Edgar Filing: VALERO ENERGY CORP/TX

Form 10-Q

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 June 30, 2006

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

For the transition period from to

Commission file number 1-13175

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

74-1828067

(State or other jurisdiction of

incorporation or organization)

(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 July 31, 2006 was 612,863,378.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

INDEX


		Page
PART I - FINANCIAL INFORMATION

	Item 1. Financial Statements

	Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005	3

	Consolidated Statements of Income for the Three and Six Months Ended June 30, 2006 and 2005	4

	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2005	5

	Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2006 and 2005	6

	Condensed Notes to Consolidated Financial Statements	7

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	52

	Item 4. Controls and Procedures	56

PART II - OTHER INFORMATION

	Item 1. Legal Proceedings	56

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	57

	Item 4. Submission of Matters to a Vote of Security Holders	58

	Item 6. Exhibits	58

SIGNATURE		59

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Par Value)


	June 30, 2006			December 31, 2005
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	937		$	436
Restricted cash		31			30
Receivables, net		4,234			3,564
Inventories		4,626			4,039
Deferred income taxes		176			142
Prepaid expenses and other		170			65

Total current assets		10,174			8,276

Property, plant and equipment, at cost		22,893			20,388
Accumulated depreciation		(2,905	)		(2,532	)

Property, plant and equipment, net		19,988			17,856

Intangible assets, net		293			298
Goodwill		4,311			4,926
Investment in Valero L.P.		481			327
Deferred charges and other assets, net		1,277			1,045

Total assets	$	36,524		$	32,728

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Short-term debt	$	45		$	—
Current portion of long-term debt and capital lease obligations		230			222
Accounts payable		6,902			5,563
Accrued expenses		464			581
Taxes other than income taxes		598			595
Income taxes payable		557			39
Deferred income taxes		311			305

Total current liabilities		9,107			7,305

Long-term debt, less current portion		4,868			5,109

Capital lease obligations, less current portion		45			47

Deferred income taxes		4,152			3,615

Other long-term liabilities		1,588			1,602

Commitments and contingencies (Note 14)

Stockholders’ equity:
Preferred stock, $0.01 par value; 20,000,000 shares authorized; 2,416,891 and 3,164,151 shares issued and outstanding		53			68
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 622,711,332 and 621,230,266 shares issued		6			6
Additional paid-in capital		7,839			8,164
Treasury stock, at cost; 14,559,930 and 3,807,976 common shares		(868	)		(196	)
Retained earnings		9,331			6,673
Accumulated other comprehensive income		403			335

Total stockholders’ equity		16,764			15,050

Total liabilities and stockholders’ equity	$	36,524		$	32,728

See Condensed Notes to Consolidated Financial Statements.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Millions of Dollars, Except per Share Amounts and Supplemental Information)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Operating revenues (1) (2)	$	26,781		$	18,032		$	47,722		$	32,985

Costs and expenses:
Cost of sales (1)		22,300			15,679			40,382			28,751
Refining operating expenses		949			564			1,875			1,144
Retail selling expenses		204			182			393			354
General and administrative expenses		171			112			322			216
Depreciation and amortization expense		293			190			553			369

Total costs and expenses		23,917			16,727			43,525			30,834

Operating income		2,864			1,305			4,197			2,151
Equity in earnings of Valero L.P.		10			10			22			19
Other expense, net		(5	)		(13	)		(5	)		(15	)
Interest and debt expense:
Incurred		(93	)		(71	)		(189	)		(145	)
Capitalized		47			10			84			21

Income before income tax expense		2,823			1,241			4,109			2,031
Income tax expense		926			394			1,363			650

Net income		1,897			847			2,746			1,381
Preferred stock dividends		1			4			2			8

Net income applicable to common stock	$	1,896		$	843		$	2,744		$	1,373

Earnings per common share	$	3.10		$	1.64		$	4.46		$	2.68
Weighted-average common shares outstanding (in millions)		611			514			615			513

Earnings per common share – assuming dilution	$	2.98		$	1.53		$	4.29		$	2.49
Weighted-average common equivalent shares outstanding (in millions)		636			555			640			555

Dividends per common share	$	0.08		$	0.05		$	0.14		$	0.09
___________
Supplemental information (billions of dollars):
(1) Includes the following amounts related to crude oil buy/sell arrangements (see Note 2, EITF Issue No. 04-13):
Operating revenues		N/A		$	1.6			N/A		$	2.8
Cost of sales		N/A		$	1.6			N/A		$	2.8
(2) Includes excise taxes on sales by our U.S. retail system	$	0.2		$	0.2		$	0.4		$	0.4

See Condensed Notes to Consolidated Financial Statements.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

(Unaudited)


	Six Months Ended June 30,
	2006			2005
Cash flows from operating activities:
Net income	$	2,746		$	1,381
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		553			369
Stock-based compensation expense		52			30
Deferred income tax expense		116			187
Changes in current assets and current liabilities		381			(171	)
Changes in deferred charges and credits and other, net		(25	)		(17	)

Net cash provided by operating activities		3,823			1,779

Cash flows from investing activities:
Capital expenditures		(1,588	)		(776	)
Deferred turnaround and catalyst costs		(387	)		(223	)
Contingent payments in connection with acquisitions		(76	)		(85	)
Proceeds from the sale of the Denver Refinery		—			45
Other investing activities, net		18			20

Net cash used in investing activities		(2,033	)		(1,019	)

Cash flows from financing activities:
Repayment of capital lease obligations		(1	)		(1	)
Long-term note repayments		(221	)		(478	)
Bank credit agreements:
Borrowings		501			116
Repayments		(439	)		(116	)
Termination of interest rate swaps		(54	)		—
Issuance of common stock in connection with employee benefit plans		65			40
Benefit from tax deduction in excess of recognized stock-based compensation cost		130			—
Common and preferred stock dividends		(87	)		(48	)
Purchase of treasury stock		(1,187	)		(183	)

Net cash used in financing activities		(1,293	)		(670	)

Effect of foreign exchange rate changes on cash		4			(5	)

Net increase in cash and temporary cash investments		501			85
Cash and temporary cash investments at beginning of period		436			864

Cash and temporary cash investments at end of period	$	937		$	949

See Condensed Notes to Consolidated Financial Statements.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)


	Three Months Ended June 30,					Six Months Ended June 30,
	2006		2005			2006			2005
Net income	$	1,897	$	847		$	2,746		$	1,381

Other comprehensive income (loss):
Foreign currency translation adjustment		80		(17	)		72			(30	)

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 $0, $9, $(1) and $131		—		(18	)		2			(244	)
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $0, $(48), $3 and $(71)		—		90			(6	)		133

Net gain (loss) on cash flow hedges		—		72			(4	)		(111	)

Other comprehensive income (loss)		80		55			68			(141	)

Comprehensive income	$	1,977	$	902		$	2,814		$	1,240

See Condensed Notes to Consolidated Financial Statements.

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 non-controlled entities are accounted for using the equity method.

These unaudited consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the three and six months ended June 30, 2006 and 2005 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited consolidated financial statements. Operating results for the three and six months ended June 30, 2006 are not necessarily indicative of the results that may be expected for the year ending December 31, 2006.

The consolidated balance sheet as of December 31, 2005 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, 2005.

Share and per share data (except par value) presented for 2005 reflect the effect of a two-for-one stock split which was effected in the form of a common stock dividend distributed on December 15, 2005, as discussed in Note 7 under “2005 Common Stock Split.”

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Reclassifications

Certain previously reported amounts have been reclassified to conform to the 2006 presentation, including reflecting in our consolidated statement of cash flows our gross borrowings and repayments under our committed and uncommitted bank credit facilities and presenting those amounts separate from borrowings and repayments related to our long-term notes. The reclassifications also included amounts previously reported in the consolidated statement of income in 2005 for refining operating expenses, retail selling expenses, general and administrative expenses, and depreciation and amortization expense which were reclassified due to the following changes that took effect on January 1, 2006: (i) information services costs that were previously allocated to the operating units are now being reported as general and administrative expenses to better reflect the area responsible for such costs and (ii) Statement No. 123R (discussed in Note 2) was implemented, which resulted in amounts previously reported as amortization expense now being reported as operating, selling or general and administrative expenses. These reclassified income statement amounts were as follows (in millions):


	Three Months Ended June 30, 2005
	Previously Reported		Reclassifications			Currently Reported
Refining operating expenses	$	575	$	(11	)	$	564
Retail selling expenses		185		(3	)		182
General and administrative expenses		91		21			112
Depreciation and amortization expense		197		(7	)		190


	Six Months Ended June 30, 2005
	Previously Reported		Reclassifications			Currently Reported
Refining operating expenses	$	1,166	$	(22	)	$	1,144
Retail selling expenses		360		(6	)		354
General and administrative expenses		174		42			216
Depreciation and amortization expense		383		(14	)		369

Sales of Subsidiary Stock

Securities and Exchange Commission (SEC) Staff Accounting Bulletin No. 51, “Accounting for Sales of Stock by a Subsidiary” (SAB 51), provides guidance on accounting for the effect of issuances of a subsidiary’s stock on the parent’s investment in that subsidiary. SAB 51 allows registrants to elect an accounting policy of recording such increases or decreases in a parent’s investment (SAB 51 credits or charges, respectively) either in income or in stockholders’ equity. In accordance with the election provided in SAB 51, we adopted a policy of recording such SAB 51 credits or charges directly to “additional paid-in capital” in stockholders’ equity. As further discussed in Note 5, in the second quarter of 2006, we recognized certain SAB 51 credits related to our investment in Valero L.P. under our adopted methodology.

2. ACCOUNTING PRONOUNCEMENTS

FASB Statement No. 123 (revised 2004)

In December 2004, the Financial Accounting Standards Board (FASB) issued Statement No. 123 (revised 2004), “Share-Based Payment” (Statement No. 123R), which requires the expensing of the fair value of stock options. We adopted Statement No. 123R on January 1, 2006. The specific impact of our adoption of Statement No. 123R will depend on levels of share-based incentive awards granted in the future. Had

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

we adopted Statement No. 123R in prior periods, the impact of that standard would have approximated the impact of Statement No. 123 as described in Note 12.

Statement No. 123R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported in our statements of cash flows as a financing cash flow, rather than as an operating cash flow as previously required. This requirement reduces cash flows from operating activities and increases cash flows from financing activities beginning in 2006. While we cannot estimate the specific magnitude of this change on future cash flows because it depends on, among other things, when employees exercise stock options, the cash flows recognized for such excess tax deductions were $146 million and $32 million for the six months ended June 30, 2006 and 2005, respectively.

Under our employee stock compensation plans, certain awards of stock options and restricted stock provide that employees vest in the award when they retire or will continue to vest in the award after retirement over the nominal vesting period established in the award. We previously accounted for such awards by recognizing compensation cost, if any, under APB Opinion No. 25 and pro forma compensation cost under Statement No. 123 over the nominal vesting period, as disclosed in Note 12. Upon the adoption of Statement No. 123R, we changed our method of recognizing compensation cost to the non-substantive vesting period approach for any awards that are granted after the adoption of Statement No. 123R. Under the non-substantive vesting period approach, compensation cost is recognized immediately for awards granted to retirement-eligible employees or over the period from the grant date to the date retirement eligibility is achieved if that date is expected to occur during the nominal vesting period. If the non-substantive vesting period approach had been used by us for awards granted prior to January 1, 2006, the impact on the pro forma net income applicable to common stock and pro forma net income amounts for the three and six months ended June 30, 2005 would have been less than $1 million and $2 million, respectively, and the impact on net income applicable to common stock and net income for the three and six months ended June 30, 2006, would have been less than $2 million and $3 million, respectively, as disclosed in Note 12.

EITF Issue No. 04-5

In June 2005, the FASB ratified its consensus on Emerging Issues Task Force (EITF) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (EITF No. 04-5), which requires the general partner in a limited partnership to determine whether the limited partnership is controlled by, and therefore should be consolidated by, the general partner. The guidance in EITF No. 04-5 was effective after June 29, 2005 for general partners of all new partnerships formed and for existing limited partnerships for which the partnership agreements are modified. For general partners in all other limited partnerships, the guidance in EITF No. 04-5 was effective no later than January 1, 2006. We adopted EITF No. 04-5 effective January 1, 2006, the adoption of which had no impact on the accounting for our investment in Valero L.P.

