capacity by early 2008. In regard to other operations, we have turnaround activities scheduled for the fourth quarter of 2007 at several of our refineries, including Benicia, Paulsboro, Texas City, and Wilmington. We expect to benefit during the remainder of 2007 from capital improvement projects that were completed earlier this year, including the crude unit expansion project at our Port Arthur Refinery, the addition of mild hydrocracker units at our St. Charles and Houston Refineries, and the addition of a diesel hydrotreater unit at our Benicia Refinery.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Nine Months Ended September 30, 2007 and 2006
Net cash provided by operating activities for the nine months ended September 30, 2007 was $4.0 billion compared to $5.1 billion for the nine months ended September 30, 2006. The decrease in cash generated from operating activities was due primarily to a $900 million decrease in the eligible trade receivables sold under our accounts receivable sales facility, as discussed in Note 14 of Condensed Notes to Consolidated Financial Statements. Changes in cash provided by or used for working capital during the first nine months of 2007 and 2006 are shown in Note 9 of Condensed Notes to Consolidated Financial Statements.

Cash flows related to the discontinued operations of the Lima Refinery have been combined with the cash flows from continuing operations within each category in the consolidated statement of cash flows for each period presented. Cash provided by operating activities related to our discontinued results of operations was $260 million and $170 million for the nine months ended September 30, 2007 and 2006, respectively. Cash used in investing activities related to the Lima Refinery was $14 million and $117 million for the nine months ended September 30, 2007 and 2006, respectively.

The net cash generated from operating activities during the first nine months of 2007, combined with $2.25 billion of proceeds from the issuance of long-term notes, $2.4 billion of proceeds from the sale of our Lima Refinery, a $231 million benefit from tax deductions in excess of recognized stock-based compensation cost, and $130 million of proceeds from the issuance of common stock related to our employee benefit plans, were used mainly to:

• fund $1.9 billion of capital expenditures and deferred turnaround and catalyst costs;

• purchase 68.9 million shares of treasury stock at a cost of $4.8 billion;

• make an early debt repurchase of $183 million and a scheduled debt repayment of $230 million;

• fund capital contributions, net of distributions, of $212 million to Cameron Highway Oil Pipeline Company mainly to enable the joint venture to redeem all of its outstanding debt;

• fund contingent earn-out payments in connection with the acquisition of the St. Charles Refinery and the Delaware City Refinery of $50 million and $25 million, respectively;

• pay common stock dividends of $205 million; and

• increase available cash on hand by $1.5 billion.

The net cash generated from operating activities during the first nine months of 2006, combined with $355 million of proceeds from the sale of 40.6% of our ownership interest in NuStar GP Holdings, LLC, a $160 million benefit from tax deductions in excess of recognized stock-based compensation cost, and $103 million of proceeds from the issuance of common stock related to our employee benefit plans, were used mainly to:

• fund $2.8 billion of capital expenditures and deferred turnaround and catalyst costs;

• purchase 30.8 million shares of treasury stock at a cost of $1.8 billion;

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• make long-term note repayments of $249 million;

• fund $101 million of contingent earn-out payments in connection with the acquisition of Basis Petroleum, Inc., the St. Charles Refinery, and the Delaware City Refinery,

• terminate our interest rate swap contracts for $54 million;

• pay common and preferred stock dividends of $136 million; and

• increase available cash on hand by $593 million.

Capital Investments
During the nine months ended September 30, 2007, we expended $1.6 billion for capital expenditures and $338 million for deferred turnaround and catalyst costs. Capital expenditures for the nine months ended September 30, 2007 included $474 million of costs related to environmental projects.

In connection with our acquisition of the St. Charles Refinery in 2003, the seller is entitled to receive payments in any of the seven years following this acquisition if certain average refining margins during any of those years exceed a specified level. In connection with the Premcor Acquisition in 2005, we assumed Premcor’s obligation under a contingent earn-out agreement related to Premcor’s acquisition of the Delaware City Refinery from Motiva Enterprises LLC. Any payments due under these earn-out arrangements are limited based on annual and aggregate limits. In January 2007, we made an earn-out payment of $50 million related to the St. Charles Refinery. In June 2007, we made an earn-out payment of $25 million related to the acquisition of the Delaware City Refinery, which was the maximum remaining payment based on the aggregate limitation under the agreement.