EITF Issue No. 04-13

Through December 31, 2005, our operating revenues included sales related to certain buy/sell arrangements. In September 2005, the FASB ratified its consensus on EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF No. 04-13), which requires that inventory purchase and sale transactions with the same counterparty that are entered into in contemplation of one another should be combined. The guidance in EITF No. 04-13 was effective for transactions completed in reporting periods beginning after March 15, 2006, with early application permitted. We adopted EITF No. 04-13 on January 1, 2006.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

One issue addressed by EITF No. 04-13 details factors to consider in evaluating whether certain individual transactions to purchase and sell inventory are made in contemplation of one another and should therefore be viewed as one transaction when applying the principles of AICPA Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions” (APB No. 29). When applying these factors, certain of our buy/sell arrangements are deemed to be made in contemplation of one another. Accordingly, commencing January 1, 2006, revenues and cost of sales ceased to be recognized in connection with these arrangements. If we had applied EITF No. 04-13 for the three and six months ended June 30, 2005, operating revenues and cost of sales would have been reduced by the amounts reflected in the supplemental information on the face of the consolidated statements of income.

FASB Statement No. 155

In February 2006, the 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.” Statement No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s fiscal year that begins after September 15, 2006. The adoption of Statement No. 155 is not expected to materially affect 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. Statement No. 156 is effective for fiscal years beginning after September 15, 2006, with early adoption permitted. The adoption of Statement No. 156 is not expected to materially affect 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 would be required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. FIN 48 is effective for fiscal years beginning after December 15, 2006 and is not expected to materially affect our financial position or results of operations.

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

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

annual basis for all periods presented. The disclosure of those taxes can be done on an aggregate basis. The consensus is effective for interim and annual periods beginning after December 15, 2006, with earlier application permitted. Adoption of EITF No. 06-3 is not expected to affect our financial position or results of operations.

3. ACQUISITIONS

Premcor Acquisition

On September 1, 2005, we completed our merger with Premcor Inc. (Premcor). As used in this report, Premcor Acquisition refers to the merger of Premcor with and into Valero. Premcor was an independent petroleum refiner and supplier of unbranded transportation fuels, heating oil, petrochemical feedstocks, petroleum coke and other petroleum products with all of its operations in the United States. Premcor owned and operated refineries in Port Arthur, Texas; Lima, Ohio; Memphis, Tennessee; and Delaware City, Delaware, with a combined crude oil throughput capacity of approximately 800,000 barrels per day.

During the second quarter of 2006, an independent appraisal of the assets acquired in the Premcor Acquisition and certain other evaluations related to the Premcor Acquisition purchase price allocation were completed. As of June 30, 2006, the purchase price of the Premcor Acquisition has been allocated based on the fair values of the assets acquired and the liabilities assumed at the date of acquisition resulting from this final appraisal and other evaluations. The primary adjustments to the preliminary purchase price allocation reflected in our Annual Report on Form 10-K for the year ended December 31, 2005 include an $898 million increase in property, plant and equipment, a $609 million decrease in goodwill and a $326 million increase in deferred income taxes resulting from the final appraisal. The final purchase price allocation for the Premcor Acquisition is pending further evaluation of certain loss contingency matters, with respect to which we anticipate receiving information prior to September 1, 2006. The purchase price and the purchase price allocation based on information available as of June 30, 2006 were as follows (in millions):


Cash paid	$	3,377
Transaction costs		27
Less unrestricted cash acquired		(1,061	)

Premcor Acquisition, net of cash acquired		2,343
Common stock and stock options issued		3,773

Total purchase price, excluding unrestricted cash acquired	$	6,116


Current assets, net of unrestricted cash acquired	$	3,551
Property, plant and equipment		6,771
Intangible assets		5
Goodwill		1,919
Deferred charges and other assets		30
Current liabilities, less current portion of long-term debt and capital lease obligations		(1,746	)
Long-term debt assumed, including current portion		(1,912	)
Capital lease obligation, including current portion		(14	)
Deferred income taxes		(2,004	)
Other long-term liabilities		(484	)

Purchase price, excluding unrestricted cash acquired	$	6,116

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Unaudited Pro Forma Financial Information

The consolidated statements of income include the results of operations of the Premcor Acquisition commencing on September 1, 2005. As a result, information for the three and six months ended June 30, 2006 presented below represents actual results of operations.

The following unaudited pro forma financial information assumes that the Premcor Acquisition occurred on January 1, 2005. The pro forma information assumes 85 million shares of common stock were issued, $1.5 billion of debt was incurred and $1.9 billion of available cash was utilized to fund the Premcor Acquisition on January 1, 2005.

The unaudited pro forma financial information is not necessarily indicative of the results of future operations (in millions, except per share amounts):


	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Operating revenues	$	26,781	$	23,140	$	47,722	$	42,067
Operating income		2,864		1,794		4,197		2,836
Net income		1,897		1,138		2,746		1,774
Earnings per common share		3.10		1.89		4.46		2.95
Earnings per common share – assuming dilution		2.98		1.76		4.29		2.74

4. INVENTORIES

Inventories consisted of the following (in millions):


	June 30, 2006		December 31, 2005
Refinery feedstocks	$	2,365	$	1,826
Refined products and blendstocks		2,003		1,960
Convenience store merchandise		94		91
Materials and supplies		164		162

Inventories	$	4,626	$	4,039

As of June 30, 2006 and December 31, 2005, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $5.1 billion and $3.3 billion, respectively.

5. INVESTMENT IN AND TRANSACTIONS WITH VALERO L.P.

Our ownership interest in Valero L.P. as of June 30, 2006 and December 31, 2005 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 as of June 30, 2006 was represented by 10,222,630 common units of Valero 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 Valero L.P.’s partnership agreement.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Valero L.P. has issued common units to the public on three separate occasions, which has diluted our ownership percentage. These three issuances have resulted in increases (or credits) in our proportionate share of Valero 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 our 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, we recognized the entire balance of $158 million in SAB 51 credits as an increase in our investment in Valero L.P. and $101 million after tax as an increase to “additional paid-in capital” in our consolidated balance sheet.

Summary Financial Information

Financial information reported by Valero L.P. for the three and six months ended June 30, 2006 and 2005 is summarized below (in millions):


	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Revenues	$	280	$	58	$	554	$	115
Operating income		47		24		103		49
Net income		32		19		71		38

Related-Party Transactions

We provide Valero L.P. with certain corporate functions for an annual fee as prescribed by a services agreement. In addition, we charge Valero L.P. for employee costs related to operating and maintenance services performed on certain Valero L.P. assets. We also pay Valero L.P. certain fees under separate throughput, handling, terminalling and service agreements with Valero L.P.

As of June 30, 2006 and December 31, 2005, our “receivables, net” included $11 million and $13 million, respectively, from Valero L.P., representing amounts due for employee costs, insurance costs, operating expenses, administrative costs and rentals. As of June 30, 2006 and December 31, 2005, our “accounts payable” included $21 million and $22 million, respectively, to Valero L.P., representing amounts due for pipeline tariffs, terminalling fees and tank rentals and fees. The following table summarizes the results of transactions with Valero L.P. (in millions):


	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Fees and expenses charged by us to Valero L.P.	$	31	$	11	$	57	$	22
Fees and expenses charged to us by Valero L.P.		64		58		125		113

Valero GP Holdings, LLC

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

$355 million, net of the underwriters’ discount and other offering expenses, which will result in a third quarter 2006 pre-tax gain of approximately $125 million on the sale of the units. Subsequent to the initial public offering, subsidiaries of Valero hold a 59.4% ownership interest in Valero GP Holdings, LLC. It is our intention to further reduce and ultimately sell all of our interest in Valero GP Holdings, LLC, pending market conditions. However, we are subject to a 180-day holding period subsequent to July 13, 2006 (date of prospectus) during which we have agreed not to sell any additional units without the consent of Lehman Brothers Inc. We expect to use funds from this offering for general corporate purposes, which may include acquisitions, stock purchases and debt reduction.

6. LONG-TERM DEBT AND SHORT-TERM DEBT

During March 2006, we made a scheduled debt repayment of $220 million related to our 7.375% notes and a payment of $1 million related to our 7.75% notes. In addition, during the six months ended June 30, 2006, we borrowed $406 million under our revolving credit facilities of which $388 million was repaid, and we borrowed $95 million under our short-term uncommitted bank credit facilities of which $51 million was repaid.

7. STOCKHOLDERS’ EQUITY

2% Mandatory Convertible Preferred Stock

During the six months ended June 30, 2006, 747,260 shares of our 2% mandatory convertible preferred stock were converted into 1,481,066 shares of our common stock. On July 1, 2006, the mandatory conversion date, the remaining 2,416,891 shares of our preferred stock were converted into 4,790,261 shares of our common stock.

2005 Common Stock Split

On September 15, 2005, our board of directors approved a two-for-one split of our common stock that was effected in the form of a stock dividend. The stock dividend was distributed on December 15, 2005 to stockholders of record on December 2, 2005. In connection with the stock split, our shareholders approved on December 1, 2005, an amendment to our certificate of incorporation to increase the number of authorized common shares from 600 million to 1.2 billion.

All share and per share data (except par value) for 2005 have been adjusted to reflect the effect of the stock split. In addition, the number of shares of common stock issuable upon conversion of the mandatory convertible preferred stock, the exercise of outstanding stock options and the vesting of other stock awards were proportionately increased in accordance with the terms of those respective agreements and plans.

Treasury Stock

During the six months ended June 30, 2006 and 2005, we purchased 20.4 million and 5.8 million shares of our common stock at a cost of $1.2 billion and $183 million, respectively, in connection with the administration of our employee benefit plans and the stock purchase program authorized by our board of directors. During the six months ended June 30, 2006, we issued 9.6 million treasury shares at an average cost of $53.52 per share, and for the six months ended June 30, 2005, we issued 4.6 million treasury shares at an average cost of $19.02 per share, for our employee benefit plans.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Common Stock Dividends

On July 20, 2006, our board of directors declared a regular quarterly cash dividend of $0.08 per common share payable September 14, 2006 to holders of record at the close of business on August 16, 2006.

8. EARNINGS PER COMMON SHARE

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Earnings per Common Share:
Net income	$	1,897	$	847	$	2,746	$	1,381
Preferred stock dividends		1		4		2		8

Net income applicable to common stock	$	1,896	$	843	$	2,744	$	1,373

Weighted-average common shares outstanding		611		514		615		513

Earnings per common share	$	3.10	$	1.64	$	4.46	$	2.68

Earnings per Common Share – Assuming Dilution:
Net income applicable to common equivalent shares	$	1,897	$	847	$	2,746	$	1,381

Weighted-average common shares outstanding		611		514		615		513
Effect of dilutive securities:
Stock options		19		20		19		20
Performance awards and other benefit plans		1		6		1		6
Mandatory convertible preferred stock		5		15		5		16

Weighted-average common equivalent shares outstanding		636		555		640		555

Earnings per common share – assuming dilution	$	2.98	$	1.53	$	4.29	$	2.49

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):


	Six Months Ended June 30,
	2006			2005
Decrease (increase) in current assets:
Receivables, net	$	(648	)	$	(815	)
Inventories		(573	)		(792	)
Prepaid expenses and other		(105	)		(45	)
Increase (decrease) in current liabilities:
Accounts payable		1,316			1,432
Accrued expenses		(148	)		(48	)
Taxes other than income taxes		(1	)		(46	)
Income taxes payable		540			143

Changes in current assets and current liabilities	$	381		$	(171	)

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

•

previously accrued contingent earn-out payments are reflected separately in investing activities in the consolidated statements of cash flows; 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.

Noncash investing activities for the six months ended June 30, 2006 included the pre-tax recognition of $158 million of SAB 51 credits related to our investment in Valero 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 and UDS. Noncash financing activities for the six months ended June 30, 2006 included the conversion of 747,260 shares of preferred stock into 1,481,066 shares of our common stock as discussed in Note 7.

Noncash investing activities for the six months ended June 30, 2005 included adjustments to property, plant and equipment and certain current and noncurrent assets and liabilities resulting from adjustments to the purchase price allocation related to the acquisition of the Aruba Refinery. Noncash financing activities for the six months ended June 30, 2005 included the recognition of a $28 million capital lease obligation and related capital lease asset pertaining to certain equipment at our Texas City Refinery and the conversion of 2,609,952 shares of preferred stock into 5,172,916 shares of our common stock.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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


	Six Months Ended June 30,
	2006		2005
Interest paid (net of amount capitalized)	$	164	$	123
Income taxes paid (net of tax refunds received)		569		320

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 June 30,					Six Months Ended June 30,
	2006			2005		2006			2005
Fair value hedges	$	(3	)	$	2	$	(6	)	$	3
Cash flow hedges		5			2		5			—

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 six months ended June 30, 2005, we recognized in “accumulated other comprehensive income” unrealized after-tax losses of $244 million on certain cash flow hedges, primarily related to forward sales of distillates and associated forward purchases of crude oil. During the six months ended June 30, 2006, there were no significant gains or losses recognized in “accumulated other comprehensive income,” nor did any amounts related to cash flow hedges remain in “accumulated other comprehensive income” as of June 30, 2006. For the six months ended June 30, 2006 and 2005, there were no amounts reclassified from “accumulated other comprehensive income” into income as a result of the discontinuance of cash flow hedge accounting.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. SEGMENT INFORMATION

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


	Refining		Retail		Corporate			Total
Three months ended June 30, 2006
Operating revenues from external customers	$	24,530	$	2,251	$	—		$	26,781
Intersegment revenues		1,601		—		—			1,601
Operating income (loss)		2,999		46		(181	)		2,864

Three months ended June 30, 2005:
Operating revenues from external customers		16,231		1,801		—			18,032
Intersegment revenues		1,165		—		—			1,165
Operating income (loss)		1,375		50		(120	)		1,305

Six months ended June 30, 2006:
Operating revenues from external customers		43,566		4,156		—			47,722
Intersegment revenues		2,912		—		—			2,912
Operating income (loss)		4,471		67		(341	)		4,197

Six months ended June 30, 2005:
Operating revenues from external customers		29,597		3,388		—			32,985
Intersegment revenues		2,207		—		—			2,207
Operating income (loss)		2,319		64		(232	)		2,151

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


	June 30, 2006		December 31, 2005
Refining	$	32,772	$	29,609
Retail		1,838		1,867
Corporate		1,914		1,252

Total consolidated assets	$	36,524	$	32,728

The entire balance of goodwill as of June 30, 2006 and December 31, 2005 has been included in the refining reportable segment.

12. STOCK-BASED COMPENSATION

As discussed in Note 2, on January 1, 2006, we adopted Statement No. 123R, which requires the expensing of the fair value of stock compensation awards. Prior to our adoption of Statement No. 123R, we accounted for our employee stock compensation plans using the intrinsic value method of accounting set forth in APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as permitted by Statement No. 123, “Accounting for Stock-Based Compensation.”

Stock-based compensation expense recognized for the three and six months ended June 30, 2005 was $10 million and $19 million, respectively, net of tax benefits of $5 million and $11 million, respectively. Because we accounted for our employee stock compensation plans using the intrinsic value method,

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

compensation cost was not recognized in the consolidated statements of income for the three or six months ended June 30, 2005 for our fixed stock option plans as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. Had compensation cost for our fixed stock option plans been determined based on the grant-date fair value of awards consistent with the alternative method set forth in Statement No. 123, our net income applicable to common stock, net income and earnings per common share, both with and without dilution, for the three and six months ended June 30, 2005 would have been reduced to the pro forma amounts indicated in the following table (in millions, except per share amounts):


	Three Months Ended			Six Months Ended
	June 30, 2005
Net income applicable to common stock, as reported	$	843		$	1,373
Deduct: Compensation expense on stock options determined under fair value method for all awards, net of related tax effects		(5	)		(9	)

Pro forma net income applicable to common stock	$	838		$	1,364

Earnings per common share:
As reported	$	1.64		$	2.68
Pro forma		1.63			2.66

Net income, as reported	$	847		$	1,381
Deduct: Compensation expense on stock options determined under fair value method for all awards, net of related tax effects		(5	)		(9	)

Pro forma net income	$	842		$	1,372

Earnings per common share – assuming dilution:
As reported	$	1.53		$	2.49
Pro forma		1.52			2.47

Subsequent to the adoption of Statement No. 123R, our total stock-based compensation expense recognized for the three and six months ended June 30, 2006 was $19 million and $34 million, net of tax benefits of $10 million and $18 million, respectively. We adopted the fair value recognition provisions of Statement No. 123R using the modified prospective application. Accordingly, we are recognizing compensation expense for all newly granted stock options and stock options modified, repurchased, or cancelled after January 1, 2006. In addition, compensation cost for the unvested portion of stock options and other awards that were outstanding as of January 1, 2006 is being recognized over the remaining vesting period based on the fair value at date of grant and the attribution approach utilized in determining the pro forma information reflected above.

Upon adoption of Statement No. 123R, compensation expense for stock options granted on or after January 1, 2006 is being recognized on a straight-line basis, and we have changed our attribution approach for new grants that have retirement-eligibility provisions from the nominal vesting period approach to the non-substantive vesting period approach. If the non-substantive vesting period approach

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

had been used by us for awards granted prior to January 1, 2006, the impact on the pro forma net income applicable to common stock and pro forma net income amounts reflected above for the three and six months ended June 30, 2005 would have been less than $1 million and $2 million, respectively, and the impact on net income applicable to common stock and net income for the three and six months ended June 30, 2006, would have been less than $2 million and $3 million, respectively.

We have various fixed and performance-based stock compensation plans under which awards may currently be granted, which are summarized as follows:

•

The 2005 Omnibus Stock Incentive Plan (the OSIP) authorizes the grant of various stock and stock-based awards to our employees and our non-employee directors. Awards available under the OSIP include options to purchase shares of common stock, performance awards that vest upon the achievement of an objective performance goal, and restricted stock which vests over a period determined by our compensation committee. As of June 30, 2006, a total of 19,582,632 shares of our common stock remained available to be awarded under the OSIP.

•

A non-employee director stock option plan provides our non-employee directors automatic grants of stock options to purchase our common stock upon their election to our board of directors and annual grants of stock options upon their continued service on the board. As of June 30, 2006, a total of 278,000 shares of our common stock remained available for issuance under this plan.

•

A restricted stock plan for non-employee directors provides non-employee directors, upon their election to the board of directors, a grant of our common stock valued at $60,000 that vests in three equal annual installments, with similar grants issued after full vesting of prior grants. As of June 30, 2006, a total of 261,458 shares of our common stock remained available to be awarded under this plan.

•

The 2003 Employee Stock Incentive Plan authorizes the grant of various stock and stock-related awards to employees and prospective employees. Awards include options to purchase shares of common stock, performance awards that vest upon the achievement of an objective performance goal, stock appreciation rights, and restricted stock which vests over a period determined by our compensation committee. As of June 30, 2006, a total of 5,490,189 shares of our common stock remained available to be awarded under this plan.

In addition, we formerly maintained other stock option plans under which previously granted stock options remain outstanding. No shares are available to be awarded under these plans.

Each of our current stock-based compensation arrangements is discussed below. The tax benefit realized for tax deductions resulting from exercises and vestings under all of our stock compensation arrangements totaled $183 million and $38 million, respectively, for the six months ended June 30, 2006 and 2005.

Stock Options

Under the terms of our various stock option plans, the exercise price of options granted is not less than the fair market value of our common stock on the date of grant. Stock options become exercisable pursuant to the individual written agreements between the participants and us, usually in three or five equal annual installments beginning one year after the date of grant, with unexercised options generally expiring seven or ten years from the date of grant.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

A summary of the status of our stock option awards is presented in the table below.


	Number of Stock Options		Weighted- Average Exercise Price Per Share		Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value
					(in years)	(in millions)
Outstanding at January 1, 2006	42,242,977		$	13.31
Granted	22,696			59.33
Exercised	(5,035,330	)		10.90
Forfeited	(102,262	)		28.95

Outstanding at June 30, 2006	37,128,081			13.62	5.4	$	1,964

Exercisable at June 30, 2006	26,229,689			8.91	4.6		1,511

There were no significant stock options granted during the six months ended June 30, 2006 and 2005. As of June 30, 2006, there was $65 million of unrecognized compensation cost related to outstanding unvested stock option awards, which is expected to be recognized over a weighted-average period of approximately 1.4 years. The total intrinsic value of stock options exercised during the three months ended June 30, 2006 and 2005 was $146 million and $35 million, respectively, and during the six months ended June 30, 2006 and 2005 was $250 million and $91 million, respectively. Cash received from stock option exercises for the three months ended June 30, 2006 and 2005 was $23 million and $9 million, respectively, and for the six months ended June 30, 2006 and 2005 was $41 million and $22 million, respectively.

Restricted Stock

Restricted stock is granted to employees and non-employee directors. Restricted stock vests in accordance with individual written agreements between the participants and us, usually in equal annual installments over a period of five years beginning one year after the date of grant. A summary of the status of our restricted stock awards is presented in the table below.


	Number of Shares		Weighted- Average Grant-Date Fair Value Per Share
Nonvested shares at January 1, 2006	1,563,678		$	27.48
Granted	12,578			61.89
Vested	(43,538	)		17.02
Forfeited	(7,940	)		38.10

Nonvested shares at June 30, 2006	1,524,778			28.00

As of June 30, 2006, there was $37 million of unrecognized compensation cost related to outstanding unvested restricted stock awards. That cost is expected to be recognized over a weighted-average period of approximately four years.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Performance Awards

We grant performance awards to certain key employees which vest only upon the achievement of an objective performance measure. Performance awards granted are subject to vesting in three annual amounts beginning one year after the date of grant. The portion of each year’s amount that vests is determined by our total shareholder return over a rolling three-year period compared to the total shareholder return of a defined peer group for the same time period.

During the six months ended June 30, 2006, 78,660 performance awards were granted and no awards were forfeited. The weighted-average grant-date fair value of these awards was $58.81 per share, which was based on the market price of our common stock on the date of grant reduced by the discounted present value of expected dividends over the vesting period. The total fair value of performance awards that vested during the six months ended June 30, 2006 and 2005 was $193 million and $14 million, respectively.

Restricted Stock Units

As of June 30, 2006, 671,354 unvested restricted stock units were outstanding. Restricted stock units vest in equal annual amounts over a three-year or five-year period beginning one year after the date of grant. These restricted stock units are payable in cash based on the price of our common stock on the date of vesting, and therefore they are accounted for as liability-based awards under Statement No. 123R. No restricted stock units were granted or forfeited during the six months ended June 30, 2006. Based on the price of our common stock on June 30, 2006, the fair value of the unvested restricted stock units was $45 million, of which $23 million was recognized as of June 30, 2006.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost related to our defined benefit plans were as follows for the three and six months ended June 30, 2006 and 2005 (in millions):


	Pension Plans						Other Postretirement Benefit Plans
	2006			2005			2006			2005
Three months ended June 30:
Components of net periodic benefit cost:
Service cost	$	25		$	17		$	4		$	2
Interest cost		16			13			6			4
Expected return on plan assets		(15	)		(11	)		—			—
Amortization of:
Prior service cost		—			—			(3	)		(1	)
Net loss		4			2			1			2

Net periodic benefit cost	$	30		$	21		$	8		$	7

Six months ended June 30:
Components of net periodic benefit cost:
Service cost	$	50		$	33		$	7		$	4
Interest cost		32			27			12			8
Expected return on plan assets		(29	)		(23	)		—			—
Amortization of:
Prior service cost		1			1			(5	)		(3	)
Net loss		7			4			3			4

Net periodic benefit cost	$	61		$	42		$	17		$	13

We expect to contribute approximately $145 million to our qualified pension plans during 2006, although our minimum required contribution to our qualified pension plans during 2006 under the Employee Retirement Income Security Act is less than $5 million. For the six months ended June 30, 2006 and 2005, we contributed $45 million and $28 million, respectively, to our qualified pension plans.

14. COMMITMENTS AND CONTINGENCIES

Accounts Receivable Sales Facility

As of June 30, 2006, 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. As of June 30, 2006 and December 31, 2005, the amount of eligible receivables sold to the third-party financial institutions was $1 billion.

Contingent Earn-Out Agreements

In the second quarter of 2006 and 2005, we made earn-out contingency payments of $26 million and $35 million, respectively, to Salomon Inc in connection with our acquisition of Basis Petroleum, Inc., which were recorded as increases to “goodwill.” In both January 2006 and January 2005, we made previously accrued earn-out payments of $50 million related to the acquisition of the St. Charles Refinery.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table summarizes the aggregate payments we have made through June 30, 2006 and payment limitations related to the following acquisitions (in millions). The amounts reflected for the Delaware City Refinery represent amounts applicable only to the throughput/margin earn-out contingency since the earn-out contingency related to the refinery’s gasification facility expired during the second quarter of 2006 with no payment required. The amounts reflected represent only amounts for which we are potentially liable subsequent to the Premcor Acquisition.


	Aggregate Payments Made Through June 30, 2006		Annual Maximum Limit		Aggregate Limit
Basis Petroleum, Inc.	$	200	$	35	$	200
St. Charles Refinery		100		50		175
Delaware City Refinery		—		25		50

In July 2006, we made a previously accrued payment of $25 million related to the Delaware City Refinery contingent earn-out agreement.