For 2007, we expect to incur approximately $3.0 billion for capital investments, including approximately $2.5 billion for capital expenditures (approximately $640 million of which is for environmental projects) and approximately $475 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes expenditures related to the earn-out contingency agreements discussed above and strategic acquisitions. We continuously evaluate our capital budget and make changes as economic conditions warrant.

In May and June of 2007, we made cash capital contributions of $190 million and $25 million, respectively, to Cameron Highway Oil Pipeline Company, representing our 50% portion of the amount required for the Cameron Highway Oil Pipeline joint venture to redeem its fixed-rate notes and variable-rate debt, respectively. Our capital contributions, along with equal capital contributions from the other 50% joint venture partner, were used to redeem all of the joint venture’s outstanding debt.

Lima Refinery Disposition
Effective July 1, 2007, we consummated the sale of our Lima Refinery to Husky. Proceeds from the sale were approximately $2.4 billion, including approximately $550 million from the sale of working capital to Husky primarily related to the sale of inventory by our marketing and supply subsidiary. The sale resulted in a pre-tax gain of $827 million, or $426 million after tax, which is presented in “income from discontinued operations, net of income tax expense” in the consolidated statements of income for the three months and nine months ended September 30, 2007. In connection with the sale, we entered into a transition services agreement with Husky under which we agreed to provide certain accounting and administrative services to Husky beginning July 3, 2007, with the services terminating by July 31, 2008.

Contractual Obligations
As of September 30, 2007, our contractual obligations included long-term debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities. We had the following changes to our long-term debt during the nine months ended September 30, 2007.

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On February 1, 2007, we redeemed our 9.25% senior notes for $183 million, or 104.625% of stated value. In April 2007, we repaid in full, at the scheduled maturity date, $230 million related to our 6.125% notes.

In April 2007, we borrowed $3 billion under a 364-day term credit agreement with a financial institution to fund the accelerated share repurchase program discussed in Note 7 of Condensed Notes to Consolidated Financial Statements. In May 2007, we repaid $500 million of the borrowings under the 364-day term credit agreement. The remaining balance of $2.5 billion was repaid in June 2007 using available cash and proceeds from the issuance of $2.25 billion of notes described in Note 6 of Condensed Notes to Consolidated Financial Statements.

During the nine months ended September 30, 2007, we had no material changes outside the ordinary course of our business in operating leases or purchase obligations. Other long-term liabilities increased during the first nine months of 2007 due to the adoption of FIN 48 on January 1, 2007, as discussed in Note 11 of Condensed Notes to Consolidated Financial Statements.

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, 2007, all of our ratings on our senior unsecured debt are at or above “investment grade” level as follows:

Rating Agency	Rating
Standard & Poor’s Ratings Services	BBB (stable outlook)
Moody’s Investors Service	Baa3 (positive outlook)
Fitch Ratings	BBB (stable outlook)

Other Commercial Commitments
As of September 30, 2007, our committed lines of credit included:

	Borrowing
	Capacity	Expiration
Revolving credit facility	$2.5 billion	August 2011
Canadian revolving credit facility	Cdn. $115 million	December 2010

As of September 30, 2007, we had $594 million of letters of credit outstanding under our uncommitted short-term bank credit facilities and $298 million of letters of credit outstanding under our committed revolving credit facility. Under our Canadian committed revolving credit facility, we had Cdn. $11 million of letters of credit outstanding as of September 30, 2007. These letters of credit expire during 2007, 2008, and 2009.

In November 2007, we expect to amend our $2.5 billion revolving credit facility to extend the maturity date from August 2011 to November 2012.

Stock Purchase Programs
During the first quarter of 2007, we had two stock purchase programs that had been previously approved by our board of directors, which authorized our purchase of treasury stock in open market transactions to satisfy employee benefit plan requirements as well as a $2 billion common stock purchase program. Stock purchases under the programs are made from time to time at prevailing prices as permitted by securities laws and other legal requirements, subject to market conditions and other factors. The programs do not have a scheduled expiration date.

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On April 25, 2007, our board of directors approved an amendment to our $2 billion common stock purchase program to increase the authorized purchases under the program to $6 billion. In conjunction with the increase in our common stock purchase program, we entered into an agreement with a financial institution to purchase $3 billion of our shares under an accelerated share repurchase program, and in late April 2007, 42.1 million shares were purchased under this agreement. The purchase of these shares was funded with a short-term bridge loan, which we subsequently replaced with longer-term financing as described in Note 6 of Condensed Notes to Consolidated Financial Statements. The cost of the shares purchased under the accelerated share repurchase program was to be adjusted, with the final purchase cost based on a discount to the average trading price of our common stock, weighted by the daily volume of shares traded, during the program period. Any adjustment to the cost could be paid in cash or stock, at our option.