Insurance Recoveries

During the third quarter of 2005, certain of our refineries experienced property damage and business interruption losses associated with Hurricanes Katrina and Rita. As a result of these losses, we have submitted claims to our insurance carriers under our insurance policies. As of June 30, 2006, we have recorded a $16 million receivable related to our property damage claims, which was recorded as a reduction of repair and maintenance expense. During the second quarter of 2006, we received $13 million related to our business interruption insurance claims which was recorded in “accrued expenses” in the consolidated balance sheet as of June 30, 2006 to defer the recognition of income pending further review by the insurance carriers. During July 2006, an additional $20 million was received related to the business interruption insurance claims.

Environmental Matters

The Environmental Protection Agency’s (EPA) Tier II Gasoline and Diesel Standards. The EPA’s Tier II gasoline and diesel standards, adopted under the Clean Air Act, phase in limitations on the sulfur content of gasoline (which began in 2004) and diesel fuel sold to highway consumers (which began in June 2006). All of our refineries have implemented strategies to comply with the Tier II gasoline and diesel standards. We estimate that capital expenditures of approximately $1.3 billion will be required from 2006 through 2008 for our refineries to meet the Tier II specifications. This estimate includes amounts related to projects at three refineries to provide hydrogen necessary for removing sulfur from gasoline and diesel. We expect these cost estimates to change as additional engineering is completed and progress is made toward completion of these projects.

EPA’s Section 114 Initiative. Prior to the Premcor Acquisition, our Port Arthur, Memphis and Lima Refineries received information requests from the EPA pursuant to Section 114 of the Clean Air Act as part of the EPA’s National Petroleum Refinery Initiative to reduce air emissions. We have reached a tentative settlement with the EPA concerning these three refineries and are working to finalize the terms of a consent decree with the EPA. We expect to incur penalties and related expenses in connection with a potential settlement, but we believe that any settlement penalties will be immaterial to our results of operations and financial position. We expect the potential settlement to require capital improvements or changes in operating parameters, or both, at the three refineries.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Litigation

MTBE Litigation

As of August 1, 2006, we were named as a defendant in 71 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. All but one of the cases are pending in federal court and will be 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). Valero agreed to settle the one remaining state court case for an immaterial amount, but it has not yet been dismissed. Four of the cases Valero is involved in have been selected by the court as “focus cases” for discovery and pre-trial motions. Two of the cases, Suffolk County Water Authority et al. and United Water New York, have been set for trial in September 2007. 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.

Rosolowski v. Clark Refining & Marketing, Inc., et al., Judicial Circuit Court, Cook County, Illinois (Case No. 95-L 014703). We assumed this class action lawsuit in the Premcor Acquisition. This lawsuit, filed October 11, 1995, relates in part to a release to the atmosphere of spent catalyst containing low levels of heavy metals from the now-closed Blue Island, Illinois refinery on October 7, 1994. The release resulted in the temporary evacuation of certain areas near the refinery. The case was certified as a class action in 2000 with three classes: (i) persons purportedly affected by the October 7, 1994 catalyst release, but with no permanent health effects; (ii) persons with medical expenses for dependents purportedly affected by the October 7, 1994 release; and (iii) local residents claiming property damage or loss of use and enjoyment of their property over a period of several years. Following three weeks of trial, on November 21, 2005, the jury returned a verdict for the plaintiffs of $80.1 million in compensatory damages and $40 million in punitive damages. In January 2006, we filed motions for new trial, remittitur and judgment notwithstanding the verdict, citing, among other things, misconduct by plaintiffs’ counsel and improper class certification. We plan to pursue all of our appeals remedies, and we believe that we will prevail in reversing the verdict or reducing the jury’s award of damages. 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 the appeal, we believe that it is reasonably possible (as defined in FASB Statement No. 5) that we may suffer a loss in this matter in excess of the amount accrued, but we do not believe that this matter will have a material effect on our financial position or results of operations.

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 Premcor Acquisition 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:

•

9.25% senior notes due February 2010,

•

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 for the periods subsequent to the Premcor Acquisition. The accounts for all companies reflected herein are presented using the equity method of accounting for investments in subsidiaries.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet as of June 30, 2006

(unaudited, in millions)


	Valero Energy Corporation			PRG			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	585		$	1		$	351		$	—		$	937
Restricted cash		22			2			7			—			31
Receivables, net		—			96			4,138			—			4,234
Inventories		—			348			4,278			—			4,626
Income tax receivable		—			1			20			(21	)		—
Deferred income taxes		—			—			176			—			176
Prepaid expenses and other		—			10			160			—			170

Total current assets		607			458			9,130			(21	)		10,174

Property, plant and equipment, at cost		—			6,854			16,039			—			22,893
Accumulated depreciation		—			(162	)		(2,743	)		—			(2,905	)

Property, plant and equipment, net		—			6,692			13,296			—			19,988

Intangible assets, net		—			3			290			—			293
Goodwill		—			1,918			2,393			—			4,311
Investment in Valero Energy affiliates		4,287			1,034			588			(5,909	)		—
Long-term notes receivable from affiliates		18,065			—			—			(18,065	)		—
Investment in Valero L.P.		—			—			481			—			481
Deferred income tax receivable		—			162			—			(162	)		—
Deferred charges and other assets, net		117			224			936			—			1,277

Total assets	$	23,076		$	10,491		$	27,114		$	(24,157	)	$	36,524

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Short-term debt	$	—		$	—		$	45		$	—		$	45
Current portion of long-term debt and capital lease obligations		227			—			3			—			230
Accounts payable		73			353			6,476			—			6,902
Accrued expenses		64			83			317			—			464
Taxes other than income taxes		—			18			580			—			598
Income taxes payable		578			—			—			(21	)		557
Deferred income taxes		39			272			—			—			311

Total current liabilities		981			726			7,421			(21	)		9,107

Long-term debt and capital lease obligations, less current portion		3,333			1,517			63			—			4,913

Long-term notes payable to affiliates		—			7,367			10,698			(18,065	)		—

Deferred income taxes		1,332			—			2,982			(162	)		4,152

Other long-term liabilities		666			293			629			—			1,588

Stockholders’ equity:
Preferred stock		53			—			—			—			53
Common stock		6			—			2			(2	)		6
Additional paid-in capital		7,839			100			1,621			(1,721	)		7,839
Treasury stock		(868	)		—			—			—			(868	)
Retained earnings		9,331			488			3,698			(4,186	)		9,331
Accumulated other comprehensive income		403			—			—			—			403

Total stockholders’ equity		16,764			588			5,321			(5,909	)		16,764

Total liabilities and stockholders’ equity	$	23,076		$	10,491		$	27,114		$	(24,157	)	$	36,524

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet as of December 31, 2005

(in millions)


	Valero Energy Corporation			PRG			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	11		$	5		$	420		$	—		$	436
Restricted cash		22			2			6			—			30
Receivables, net		1			447			3,494			(378	)		3,564
Inventories		—			380			3,659			—			4,039
Deferred income taxes		—			—			195			(53	)		142
Prepaid expenses and other		—			7			58			—			65

Total current assets		34			841			7,832			(431	)		8,276

Property, plant and equipment, at cost		—			4,821			15,567			—			20,388
Accumulated depreciation		—			(43	)		(2,489	)		—			(2,532	)

Property, plant and equipment, net		—			4,778			13,078			—			17,856

Intangible assets, net		—			4			294			—			298
Goodwill		—			2,528			2,398			—			4,926
Investment in Valero Energy affiliates		1,697			705			100			(2,502	)		—
Long-term notes receivable from affiliates		17,981			—			—			(17,981	)		—
Investment in Valero L.P.		—			—			327			—			327
Deferred charges and other assets, net		118			133			836			(42	)		1,045

Total assets	$	19,830		$	8,989		$	24,865		$	(20,956	)	$	32,728

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	220		$	—		$	2		$	—		$	222
Accounts payable		96			374			5,093			—			5,563
Accrued expenses		71			116			394			—			581
Taxes other than income taxes		—			23			572			—			595
Income taxes payable		53			—			364			(378	)		39
Deferred income taxes		—			358			—			(53	)		305

Total current liabilities		440			871			6,425			(431	)		7,305

Long-term debt and capital lease obligations, less current portion		3,584			1,525			47			—			5,156

Long-term notes payable to affiliates		—			5,073			12,908			(17,981	)		—

Deferred income taxes		53			1,212			2,350			—			3,615

Other long-term liabilities		661			208			733			—			1,602

Stockholders’ equity:
Preferred stock		68			—			—			—			68
Common stock		6			—			2			(2	)		6
Additional paid-in capital		8,206			100			1,811			(1,953	)		8,164
Treasury stock		(196	)		—			—			—			(196	)
Retained earnings		6,673			—			589			(589	)		6,673
Accumulated other comprehensive income		335			—			—			—			335

Total stockholders’ equity		15,092			100			2,402			(2,544	)		15,050

Total liabilities and stockholders’ equity	$	19,830		$	8,989		$	24,865		$	(20,956	)	$	32,728

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income for the Three Months Ended June 30, 2006

(unaudited, in millions)


	Valero Energy Corporation			PRG			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues	$	—		$	8,396		$	26,462		$	(8,077	)	$	26,781

Costs and expenses:
Cost of sales		—			7,662			22,715			(8,077	)		22,300
Refining operating expenses		—			233			716			—			949
Retail selling expenses		—			—			204			—			204
General and administrative expenses		2			11			158			—			171
Depreciation and amortization expense		—			104			189			—			293

Total costs and expenses		2			8,010			23,982			(8,077	)		23,917

Operating income (loss)		(2	)		386			2,480			—			2,864
Equity in earnings of subsidiaries		1,747			176			284			(2,207	)		—
Equity in earnings of Valero L.P.		—			—			10			—			10
Other income (expense), net		410			(23	)		437			(829	)		(5	)
Interest and debt expense:
Incurred		(190	)		(237	)		(495	)		829			(93	)
Capitalized		—			17			30			—			47

Income before income tax expense		1,965			319			2,746			(2,207	)		2,823
Income tax expense (1)		68			35			823			—			926

Net income		1,897			284			1,923			(2,207	)		1,897
Preferred stock dividends		1			—			—			—			1

Net income applicable to common stock	$	1,896		$	284		$	1,923		$	(2,207	)	$	1,896

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

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income for the Six Months Ended June 30, 2006

(unaudited, in millions)


	Valero Energy Corporation			PRG			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues	$	—		$	14,006		$	47,180		$	(13,464	)	$	47,722

Costs and expenses:
Cost of sales		—			12,803			41,043			(13,464	)		40,382
Refining operating expenses		—			456			1,419			—			1,875
Retail selling expenses		—			—			393			—			393
General and administrative expenses		2			26			294			—			322
Depreciation and amortization expense		—			147			406			—			553

Total costs and expenses		2			13,432			43,555			(13,464	)		43,525

Operating income (loss)		(2	)		574			3,625			—			4,197
Equity in earnings of subsidiaries		2,470			328			488			(3,286	)		—
Equity in earnings of Valero L.P.		—			—			22			—			22
Other income (expense), net		721			(4	)		578			(1,300	)		(5	)
Interest and debt expense:
Incurred		(278	)		(396	)		(815	)		1,300			(189	)
Capitalized		—			31			53			—			84

Income before income tax expense		2,911			533			3,951			(3,286	)		4,109
Income tax expense (1)		165			45			1,153			—			1,363

Net income		2,746			488			2,798			(3,286	)		2,746
Preferred stock dividends		2			—			—			—			2

Net income applicable to common stock	$	2,744		$	488		$	2,798		$	(3,286	)	$	2,744

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

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2006

(unaudited, in millions)


	Valero Energy Corporation			PRG			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	897		$	370		$	2,556		$	—		$	3,823

Cash flows from investing activities:
Capital expenditures		—			(513	)		(1,075	)		—			(1,588	)
Deferred turnaround and catalyst costs		—			(118	)		(269	)		—			(387	)
Contingent payments in connection with acquisitions		—			—			(76	)		—			(76	)
Net intercompany receipts		1,030			—			—			(1,030	)		—
Other investing activities, net		—			—			18			—			18

Net cash provided by (used in) investing activities		1,030			(631	)		(1,402	)		(1,030	)		(2,033	)

Cash flows from financing activities:
Long-term note repayments		(220	)		(1	)		—			—			(221	)
Bank credit agreements:
Borrowings		8			—			493			—			501
Repayments		(8	)		—			(431	)		—			(439	)
Termination of interest rate swaps		(54	)		—			—			—			(54	)
Purchase of treasury stock		(1,187	)		—			—			—			(1,187	)
Benefit from tax deduction in excess of recognized stock-based compensation cost		130			—			—			—			130
Net intercompany borrowings (repayments)		—			258			(1,288	)		1,030			—
Other financing activities, net		(22	)		—			(1	)		—			(23	)

Net cash provided by (used in) financing activities		(1,353	)		257			(1,227	)		1,030			(1,293	)

Effect of foreign exchange rate changes on cash		—			—			4			—			4

Net increase (decrease) in cash and temporary cash investments		574			(4	)		(69	)		—			501
Cash and temporary cash investments at beginning of period		11			5			420			—			436

Cash and temporary cash investments at end of period	$	585		$	1		$	351		$	—		$	937

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:

•

the synergies and accretion to reported earnings estimated to result from the Premcor Acquisition;

•

various actions to be taken or requirements to be met in connection with integrating Valero and Premcor after the Premcor Acquisition;

•

our revenue, income and operations after the Premcor Acquisition;

•

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 discounts, 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 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:

•

expected cost savings from the Premcor Acquisition may not be fully realized or realized within the expected time frame, and costs or expenses relating to the Premcor Acquisition may be higher than expected;

•

revenues or margins following the Premcor Acquisition may be lower than expected;

•

costs or difficulties related to the integration of the businesses of Valero and Premcor may be greater than expected;

•

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

•

the level of foreign imports of refined products;

•

accidents or other unscheduled shutdowns affecting our refineries, machinery, pipelines or equipment, or those of our suppliers or customers;

•

changes in the cost or availability of transportation for feedstocks and refined products;

•

the price, availability and acceptance of alternative fuels and alternative-fuel vehicles;

•

delay of, cancellation of or failure to implement planned capital projects and realize the various assumptions and benefits projected for such projects or cost overruns in constructing such planned capital projects;

•

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.