The accelerated share repurchase program was completed on July 23, 2007, resulting in an additional $94 million payment by us for the shares purchased. At that time, we elected to pay this additional amount in cash. This cash payment had a dilutive effect on our third quarter computation of earnings per common share from continuing operations assuming dilution.

During the first nine months of 2007, we purchased 68.9 million shares of our common stock at a cost of $4.8 billion in connection with the administration of our employee benefit plans and the common stock purchase programs authorized by our board of directors, including shares purchased under the accelerated share repurchase program discussed above.

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. Certain of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties.

Effective January 1, 2007, the Government of Aruba (GOA) enacted a turnover tax on revenues from the sale of goods produced and services rendered in Aruba. The turnover tax, which is 3% for on-island sales and services and 1% on export sales, is being assessed by the GOA on sales by our Aruba Refinery. However, due to a previous tax holiday that was granted to our Aruba Refinery by the GOA through December 31, 2010 as well as other reasons, we believe that exports by our Aruba Refinery should not be subject to this turnover tax. No amounts have been accrued on exports with respect to this turnover tax. We have commenced arbitration proceedings with the Netherlands Arbitration Institute pursuant to which we will seek to enforce our rights under the tax holiday.

Other
Although we had only $1 million of minimum required contributions to our qualified pension plans during 2007 under the Employee Retirement Income Security Act, we contributed $43 million to our qualified plans during the nine months ended September 30, 2007.

In November 2007, we announced our plan to explore strategic alternatives related to our Aruba Refinery.

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

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expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our refineries could require material additional expenditures to comply with environmental laws and regulations.

We believe that we have sufficient funds from operations and, to the extent necessary, from the public and private capital markets and bank markets, 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. However, there can be no assurances regarding the availability of any future financings or whether such financings can be made available on terms that are acceptable to us.

OFF-BALANCE SHEET ARRANGEMENTS

Accounts Receivable Sales Facility
As of September 30, 2007, we had an accounts receivable sales facility with a group of third-party financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables, which matures in August 2008. During the third quarter of 2007, we reduced the amount of eligible receivables sold to the third-party financial institutions by $900 million. As a result, as of September 30, 2007 and December 31, 2006, the amount of eligible receivables sold to the third-party financial institutions was $100 million and $1 billion, respectively.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Our critical accounting policies are disclosed in our Annual Report on Form 10-K for the year ended December 31, 2006.

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

COMMODITY PRICE RISK

The following tables provide information about our derivative commodity instruments as of September 30, 2007 and December 31, 2006 (dollars in millions, except for the weighted-average pay and receive prices as described below), including:

• fair value hedges which are used to hedge our recognized refining inventories (which had a carrying amount of $4.4 billion and $3.7 billion as of September 30, 2007 and December 31, 2006, respectively, and a fair value of $9.6 billion and $6.6 billion as of September 30, 2007 and December 31, 2006, respectively) and unrecognized firm commitments (i.e., binding agreements to purchase inventories in the future);

• cash flow hedges which are used to hedge our forecasted feedstock and product purchases, refined product sales, and natural gas purchases;

• economic hedges (hedges not designated as fair value or cash flow hedges) which are used to:

- manage price volatility in refinery feedstock and refined product inventories, and

- manage price volatility in forecasted feedstock and product purchases, refined product sales, and natural gas purchases; and

• derivative commodity instruments held or issued for trading purposes.

The gain or loss on a derivative instrument designated and qualifying as a fair value hedge and the offsetting loss or gain on the hedged item are recognized currently in income in the same period. The effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is initially reported as a component of “other comprehensive income” and is then recorded in income in the period or periods during which the hedged forecasted transaction affects income. The ineffective portion of the gain or loss on the cash flow derivative instrument, if any, is recognized in income as incurred. For our economic 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 following tables include only open positions at the end of the reporting period, and therefore do not include amounts related to closed cash flow hedges for which the gain or loss remains in “accumulated other comprehensive income” pending consummation of the forecasted transactions.