Overview

Our operations are affected by:

•

company-specific factors, primarily refinery utilization rates (including unplanned downtime) and refinery maintenance turnarounds;

•

seasonal factors, such as the demand for refined products; and

•

industry factors, such as movements in and the level of crude oil prices, including the effect of quality differential between grades of crude oil, the demand for and prices of refined products, industry supply capacity and competitor refinery maintenance turnarounds.

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.” Since up to 70% 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 discount.” The strong industry fundamentals we experienced throughout 2005 continued during the first and second quarters of 2006. During the first and second quarters of 2006, heavy industry-wide turnaround activity, the implementation of more restrictive sulfur regulations on gasoline and diesel, increased use of ethanol and decreased use of MTBE in the reformulated gasoline pool, and limited capacity expansions due to the high cost of compliance with environmental regulations resulted in tighter supplies of refined products and continuing strong margins. We also continued to benefit from the addition of the four former Premcor refineries, which generated approximately $870 million of operating income with average throughput volumes of 831,000 barrels per day during the second quarter of 2006 and $1.3 billion of operating income with average throughput volumes of 784,000 barrels per day for the first six months of 2006. However, during the first and second quarters of 2006, we had significant unplanned downtime at several of our refineries that partially offset these positive factors. The incremental throughput volumes from the Premcor refineries were partially offset by reduced throughput volumes resulting from this downtime.

Gasoline and distillate margins were significantly higher during the second quarter and first six months of 2006 than the margins realized in the comparable periods of 2005. The stronger gasoline and distillate margins, combined with wider sour crude oil discounts and the higher throughput volumes due to the Premcor Acquisition, contributed to a significant increase in operating results in the second quarter and first six months of 2006 compared to the prior year periods. Net income for the second quarter of 2006 was more than twice the net income for the second quarter of 2005 and net income for the first six months of 2006 was 99% higher than the net income reported for the first six months of 2005. We reported net income of $1.9 billion, or $2.98 per share, for the second quarter of 2006, compared to $847 million, or $1.53 per share, for the second quarter of 2005, and net income of $2.7 billion, or $4.29 per share, for the first six months of 2006 compared to $1.4 billion, or $2.49 per share, for the first six months of 2005. We expect the strong industry fundamentals and positive financial results to continue, as slower than anticipated growth in global refining capacity, tighter fuel specifications and continued demand growth is expected to keep the supply/demand balance for refined products tight for the foreseeable future.

RESULTS OF OPERATIONS

Second Quarter 2006 Compared to Second Quarter 2005

Financial Highlights

(millions of dollars, except per share amounts)


	Three Months Ended June 30,
	2006 (a)			2005			Change
Operating revenues (b)	$	26,781		$	18,032		$	8,749

Costs and expenses:
Cost of sales (b)		22,300			15,679			6,621
Refining operating expenses		949			564			385
Retail selling expenses		204			182			22
General and administrative expenses		171			112			59
Depreciation and amortization expense:
Refining		262			163			99
Retail		21			19			2
Corporate		10			8			2

Total costs and expenses		23,917			16,727			7,190

Operating income		2,864			1,305			1,559
Equity in earnings of Valero L.P.		10			10			—
Other expense, net		(5	)		(13	)		8
Interest and debt expense:
Incurred		(93	)		(71	)		(22	)
Capitalized		47			10			37

Income before income tax expense		2,823			1,241			1,582
Income tax expense		926			394			532

Net income		1,897			847			1,050
Preferred stock dividends		1			4			(3	)

Net income applicable to common stock	$	1,896		$	843		$	1,053

Earnings per common share – assuming dilution	$	2.98		$	1.53		$	1.45

See the footnote references on page 38.

Operating Highlights

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


	Three Months Ended June 30,
	2006 (a)			2005			Change
Refining:
Operating income	$	2,999		$	1,375		$	1,624
Throughput margin per barrel (c)	$	15.44		$	10.25		$	5.19
Operating costs per barrel:
Refining operating expenses	$	3.48		$	2.75		$	0.73
Depreciation and amortization		0.96			0.79			0.17

Total operating costs per barrel	$	4.44		$	3.54		$	0.90

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		674			482			192
Medium/light sour crude		641			568			73
Acidic sweet crude		51			106			(55	)
Sweet crude		880			559			321
Residuals		278			184			94
Other feedstocks		153			137			16

Total feedstocks		2,677			2,036			641
Blendstocks and other		320			218			102

Total throughput volumes		2,997			2,254			743

Yields (thousand barrels per day):
Gasolines and blendstocks		1,443			1,083			360
Distillates		926			664			262
Petrochemicals		82			64			18
Other products (d)		542			449			93

Total yields		2,993			2,260			733

Retail – U.S.:
Operating income	$	24		$	34		$	(10	)
Company-operated fuel sites (average)		988			1,025			(37	)
Fuel volumes (gallons per day per site)		4,916			4,959			(43	)
Fuel margin per gallon	$	0.145		$	0.161		$	(0.016	)
Merchandise sales	$	251		$	246		$	5
Merchandise margin (percentage of sales)		30.5	%		29.7	%		0.8	%
Margin on miscellaneous sales	$	44		$	30		$	14
Retail selling expenses	$	145		$	131		$	14
Depreciation and amortization expense	$	15		$	13		$	2

Retail – Canada:
Operating income	$	22		$	16		$	6
Fuel volumes (thousand gallons per day)		3,114			3,108			6
Fuel margin per gallon	$	0.237		$	0.197		$	0.040
Merchandise sales	$	43		$	37		$	6
Merchandise margin (percentage of sales)		28.0	%		25.8	%		2.2	%
Margin on miscellaneous sales	$	7		$	7		$	—
Retail selling expenses	$	59		$	51		$	8
Depreciation and amortization expense	$	6		$	6		$	—

See the footnote references on page 38.

Refining Operating Highlights by Region (e)

(millions of dollars, except per barrel amounts)


	Three Months Ended June 30,
	2006 (a)		2005		Change
Gulf Coast:
Operating income	$	1,715	$	838	$	877
Throughput volumes (thousand barrels per day) (f)		1,589		1,285		304
Throughput margin per barrel (c)	$	15.92	$	10.51	$	5.41
Operating costs per barrel:
Refining operating expenses	$	3.28	$	2.61	$	0.67
Depreciation and amortization		0.78		0.73		0.05

Total operating costs per barrel	$	4.06	$	3.34	$	0.72

Mid-Continent (g):
Operating income	$	582	$	114	$	468
Throughput volumes (thousand barrels per day) (f)		584		263		321
Throughput margin per barrel (c)	$	14.91	$	8.53	$	6.38
Operating costs per barrel:
Refining operating expenses	$	2.89	$	3.19	$	(0.30	)
Depreciation and amortization		1.06		0.59		0.47

Total operating costs per barrel	$	3.95	$	3.78	$	0.17

Northeast:
Operating income	$	291	$	152	$	139
Throughput volumes (thousand barrels per day) (f)		520		391		129
Throughput margin per barrel (c)	$	11.73	$	7.28	$	4.45
Operating costs per barrel:
Refining operating expenses	$	4.34	$	2.21	$	2.13
Depreciation and amortization		1.26		0.79		0.47

Total operating costs per barrel	$	5.60	$	3.00	$	2.60

West Coast:
Operating income	$	411	$	271	$	140
Throughput volumes (thousand barrels per day)		304		315		(11	)
Throughput margin per barrel (c)	$	20.29	$	14.30	$	5.99
Operating costs per barrel:
Refining operating expenses	$	4.20	$	3.63	$	0.57
Depreciation and amortization		1.24		1.22		0.02

Total operating costs per barrel	$	5.44	$	4.85	$	0.59

See the footnote references on page 38.

Average Market Reference Prices and Differentials (h)

(dollars per barrel)


	Three Months Ended June 30,
	2006		2005		Change
Feedstocks:
West Texas Intermediate (WTI) crude oil	$	70.40	$	53.03	$	17.37
WTI less sour crude oil at U.S. Gulf Coast (i)		7.24		6.71		0.53
WTI less Alaska North Slope (ANS) crude oil		1.62		2.99		(1.37	)
WTI less Maya crude oil		15.68		13.04		2.64
Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		20.01		9.64		10.37
No. 2 fuel oil less WTI		11.78		9.61		2.17
Propylene less WTI		10.54		2.61		7.93
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		19.03		10.43		8.60
Low-sulfur diesel less WTI		20.73		13.67		7.06
U.S. Northeast:
Conventional 87 gasoline less WTI		16.94		7.90		9.04
No. 2 fuel oil less WTI		11.73		10.60		1.13
Lube oils less WTI		49.81		30.73		19.08
U.S. West Coast:
CARBOB 87 gasoline less ANS		33.11		21.46		11.65
Low-sulfur diesel less ANS		27.53		20.21		7.32

The following notes relate to references on pages 35 through 38.

(a)	Includes the operations related to the Premcor Acquisition, which was effective on September 1, 2005.

(b)

Operating revenues and cost of sales both include approximately $1.6 billion for the three months ended June 30, 2005 related to certain crude oil buy/sell arrangements, which involve linked purchases and sales related to crude oil contracts entered into to address location, quality or grade requirements. Commencing January 1, 2006, we adopted EITF Issue No. 04-13 which requires that such buy/sell arrangements be accounted for as one transaction, thereby resulting in no recognition of revenues and cost of sales for these transactions.

(c)	Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.

(d)	Other products primarily include gas oils, No. 6 fuel oil, petroleum coke and asphalt.

(e)

The regions reflected herein contain the following refineries subsequent to the Premcor Acquisition: 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, Memphis and Lima Refineries; the Northeast refining region includes the Quebec, Paulsboro and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries. The Mid-Continent region also included the Denver Refinery prior to its disposition on May 31, 2005.

(f)	Throughput volumes for the Gulf Coast, Mid-Continent and Northeast regions for the three months ended June 30, 2006 include 302,000, 321,000 and 208,000 barrels per day, respectively, related to the operations of the refineries acquired from Premcor on September 1, 2005.

(g)

For the three months ended June 30, 2005, the information presented for the Mid-Continent region includes the operations of the Denver Refinery, which was sold on May 31, 2005 to Suncor Energy (U.S.A.) Inc. Throughput volumes for the Mid-Continent region for the second quarter of 2005 include 23,000 barrels per day related to the Denver Refinery.

(h)

The average market reference prices and differentials, with the exception of the propylene and lube oil differentials, are based on posted prices from Platts Oilgram. The propylene differential is based on posted propylene prices in Chemical Market Associates, Inc. and the lube oil differential is based on Exxon Mobil Corporation postings provided by Independent Commodity Information Services-London Oil Reports. The average market reference prices and differentials are presented to provide users of the consolidated financial statements with economic indicators that significantly affect our operations and profitability.

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

General

Operating revenues increased 49% for the second quarter of 2006 compared to the second quarter of 2005 primarily as a result of significantly higher refined product prices combined with additional throughput volumes from the former Premcor refinery operations. Operating income of $2.9 billion and net income of $1.9 billion more than doubled from the second quarter of 2005 to the second quarter of 2006 primarily due to a $1.6 billion increase in refining segment operating income, partially offset by a $61 million increase in general and administrative expenses (including corporate depreciation and amortization expense).

Refining

Operating income for our refining segment increased from $1.4 billion for the second quarter of 2005 to $3.0 billion for the second quarter of 2006, resulting from a 33% increase in throughput volumes and an increase in refining throughput margin of $5.19 per barrel, or 51%, partially offset by increased refining operating expenses (including depreciation and amortization expense) of $484 million.

Refining total throughput margin for the second quarter of 2006 increased primarily due to the following factors:

•

Throughput volumes increased 743,000 barrels per day in the second quarter of 2006 compared to the second quarter of 2005 due to the 831,000 barrel per day incremental throughput from the four former Premcor refineries, offset to some extent by the sale of the Denver Refinery in 2005 and significant planned and unplanned downtime at several of our refineries.

•

Gasoline and distillate margins increased significantly in all of our refining regions in the second quarter of 2006 compared to the second quarter of 2005, with gasoline margins more than doubling in the Gulf Coast and Northeast regions. The continued strength of refined product margins for the second quarter of 2006 was primarily due to increased foreign and U.S. demand, limited capacity additions, major industry turnaround activity, and continuing outages from last season’s hurricanes.

•

With the exception of the discount on our Alaska North Slope crude oil in the West Coast region, discounts on sour crude oil feedstocks during the second quarter of 2006 improved from the already strong discounts in the second quarter of 2005 due to continued ample supplies of sour crude oils and heavy sour residual fuel oils on the world market. Discounts 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, particularly in Asia, which has resulted in higher utilization rates by refineries that require sweet crude oil as feedstock.

Partially offsetting the above increases in throughput margin were lower margins on other refined products such as petroleum coke and sulfur due to a significant increase in the price of crude oil from the second quarter of 2005 to the second quarter of 2006.

Refining operating expenses, excluding depreciation and amortization expense, were 68% higher for the quarter ended June 30, 2006 compared to the quarter ended June 30, 2005, due primarily to the Premcor Acquisition on September 1, 2005. Excluding the effect of the Premcor Acquisition, operating expenses increased 16% due mainly to increases in maintenance expense, employee compensation and related benefits, energy costs, catalyst and chemicals, and outside services. Refining depreciation and amortization expense increased 61% from the second quarter of 2005 to the second quarter of 2006 primarily due to the Premcor Acquisition, increased turnaround and catalyst amortization, and the implementation of new capital projects.

Retail

Retail operating income was $46 million for the quarter ended June 30, 2006 compared to $50 million for the quarter ended June 30, 2005. This 8% decrease in operating income was primarily due to increased selling expenses in our U.S. retail operations resulting mainly from higher credit card processing fees attributable to higher retail fuel prices. The decreased operating income resulting from U.S. retail operations was partially offset by higher fuel margins in the Canadian retail operations.

Corporate Expenses and Other

General and administrative expenses, including corporate depreciation and amortization expense, increased $61 million from the second quarter of 2005 to the second quarter of 2006. The increase was primarily due to increases in employee compensation and benefits, stock-based compensation expense, charitable contributions, and legal and regulatory costs, as well as expenses in 2006 resulting from the Premcor Acquisition.

Interest and debt expense incurred increased from the second quarter of 2005 to the second quarter of 2006 primarily as a result of interest expense incurred on the debt assumed in the Premcor Acquisition. However, the increased interest incurred was more than offset by increased capitalized interest due to an increase in capital projects, including those at the four former Premcor refineries.

Income tax expense increased $532 million from the second quarter of 2005 to the second quarter of 2006 mainly as a result of higher operating income. Our effective tax rate for the quarter ended June 30, 2006 increased from the quarter ended June 30, 2005 as a lower percentage of our pre-tax income was contributed by the Aruba Refinery, the operations of which are non-taxable in Aruba through December 31, 2010. This increase in the effective tax rate was partially offset by the effect of new tax legislation in both Texas and Canada in the second quarter of 2006.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Financial Highlights

(millions of dollars, except per share amounts)


	Six Months Ended June 30,
	2006 (a)			2005			Change
Operating revenues (b)	$	47,722		$	32,985		$	14,737

Costs and expenses:
Cost of sales (b)		40,382			28,751			11,631
Refining operating expenses		1,875			1,144			731
Retail selling expenses		393			354			39
General and administrative expenses		322			216			106
Depreciation and amortization expense:
Refining		493			316			177
Retail		41			37			4
Corporate		19			16			3

Total costs and expenses		43,525			30,834			12,691

Operating income		4,197			2,151			2,046
Equity in earnings of Valero L.P.		22			19			3
Other expense, net		(5	)		(15	)		10
Interest and debt expense:
Incurred		(189	)		(145	)		(44	)
Capitalized		84			21			63

Income before income tax expense		4,109			2,031			2,078
Income tax expense		1,363			650			713

Net income		2,746			1,381			1,365
Preferred stock dividends		2			8			(6	)

Net income applicable to common stock	$	2,744		$	1,373		$	1,371

Earnings per common share – assuming dilution	$	4.29		$	2.49		$	1.80

See the footnote references on page 44.

Operating Highlights

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


	Six Months Ended June 30,
	2006 (a)			2005			Change
Refining:
Operating income	$	4,471		$	2,319		$	2,152
Throughput margin per barrel (c)	$	12.84		$	9.33		$	3.51
Operating costs per barrel:
Refining operating expenses	$	3.52		$	2.83		$	0.69
Depreciation and amortization		0.92			0.78			0.14

Total operating costs per barrel	$	4.44		$	3.61		$	0.83

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		719			501			218
Medium/light sour crude		597			582			15
Acidic sweet crude		58			106			(48	)
Sweet crude		878			552			326
Residuals		217			150			67
Other feedstocks		168			129			39

Total feedstocks		2,637			2,020			617
Blendstocks and other		307			217			90

Total throughput volumes		2,944			2,237			707

Yields (thousand barrels per day):
Gasolines and blendstocks		1,424			1,046			378
Distillates		917			674			243
Petrochemicals		85			68			17
Other products (d)		518			457			61

Total yields		2,944			2,245			699

Retail – U.S.:
Operating income	$	24		$	21		$	3
Company-operated fuel sites (average)		992			1,031			(39	)
Fuel volumes (gallons per day per site)		4,899			4,799			100
Fuel margin per gallon	$	0.122		$	0.116		$	0.006
Merchandise sales	$	470		$	460		$	10
Merchandise margin (percentage of sales)		30.1	%		29.5	%		0.6	%
Margin on miscellaneous sales	$	81		$	58		$	23
Retail selling expenses	$	278		$	251		$	27
Depreciation and amortization expense	$	28		$	26		$	2

Retail – Canada:
Operating income	$	43		$	43		$	—
Fuel volumes (thousand gallons per day)		3,199			3,228			(29	)
Fuel margin per gallon	$	0.231		$	0.213		$	0.018
Merchandise sales	$	79		$	70		$	9
Merchandise margin (percentage of sales)		28.0	%		25.7	%		2.3	%
Margin on miscellaneous sales	$	15		$	15		$	—
Retail selling expenses	$	115		$	103		$	12
Depreciation and amortization expense	$	13		$	11		$	2

See the footnote references on page 44.

Refining Operating Highlights by Region (e)

(millions of dollars, except per barrel amounts)


	Six Months Ended June 30,
	2006 (a)		2005		Change
Gulf Coast:
Operating income	$	2,718	$	1,466	$	1,252
Throughput volumes (thousand barrels per day) (f)		1,550		1,269		281
Throughput margin per barrel (c)	$	13.73	$	9.76	$	3.97
Operating costs per barrel:
Refining operating expenses	$	3.23	$	2.69	$	0.54
Depreciation and amortization		0.81		0.69		0.12

Total operating costs per barrel	$	4.04	$	3.38	$	0.66

Mid-Continent (g):
Operating income	$	683	$	149	$	534
Throughput volumes (thousand barrels per day) (f)		544		277		267
Throughput margin per barrel (c)	$	11.06	$	6.75	$	4.31
Operating costs per barrel:
Refining operating expenses	$	3.24	$	3.15	$	0.09
Depreciation and amortization		0.89		0.64		0.25

Total operating costs per barrel	$	4.13	$	3.79	$	0.34

Northeast:
Operating income	$	470	$	225	$	245
Throughput volumes (thousand barrels per day) (f)		548		384		164
Throughput margin per barrel (c)	$	10.05	$	6.46	$	3.59
Operating costs per barrel:
Refining operating expenses	$	4.22	$	2.41	$	1.81
Depreciation and amortization		1.08		0.80		0.28

Total operating costs per barrel	$	5.30	$	3.21	$	2.09

West Coast:
Operating income	$	600	$	479	$	121
Throughput volumes (thousand barrels per day)		302		307		(5	)
Throughput margin per barrel (c)	$	16.50	$	13.51	$	2.99
Operating costs per barrel:
Refining operating expenses	$	4.24	$	3.64	$	0.60
Depreciation and amortization		1.28		1.24		0.04

Total operating costs per barrel	$	5.52	$	4.88	$	0.64

See the footnote references on page 44.

Average Market Reference Prices and Differentials (h)

(dollars per barrel)


	Six Months Ended June 30,
	2006		2005		Change
Feedstocks:
WTI crude oil	$	66.84	$	51.36	$	15.48
WTI less sour crude oil at U.S. Gulf Coast (i)		7.61		7.38		0.23
WTI less ANS crude oil		2.02		3.92		(1.90	)
WTI less Maya crude oil		15.65		15.06		0.59

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		14.00		7.75		6.25
No. 2 fuel oil less WTI		10.32		8.49		1.83
Propylene less WTI		8.84		12.39		(3.55	)
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		13.56		8.84		4.72
Low-sulfur diesel less WTI		17.00		11.46		5.54
U.S. Northeast:
Conventional 87 gasoline less WTI		11.85		6.41		5.44
No. 2 fuel oil less WTI		10.38		9.97		0.41
Lube oils less WTI		48.36		28.44		19.92
U.S. West Coast:
CARBOB 87 gasoline less ANS		24.16		20.29		3.87
Low-sulfur diesel less ANS		23.54		19.12		4.42

The following notes relate to references on pages 41 through 44.

(a)	Includes the operations related to the Premcor Acquisition, which was effective on September 1, 2005.

(b)

Operating revenues and cost of sales both include approximately $2.8 billion for the six months ended June 30, 2005 related to certain crude oil buy/sell arrangements, which involve linked purchases and sales related to crude oil contracts entered into to address location, quality or grade requirements. Commencing January 1, 2006, we adopted EITF Issue No. 04-13 which requires that such buy/sell arrangements be accounted for as one transaction, thereby resulting in no recognition of revenues and cost of sales for these transactions.

(c)	Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.

(d)	Other products primarily include gas oils, No. 6 fuel oil, petroleum coke and asphalt.

(e)

(f)	Throughput volumes for the Gulf Coast, Mid-Continent and Northeast regions for the six months ended June 30, 2006 include 298,000, 285,000 and 201,000 barrels per day, respectively, related to the operations of the refineries acquired from Premcor on September 1, 2005.

(g)

For the six months ended June 30, 2005, the information presented for the Mid-Continent region includes the operations of the Denver Refinery, which was sold on May 31, 2005 to Suncor Energy (U.S.A.) Inc. Throughput volumes for the Mid-Continent region for the six months ended June 30, 2005 include 31,000 barrels per day related to the Denver Refinery.

(h)

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

General

Operating revenues increased 45% for the six months ended June 30, 2006 compared to the six months ended June 30, 2005 primarily as a result of significantly higher refined product prices combined with additional throughput volumes from the former Premcor refinery operations. Operating income and net income for the first six months of 2006 almost doubled compared to the first six months of 2005. Operating income increased $2.0 billion, or 95%, and net income increased $1.4 billion, or 99%, from the six months ended June 30, 2005 to the six months ended June 30, 2006 primarily due to a $2.2 billion increase in refining segment operating income, partially offset by a $109 million increase in general and administrative expenses (including corporate depreciation and amortization expense).

Refining

Operating income for our refining segment increased from $2.3 billion for the six months ended June 30, 2005 to $4.5 billion for the six months ended June 30, 2006, resulting from a 32% increase in throughput volumes and an increase in refining throughput margin of $3.51 per barrel, or 38%, partially offset by increased refining operating expenses (including depreciation and amortization expense) of $908 million.

Refining total throughput margin for the first six months of 2006 increased primarily due to the following factors:

•

Throughput volumes increased 707,000 barrels per day during the first six months of 2006 compared to the first six months of 2005 due to the 784,000 barrel per day incremental throughput from the four former Premcor refineries, offset to some extent by the sale of the Denver Refinery in 2005 and significant planned and unplanned downtime at several of our refineries.

•

Gasoline and distillate margins increased significantly in all of Valero’s refining regions in the first six months of 2006 compared to the first six months of 2005. The continued strength of refined product margins for the first six months of 2006 was primarily due to increased foreign and U.S. demand, limited capacity additions, major industry turnaround activity, and continuing outages from last season’s hurricanes.