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

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	September 30, 2007
			Wtd Avg		Wtd Avg							Pre-tax
	Contract		Pay		Receive		Contract		Market			Fair
	Volumes		Price		Price		Value		Value			Value
Fair Value Hedges:
Futures – long:
2007 (crude oil and refined products)		42,934	$	78.15		N/A	$	3,355	$	3,515		$	160
Futures – short:
2007 (crude oil and refined products)		49,331		N/A	$	77.45		3,820		4,040			(220	)
2008 (crude oil and refined products)		305		N/A		78.17		24		24			-
Cash Flow Hedges:
Swaps – long:
2007 (crude oil and refined products)		24,360		74.64		84.03		N/A		229			229
2008 (crude oil and refined products)		9,375		71.55		78.17		N/A		62			62
Swaps – short:
2007 (crude oil and refined products)		24,360		86.49		77.68		N/A		(215	)		(215	)
2008 (crude oil and refined products)		8,475		88.19		82.35		N/A		(49	)		(49	)
Futures – long:
2007 (crude oil and refined products)		5,908		82.31		N/A		486		507			21
2008 (crude oil and refined products)		50		70.10		N/A		4		4			-
Futures – short:
2007 (crude oil and refined products)		4,581		N/A		81.03		371		391			(20	)
2008 (crude oil and refined products)		50		N/A		81.48		4		4			-
Economic Hedges:
Swaps – long:
2007 (crude oil and refined products)		17,326		25.17		28.00		N/A		49			49
2008 (crude oil and refined products)		775		78.87		79.47		N/A		-			-
2007 (natural gas)		388		0.26		0.26		N/A		-			-
Swaps – short:
2007 (crude oil and refined products)		9,095		52.59		47.90		N/A		(43	)		(43	)
2008 (crude oil and refined products)		1,675		89.39		84.97		N/A		(7	)		(7	)
2007 (natural gas)		388		0.26		0.26		N/A		-			-
Futures – long:
2007 (crude oil and refined products)		74,451		80.04		N/A		5,959		6,170			211
2008 (crude oil and refined products)		1,362		80.22		N/A		109		111			2
2007 (natural gas)		180		8.98		N/A		1		1			-
Futures – short:
2007 (crude oil and refined products)		72,775		N/A		79.09		5,756		6,006			(250	)
2008 (crude oil and refined products)		1,720		N/A		84.98		146		147			(1	)
2007 (natural gas)		380		N/A		10.02		4		3			1
Options – long:
2007 (crude oil and refined products)		21		88.10		N/A		-		-			-
2008 (crude oil and refined products)		34		87.18		N/A		-		-			-
Options – short:
2007 (crude oil and refined products)		1,200		N/A		15.78		3		-			3

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	September 30, 2007
			Wtd Avg		Wtd Avg							Pre-tax
	Contract		Pay		Receive		Contract		Market			Fair
	Volumes		Price		Price		Value		Value			Value
Trading Activities:
Swaps – long:
2007 (crude oil and refined products)		2,275	$	17.25	$	18.57		N/A	$	3		$	3
2008 (crude oil and refined products)		9,532		3.87		3.87		N/A		-			-
Swaps – short:
2007 (crude oil and refined products)		925		41.00		39.00		N/A		(2	)		(2	)
2008 (crude oil and refined products)		1,132		37.25		38.02		N/A		1			1
Futures – long:
2007 (crude oil and refined products)		12,334		85.94		N/A	$	1,060		1,084			24
2008 (crude oil and refined products)		1,180		87.01		N/A		103		107			4
Futures – short:
2007 (crude oil and refined products)		12,638		N/A		86.42		1,092		1,112			(20	)
2008 (crude oil and refined products)		875		N/A		84.36		74		78			(4	)
Options – short:
2007 (crude oil and refined products)		6		N/A		90.86		-		-			-
2008 (crude oil and refined products)		11		N/A		87.11		-		-			-
Total pre-tax fair value of open positions												$	(61	)