•

Throughput margin improved due to the negative impact in the first six months of 2005 of losses of approximately $205 million on hedges related to forward sales of distillates and associated forward purchases of crude oil.

Partially offsetting the above increases in throughput margin were lower margins on other refined products such as petroleum coke, sulfur and propylene due to a significant increase in the price of crude oil from the first six months of 2005 to the first six months of 2006.

Refining operating expenses, excluding depreciation and amortization expense, were 64% higher for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, due primarily to the Premcor Acquisition on September 1, 2005. Excluding the effect of the Premcor Acquisition, operating expenses increased 13% due mainly to increases in maintenance expense, employee compensation and related benefits, energy costs, catalyst and chemicals, and outside services. Refining depreciation and amortization expense increased 56% from the first six months of 2005 to the first six months of 2006 primarily due to the Premcor Acquisition, the implementation of new capital projects and increased turnaround and catalyst amortization.

Retail

Retail operating income was $67 million for the six months ended June 30, 2006 compared to $64 million for the six months ended June 30, 2005. This increase in operating income was attributable to U.S. retail

operations, as improved margins on fuel, merchandise and other sales were almost entirely offset by increased selling expenses resulting mainly from higher credit card processing fees attributable to higher retail fuel prices.

Corporate Expenses and Other

General and administrative expenses, including corporate depreciation and amortization expense, increased $109 million from the first six months of 2005 to the first six months of 2006. The increase was primarily due to increases in employee compensation and benefits, stock-based compensation expense, charitable contributions and legal and regulatory costs, as well as 2006 expenses attributable to the Premcor Acquisition and the favorable resolution of a California excise tax dispute in the first quarter of 2005.

Interest and debt expense incurred increased from the first six months of 2005 to the first six months of 2006 primarily as a result of interest expense incurred on the debt assumed in the Premcor Acquisition. However, the increased interest incurred was more than offset by increased capitalized interest due to an increase in capital projects, including those at the four former Premcor refineries.

Income tax expense increased $713 million from the first six months of 2005 to the first six months of 2006 mainly as a result of higher operating income. Our effective tax rate for the six months ended June 30, 2006 increased from the six months ended June 30, 2005 as a lower percentage of our pre-tax income was contributed by the Aruba Refinery, the operations of which are non-taxable in Aruba through December 31, 2010. This increase in the effective tax rate was partially offset by the effect of new tax legislation in both Texas and Canada in 2006.

OUTLOOK

During the third quarter of 2006, refining industry fundamentals have remained positive, resulting in a continuation of favorable refined product margins and sour crude oil discounts. For example, Gulf Coast gasoline and low-sulfur diesel margins for July 2006 averaged $22 per barrel and $19 per barrel, respectively. This compares favorably to third quarter 2005 average margins for gasoline of almost $20 per barrel and low-sulfur diesel of approximately $16 per barrel, which were significantly impacted by Hurricanes Katrina and Rita. Historically, when gasoline margins reach this level, imports increase to take advantage of the favorable margins. However, imports to date have not caused an increase in days-of-supply of gasoline or significantly impacted gasoline margins. Strong demand, combined with tight supplies of octane-enhancing components required to meet the stringent low-sulfur specifications, has kept gasoline margins high with an expectation of continuing strong margins. Low-sulfur on-road diesel demand is very strong for this time of year and this high demand has resulted in a reduction in on-road diesel supplies to five-year lows on a days-of-supply basis. This tight supply situation has resulted in significant premiums for on-road diesel over off-road diesel. We believe refined product margins will remain favorable for the second half of 2006 due to slower than anticipated growth in global refining capacity, supply constraints resulting from lower-sulfur specifications for gasoline and diesel, and continued strong refined product demand.

With the exception of the discount on our Alaska North Slope crude oil in the West Coast region, sour crude oil discounts remained wide during the month of July 2006 and are expected to remain favorable for the foreseeable future due to ample supplies of sour crude oil, limited refining capacity to economically process these feedstocks and continued strong demand for sweet crude oil. As refined product margins and light product demand have increased, worldwide refinery utilization rates have also increased, leading to higher production of residual fuel oil (resid) as a by-product of the refining process. Resid can compete with certain heavy sour crude oils as a refinery feedstock, thereby widening the

discounts for heavy sour crude oils. In addition, the global movement to lower-sulfur fuels has contributed to increased demand for sweet crude oils rather than sour crude oils to meet those more stringent specifications. Higher light product margins also increase sweet crude oil demand because sweet crude oils have a higher yield of light products.

Operationally, we do not have significant turnaround activity scheduled for the third quarter. This, along with the resolution of certain unplanned downtime issues that arose during the second quarter of 2006, has resulted in our refining system running at higher rates thus far in the third quarter of 2006, which we expect will continue for the remainder of the quarter. In addition, we expect to benefit during the second half of 2006 from the completion of significant turnaround and capital improvement projects during the first half of 2006, as well as additional strategic and environmental projects that we expect to complete during the remainder of 2006, including a 75,000 barrel-per-day expansion project at our Port Arthur Refinery.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Six Months Ended June 30, 2006 and 2005

Net cash provided by operating activities for the six months ended June 30, 2006 was $3.8 billion compared to $1.8 billion for the six months ended June 30, 2005. The increase in cash generated from operating activities was due primarily to the significant increase in operating income discussed above under “Results of Operations” and a $552 million increase from a favorable change in working capital between the years. Changes in cash provided by or used for working capital during the first six months of 2006 and 2005 are shown in Note 9 of Condensed Notes to Consolidated Financial Statements. The primary difference in the working capital changes between the two periods relates to a larger increase in income taxes payable in the 2006 period attributable mainly to the increase in operating income in the first six months of 2006.

The net cash generated from operating activities during the first six months of 2006, combined with a $130 million benefit from tax deductions in excess of recognized stock-based compensation cost, $65 million of proceeds from the issuance of common stock related to our benefit plans and $62 million of net borrowings (net of repayments) under our bank credit facilities were used mainly to:

•

fund $2.0 billion of capital expenditures and deferred turnaround and catalyst costs,

•

purchase 20.4 million shares of treasury stock at a cost of $1.2 billion,

•

make long-term note repayments of $221 million,

•

fund contingent earn-out payments in connection with the acquisition of Basis Petroleum, Inc. and the St. Charles Refinery of $26 million and $50 million, respectively,

•

terminate our interest rate swap contracts for $54 million,

•

pay common and preferred stock dividends of $87 million, and

•

increase available cash on hand by $501 million.

Net cash provided by operating activities during the first six months of 2005, combined with $40 million of proceeds from the issuance of common stock related to our benefit plans, $45 million of proceeds from the sale of the Denver Refinery, and a $40 million net return of investment from the Cameron Highway Oil Pipeline joint venture resulting from the refinancing of the joint venture’s debt in June 2005, were used mainly to:

•

fund $999 million of capital expenditures and deferred turnaround and catalyst costs,

•

make scheduled long-term note repayments of $396 million and early debt repurchases of $82 million,

•

purchase 5.8 million shares of treasury stock at a cost of $183 million,

•

fund contingent earn-out payments in connection with the acquisition of Basis Petroleum, Inc. and the St. Charles Acquisition of $35 million and $50 million, respectively,

•

fund the acquisition of four asphalt terminals for $35 million,

•

pay common and preferred stock dividends of $48 million, and

•

increase available cash on hand by $85 million.

Capital Investments

During the six months ended June 30, 2006, we expended $1.6 billion for capital expenditures and $387 million for deferred turnaround and catalyst costs. Capital expenditures for the six months ended June 30, 2006 included $826 million of costs related to environmental projects.

In connection with our acquisitions of Basis Petroleum, Inc. in 1997 and the St. Charles Refinery in 2003, the sellers are entitled to receive payments in any of the ten years and seven years, respectively, following these acquisitions 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 (Motiva). Under this agreement, Motiva was entitled to receive two separate annual earn-out payments depending on (a) the amount of crude oil processed at the refinery and the level of refining margins through May 2007, and (b) the achievement of certain performance criteria at the gasification facility through May 2006. The earn-out contingency related to the gasification facility expired in the second quarter of 2006 with no payment required. Any payments due under these earn-out arrangements are limited based on annual and aggregate limits. In January 2006, we made an earn-out payment of $50 million related to the St. Charles Refinery. An earn-out payment of $26 million (the maximum remaining payment based on the aggregate limitation under the agreement) related to the acquisition of Basis Petroleum, Inc. was made in the second quarter of 2006. In July 2006, we made a payment of $25 million related to the Delaware City Refinery contingent earn-out agreement.

For 2006, we expect to incur approximately $3.5 billion for capital investments, including approximately $3.0 billion for capital expenditures (approximately $1.5 billion of which is for environmental projects) and approximately $540 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes anticipated 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.

Stock Purchase Programs

Our board of directors has approved the purchase of treasury stock to satisfy employee benefit plan requirements and an existing publicly announced stock purchase program as described in Part II, Item 2(c), of this report. Under these authorizations, management currently expects to purchase approximately 5% of our outstanding shares during 2006.

During the six months ended June 30, 2006, we purchased 20.4 million shares of our common stock for $1.2 billion under these two programs. Of this amount, we purchased approximately 14.7 million shares for $826 million related to our employee benefit plans and approximately 5.7 million shares for $361 million under our publicly announced stock purchase program.

Contractual Obligations

As of June 30, 2006, our contractual obligations included long-term debt, capital lease obligations, operating leases and purchase obligations. Except as discussed below, there were no significant changes to our contractual obligations during the six months ended June 30, 2006.

During the first six months of 2006, we made a scheduled debt repayment of $220 million related to our 7.375% notes and a payment of $1 million related to our 7.75% notes.

As of June 30, 2006, our short-term and long-term purchase obligations increased by approximately $1.3 billion from the amount reported as of December 31, 2005, resulting primarily from both new crude oil and refined product purchase contracts entered into in the first six months of 2006 and higher crude oil prices as of June 30, 2006.

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. Following the completion of the Premcor Acquisition, Standard & Poor’s Ratings Services affirmed its rating of our senior unsecured debt of BBB minus and changed our outlook from negative to stable, and in June 2006 indicated that we were being evaluated for a possible upgrade. Also following the completion of the Premcor Acquisition, Moody’s Investors Service affirmed our senior unsecured debt rating of Baa3 with a stable outlook, while in February 2006, Fitch Ratings upgraded its rating of our senior unsecured debt to BBB with a stable outlook.

Other Commercial Commitments

As of June 30, 2006, our committed lines of credit included:


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

During July 2006, the 5-year revolving credit facility was amended to (i) extend the maturity date by one year to August 2011, (ii) eliminate certain covenants, and (iii) reduce the pricing under the agreement.

As of June 30, 2006, we had $504 million of letters of credit outstanding under our U.S. uncommitted short-term bank credit facilities and $239 million of letters of credit outstanding under our 5-year revolving credit facility. Under our Canadian revolving credit facility, we had borrowings of Cdn. $20 million outstanding and Cdn. $8 million of letters of credit outstanding as of June 30, 2006, and under our Canadian uncommitted facilities, we had borrowings of Cdn. $50 million outstanding as of June 30, 2006.

Sale of Investment in Valero GP Holdings, LLC

On July 19, 2006, Valero GP Holdings, LLC, an indirect wholly owned subsidiary of Valero, consummated an initial public offering of 17,250,000 of its units representing limited liability company interests to the public at $22.00 per unit, before an underwriters’ discount of $1.265 per unit. Subsidiaries of Valero GP Holdings, LLC own the general partner interest, the incentive distribution rights and the 21.4% limited partner interest that we have in Valero L.P. Proceeds from the offering totaled approximately $355 million, net of the underwriters’ discount and other offering expenses, which will result in a third quarter 2006 pre-tax gain of approximately $125 million on the sale of the units. Subsequent to the initial public offering, subsidiaries of Valero hold a 59.4% ownership interest in Valero GP Holdings, LLC. It is our intention to further reduce and ultimately sell all of our interest in Valero GP Holdings, LLC, pending market conditions. However, we are subject to a 180-day holding period subsequent to July 13, 2006 (date of prospectus) during which we have agreed not to sell any additional units without the consent of Lehman Brothers Inc. We expect to use funds from this offering for general corporate purposes, which may include acquisitions, stock purchases and debt reduction.

Other

In conjunction with the conversion of our investment in Valero L.P.’s subordinated units to common units (as discussed in Note 5), we recognized $158 million of pre-tax SAB 51 credits ($101 million after tax) in “additional paid-in capital” in our consolidated balance sheet as of June 30, 2006 (see Note 1 for our accounting policy on issuances of subsidiary stock). Since Valero L.P. has previously issued additional common units to the public, it is possible that such issuances may occur in the future, prior to the completion of the intended sale of our investment in Valero GP Holdings, LLC discussed above; however, it is not possible at this time to predict the timing of such issuances.