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	December 31, 2006
			Wtd Avg		Wtd Avg							Pre-tax
	Contract		Pay		Receive		Contract		Market			Fair
	Volumes		Price		Price		Value		Value			Value
Fair Value Hedges:
Futures – long:
2007 (crude oil and refined products)		15,261	$	63.66		N/A	$	972	$	949		$	(23	)
Futures – short:
2007 (crude oil and refined products)		22,091		N/A	$	64.56		1,426		1,379			47
Cash Flow Hedges:
Swaps – long:
2007 (crude oil and refined products)		39,125		70.14		65.16		N/A		(195	)		(195	)
Swaps – short:
2007 (crude oil and refined products)		39,125		69.66		76.30		N/A		260			260
Futures – long:
2007 (crude oil and refined products)		21,087		64.75		N/A		1,365		1,336			(29	)
Futures – short:
2007 (crude oil and refined products)		18,356		N/A		64.82		1,190		1,161			29
Economic Hedges:
Swaps – long:
2007 (crude oil and refined products)		13,244		12.02		11.02		N/A		(13	)		(13	)
2007 (natural gas)		893		0.76		0.78		N/A		-			-
Swaps – short:
2007 (crude oil and refined products)		7,605		26.47		27.66		N/A		9			9
2007 (natural gas)		833		0.85		0.89		N/A		-			-
Futures – long:
2007 (crude oil and refined products)		50,442		64.28		N/A		3,242		3,171			(71	)
2007 (natural gas)		400		7.33		N/A		3		3			-
Futures – short:
2007 (crude oil and refined products)		51,623		N/A		64.15		3,312		3,252			60
2007 (natural gas)		400		N/A		8.21		3		3			-
Options – long:
2007 (crude oil and refined products)		31		84.29		N/A		-		-			-
Options – short:
2007 (crude oil and refined products)		1,478		N/A		61.94		-		(6	)		6
Trading Activities:
Futures – long:
2007 (crude oil and refined products)		801		77.29		N/A		62		59			(3	)
Futures – short:
2007 (crude oil and refined products)		801		N/A		84.87		68		58			10
Total pre-tax fair value of open positions												$	87

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INTEREST RATE RISK

The following table provides information about our long-term debt instruments (dollars in millions), all 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, 2007 and December 31, 2006.

	September 30, 2007
	Expected Maturity Dates
																There-						Fair
	2007			2008			2009			2010			2011			after			Total			Value
Long-term Debt:
Fixed rate	$	50		$	6		$	209		$	33		$	418		$	6,196		$	6,912		$	7,121
Average interest rate		6.3	%		6.0	%		3.6	%		6.8	%		6.4	%		6.9	%		6.7	%

	December 31, 2006
	Expected Maturity Dates
																There-						Fair
	2007			2008			2009			2010			2011			after			Total			Value
Long-term Debt:
Fixed rate	$	462		$	6		$	209		$	33		$	418		$	3,946		$	5,074		$	5,361
Average interest rate		7.3	%		6.0	%		3.6	%		6.8	%		6.4	%		7.1	%		6.9	%

FOREIGN CURRENCY RISK

As of September 30, 2007, we had commitments to purchase $346 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before October 23, 2007, resulting in $10 million of losses recorded in the fourth quarter of 2007.

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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 operating effectively as of September 30, 2007.

(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.

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, 2006 or our quarterly reports on Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007.

     Litigation

For the legal proceedings listed below, we hereby incorporate by reference into this Item our disclosures made in Part I, Item 1 of this Report included in Note 14 of Condensed Notes to Consolidated Financial Statements under the caption“Litigation.”

• MTBE Litigation

• Retail Fuel Temperature Litigation

     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 of America, et al. v. The Premcor Refining Group, Inc., et al., United States District Court, Western District of Texas (Civil Action No. SA07CA0683RF, August 16, 2007). In the past several years, the U.S. Environmental Protection Agency (EPA) issued to a majority of refiners operating in the United States a series of information requests pursuant to Section 114 of the Clean Air Act as part of the EPA’s National Petroleum Refinery Initiative (Initiative) to reduce air emissions. Three refineries that we acquired in the Premcor Acquisition (the Port Arthur, Memphis, and Lima Refineries) had received information requests as part of this Initiative (the Delaware City Refinery was already subject to a separate Section 114 settlement). On August 16, 2007, the EPA and the U.S. Department of Justice announced an Initiative settlement with us covering these three refineries. The state of Ohio and Memphis-Shelby County, Tennessee joined the EPA in the settlement. The EPA’s consent decree, lodged

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August 16, 2007 in the U.S. District Court for the Western District of Texas (Consent Decree), will require an investment of approximately $232 million in environmental projects over the next several years to reduce emissions at the refineries. The cost of projects at the Lima Refinery (approximately $85 million) will be borne by Husky Refining Company, which acquired the Lima Refinery effective July 1, 2007. In addition to the capital projects, we will pay a $4.25 million civil penalty. The 30-day public comment period for the decree expired without additional comment. We expect the court to formally enter the consent decree in the fourth quarter of 2007.

Several proceedings that we previously disclosed in our annual report on Form 10-K for the year ended December 31, 2006 were settled in connection with the Consent Decree. They are:

• United States Environmental Protection Agency, Region V, Notice of Violation and Finding of Violation EPA-5-05-OH-16(June 28, 2005) (Lima Refinery). The EPA had issued a notice and finding of violation (NOV) relating to inspections at the Lima Refinery in 2001. The NOV cited alleged violations under leak detection and repair regulations and tank floating roof regulations.

• United States Environmental Protection Agency, Region VI, Notice of Violation(June 15, 2005) (Port Arthur Refinery). The EPA issued an NOV concerning past flaring issues at the Port Arthur Refinery that occurred prior to the Premcor Acquisition.

• Ohio Environmental Protection Agency (Ohio EPA)(Lima Refinery). The Ohio EPA had issued a proposed order to the Lima Refinery related to hydrogen sulfide levels in sewer gases routed to the refinery’s wastewater thermal oxidizer.

Delaware Department of Natural Resources and Environmental Control (DDNREC)(Delaware City Refinery). On October 11, 2007, the DDNREC issued an NOV to our Delaware City Refinery alleging unauthorized emissions and failure to report emissions from the refinery’s frozen earth storage unit. The NOV does not specify a penalty amount, but we reasonably believe that such proceeding may result in monetary sanctions of $100,000 or more.

Texas Commission on Environmental Quality (TCEQ)(Port Arthur Refinery) (this matter was last reported in our Form 10-K for the year ended December 31, 2006). In September 2005, we received two enforcement actions from the TCEQ relating to alleged Texas Clean Air Act violations at the Port Arthur Refinery dating back to 2002. This matter is now being handled by the Texas Attorney General’s office, and we are currently in settlement discussions with that office.

TCEQ(Texas City Refinery). On July 11, 2007, we received a Notice of Enforcement from the TCEQ for excess air emissions that began in 2005 at our Texas City Refinery relating to a partially open flare valve. On September 25, 2007, the TCEQ issued a proposed Agreed Order with a proposed administrative penalty of $228,900. We are negotiating with the TCEQ to settle this matter.

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Item 1A. Risk Factors.

There have been no material changes from the risk factors disclosed in the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2006.

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

     (a) Unregistered Sales of Equity Securities.On August 31, 2007, we issued an aggregate of 1,145,259 shares of our common stock to five affiliated, former stockholders of Huntway Refining Company in connection with the conversion in full of our 5% convertible notes due September 1, 2007, as amended, held by such holders (with fractional shares being paid in cash). All of the shares of common stock were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act of 1933 for transactions by an issuer not involving any public offering.

     (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.

					Total Number		Total Number		Maximum Number (or
					of Shares Not		of Shares		Approximate Dollar
					Purchased as Part		Purchased as		Value) of Shares that
					of Publicly		Part of Publicly		May Yet Be Purchased
	Total Number		Average		Announced		Announced		Under the Plans or
	of Shares		Price Paid		Plans or		Plans or		Programs (at month
Period	Purchased		per Share		Programs(1)		Programs		end)(2)
July 2007		7,450	$	74.23		7,450		0	$2.05 billion(3)
August 2007		3,101,567	$	66.38		3,101,567		0	$2.05 billion(3)
September 2007		3,897,413	$	69.00		3,897,413		0	$2.05 billion(3)
Total		7,006,430	$	67.85		7,006,430		0

(1)	The shares reported in this column represent purchases settled in the third quarter of 2007 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, including a $3 billion accelerated share repurchase program, as authorized by our board of directors on April 25, 2007. The $6 billion common stock purchase program has no expiration date. The $6 billion common stock purchase program is more fully described above in Note 7 of Condensed Notes to Consolidated Financial Statements, and we hereby incorporate by reference into this Item our disclosures made in Note 7.
(3)	Includes the effects of the $94 million settlement amount paid in July upon completion of the accelerated share repurchase program as described in Note 7 of Condensed Notes to Consolidated Financial Statements.

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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) Certifications (under Section 302 of the Sarbanes-Oxley Act of 2002).
*32.01	Section 1350 Certifications (as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).

* Filed herewith.

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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 7, 2007

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