Although our minimum required contribution to our qualified pension plans during 2006 is less than $5 million under the Employee Retirement Income Security Act, we expect to contribute approximately $145 million to our qualified pension plans during 2006. During the first six months of 2006, we contributed $45 million to our qualified pension plans.

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 and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our refineries could require material additional expenditures to comply with environmental laws and regulations. For additional information regarding our environmental matters, see Note 14 of Condensed Notes to Consolidated Financial Statements.

During the third quarter of 2005, certain of our refineries experienced property damage and business interruption losses associated with Hurricanes Katrina and Rita. As a result of these losses, we have submitted claims to our insurance carriers under our insurance policies. As of June 30, 2006, we have recorded a $16 million receivable related to our property damage claims, which was recorded as a reduction of repair and maintenance expense. During the second quarter, we received $13 million related to our business interruption insurance claims which was recorded in “accrued expenses” in the consolidated balance sheet as of June 30, 2006 to defer the recognition of income pending further review by the insurance carriers. During July 2006, an additional $20 million was received related to the business interruption insurance claims.

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 acceptable to us.

OFF-BALANCE SHEET ARRANGEMENTS

Accounts Receivable Sales Facility

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, 2005.

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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

COMMODITY PRICE RISK

The following tables provide information about our derivative commodity instruments as of June 30, 2006 and December 31, 2005 (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 $3.8 billion as of June 30, 2006 and December 31, 2005, respectively, and a fair value of $9.5 billion and $7.1 billion as of June 30, 2006 and December 31, 2005, 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

•

trading activities 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 reported as a component of “other comprehensive income” and is recorded in income in the same period or periods during which the hedged forecasted transaction affects income. The remaining ineffective portion of the gain or loss on the cash flow derivative instrument, if any, is recognized currently in income. 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 certain 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 fair value for futures, swaps and options represents the fair value of the derivative contract. The 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 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.


	June 30, 2006
	Contract Volumes	Wtd Avg Pay Price		Wtd Avg Receive Price		Contract Value			Market Value			Pre-tax Fair Value
*Fair Value Hedges:*
Futures – long:
2006 (crude oil and refined products)	16,256	$	72.12		N/A	$	1,172		$	1,212		$	40
Futures – short:
2006 (crude oil and refined products)	22,018		N/A	$	72.22		1,590			1,650			(60	)

*Cash Flow Hedges:*
Swaps – long:
2006 (crude oil and refined products)	3,300		75.35		79.25		N/A			13			13
2007 (crude oil and refined products)	5,055		74.39		77.27		N/A			15			15
Swaps – short:
2006 (crude oil and refined products)	3,300		83.36		79.38		N/A			(13	)		(13	)
2007 (crude oil and refined products)	5,055		89.68		87.06		N/A			(13	)		(13	)
Futures – long:
2006 (crude oil and refined products)	32,213		73.13		N/A		2,356			2,447			91
2007 (crude oil and refined products)	36		90.72		N/A		3			3			—
Futures – short:
2006 (crude oil and refined products)	27,774		N/A		72.33		2,009			2,088			(79	)

*Economic Hedges:*
Swaps – long:
2006 (crude oil and refined products)	8,462		13.63		15.10		N/A			12			12
Swaps – short:
2006 (crude oil and refined products)	4,567		30.30		28.65		N/A			(8	)		(8	)
2006 (natural gas)	3,720		0.32		0.00		N/A			(1	)		(1	)
2007 (natural gas)	350		3.10		2.81		N/A			—			—
Futures – long:
2006 (crude oil and refined products)	56,225		76.15		N/A		4,281			4,417			136
2007 (crude oil and refined products)	130		88.89		N/A		12			12			—
Futures – short:
2006 (crude oil and refined products)	57,052		N/A		75.74		4,321			4,448			(127	)
2006 (natural gas)	200		N/A		11.44		2			2			—
Options – long:
2006 (natural gas)	3,500		5.70		N/A		(1	)		(1	)		—
Options – short:
2007 (crude oil and refined products)	600		N/A		16.05		1			1			—

*Trading Activities:*
Swaps – long:
2006 (crude oil and refined products)	1,050		6.22		7.23		N/A			1			1
Swaps – short:
2006 (crude oil and refined products)	1,950		9.86		9.41		N/A			(1	)		(1	)
Futures – long:
2006 (crude oil and refined products)	25,074		71.01		N/A		1,780			1,862			82
2006 (natural gas)	550		7.54		N/A		4			5			1
Futures – short:
2006 (crude oil and refined products)	24,924		N/A		70.93		1,768			1,850			(82	)
2006 (natural gas)	550		N/A		7.66		4			5			(1	)

Total pre-tax fair value of open positions												$	6


	December 31, 2005
	Contract Volumes	Wtd Avg Pay Price		Wtd Avg Receive Price		Contract Value			Market Value			Pre-tax Fair Value
*Fair Value Hedges:*
Futures – long:
2006 (crude oil and refined products)	50,912	$	59.03		N/A	$	3,005		$	3,113		$	108
Futures – short:
2006 (crude oil and refined products)	64,422		N/A	$	59.87		3,857			3,958			(101	)

*Cash Flow Hedges:*
Futures – long:
2006 (crude oil and refined products)	18,179		62.24		N/A		1,131			1,152			21
Futures – short:
2006 (crude oil and refined products)	13,690		N/A		60.51		828			849			(21	)

*Economic Hedges:*
Swaps – long:
2006 (crude oil and refined products)	7,947		8.12		8.81		N/A			5			5
2006 (natural gas)	2,700		11.37		9.19		N/A			(6	)		(6	)
Swaps – short:
2006 (crude oil and refined products)	4,481		17.27		16.85		N/A			(2	)		(2	)
2006 (natural gas)	1,350		9.19		11.46		N/A			3			3
Futures – long:
2006 (crude oil and refined products)	29,945		65.64		N/A		1,966			2,036			70
Futures – short:
2006 (crude oil and refined products)	27,052		N/A		65.34		1,768			1,815			(47	)
Options – long:
2006 (natural gas)	1,290		9.27		N/A		(2	)		(1	)		1
Options – short:
2006 (crude oil and refined products)	190		N/A		72.95		(1	)		(1	)		—
2006 (natural gas)	690		N/A		7.98		—			—			—

*Trading Activities:*
Swaps – long:
2006 (crude oil and refined products)	300		11.64		11.94		N/A			—			—
2006 (natural gas)	350		9.33		11.28		N/A			1			1
Swaps – short:
2006 (crude oil and refined products)	1,350		12.66		13.17		N/A			1			1
2006 (natural gas)	350		11.28		9.18		N/A			(1	)		(1	)
Futures – long:
2006 (crude oil and refined products)	12,266		60.01		N/A		736			763			27
2006 (natural gas)	840		8.03		N/A		6			9			3
Futures – short:
2006 (crude oil and refined products)	10,816		N/A		60.49		654			678			(24	)
2006 (natural gas)	840		N/A		8.34		7			9			(2	)
Options – long:
2006 (crude oil and refined products)	2,000		0.50		N/A		—			—			—
2006 (natural gas)	900		10.00		N/A		—			—			—
Options – short:
2006 (crude oil and refined products)	2,000		N/A		0.50		—			—			—
2006 (natural gas)	900		N/A		10.00		—			—			—

Total pre-tax fair value of open positions												$	36

INTEREST RATE RISK

The following table provides information about our long-term debt and interest rate derivative instruments (dollars in millions), all of which are sensitive to changes in interest rates. For long-term debt, principal cash flows and related weighted-average interest rates by expected maturity dates are presented. For interest rate swaps, the table presents notional amounts and weighted-average interest rates by expected (contractual) maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the contract. Weighted-average floating rates are based on implied forward rates in the yield curve at the reporting date.


	June 30, 2006
	Expected Maturity Dates
	2006			2007			2008			2009			2010			There- after			Total			Fair Value
Long-term Debt:
Fixed rate	$	—		$	287		$	6		$	209		$	208		$	4,391		$	5,101		$	5,251
Average interest rate		—	%		6.1	%		6.0	%		3.6	%		8.9	%		7.0	%		6.9	%
Floating rate	$	—		$	—		$	—		$	—		$	63		$	—		$	63		$	63
Average interest rate		—	%		—	%		—	%		—	%		5.1	%		—	%		5.1	%


	December 31, 2005
	Expected Maturity Dates
	2006			2007			2008			2009			2010			There- after			Total			Fair Value
Long-term Debt:
Fixed rate	$	220		$	287		$	6		$	209		$	208		$	4,392		$	5,322		$	5,735
Average interest rate		7.4	%		6.1	%		6.0	%		3.6	%		8.9	%		7.0	%		6.9	%

Interest Rate Swaps Fixed to Floating:
Notional amount	$	125		$	225		$	—		$	9		$	—		$	641		$	1,000		$	(28	)
Average pay rate		6.5	%		6.2	%		5.8	%		5.9	%		5.9	%		5.6	%		5.9	%
Average receive rate		6.0	%		5.8	%		5.7	%		5.7	%		5.7	%		5.6	%		5.7	%

Effective May 1, 2006, we terminated the $875 million of interest rate swap contracts outstanding at that date for a payment of $54 million. Substantially all of this amount was deferred and will be amortized to interest expense over the remaining lives of the debt instruments that were being hedged.

FOREIGN CURRENCY RISK

As of June 30, 2006, we had commitments to purchase $179 million of U.S. dollars. Our market risk was immaterial on these contracts, as they matured on or before July 28, 2006.

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 June 30, 2006.

(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, 2005, or our quarterly report on Form 10-Q for the quarter ended March 31, 2006.

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 Valero, we believe that there would be no material effect on our consolidated financial position or results of operations. Nevertheless, we are reporting these proceedings to comply with SEC regulations, which require us to disclose 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.

City of Houston and Texas Commission on Environmental Quality (TCEQ) (Houston Refinery) (this matter was last reported in our Form 10-Q for the quarter ended March 31, 2006). In January 2006, the City of Houston issued a notice of enforcement to our Houston Refinery alleging violations of the Texas Clean Air Act and certain TCEQ regulations for past emission events that we self-reported. In March 2006, the TCEQ issued intervening notices of enforcement pertaining to the same emission events. We recently settled these matters with the City of Houston and the TCEQ and we are currently finalizing the settlement documents.

People of the State of Illinois, ex rel. v. The Premcor Refining Group Inc., et al., Chancery Division, Circuit Court, Cook County (Case No. 05-CH-07694, filed May 3, 2005) (former Clark retail sites) (this matter was last reported in our Form 10-K for the year ended December 31, 2005). The Illinois EPA had issued NOVs to Premcor pertaining to reported releases from underground storage tanks at certain retail sites alleging that Premcor was either the operator or landlord/owner at the time of the releases. In July 2006, we entered into a consent order with the Illinois EPA for corrective action at approximately 50 retail sites.

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

(a) Unregistered Sales of Equity Securities.

We are the sponsor of the Premcor Retirement Savings Plan (Savings Plan), a tax-qualified plan under Section 401(k) of the Internal Revenue Code. The Savings Plan is a retirement savings vehicle that allows a certain group of our refinery employees to invest in several different investment funds, including a fund whose only asset is Valero common stock. Valero matches a percentage of employee contributions to the Savings Plan. These matching contributions are invested in Valero common stock. Shares of Valero common stock are acquired for participants’ Savings Plan accounts by an independent trustee. Purchases of Valero common stock are made by the trustee in the open market, and shares for employer matching contributions are acquired by the trustee from Valero.

We acquired the Savings Plan in the merger of Premcor with Valero effective September 1, 2005. We amended the Savings Plan in December 2005 to permit participants to invest in Valero common stock starting in January 2006. On August 4, 2006, we filed a registration statement on Form S-8 to register 10 million shares of Valero common stock for issuance under the Savings Plan. We have concluded that from January 3, 2006 to August 3, 2006, approximately 954,000 shares of Valero common stock were acquired by the trustee for the accounts of Savings Plan participants prior to our filing of a registration statement on Form S-8. Purchases of Valero common stock by the trustee for Savings Plan participants during this period were made at prices ranging from approximately $49.76 per share to $69.10 per share. Valero did not receive any proceeds from any shares of Valero common stock acquired by the trustee for Savings Plan participants. Exemptions from registration under federal securities laws may not be available for all shares that have been acquired for the Savings Plan during the period noted above.

(b) Use of Proceeds. Not applicable.

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


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Not Purchased as Part of Publicly Announced Plans or Programs (1)	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (2)
April 2006	782,130	$	60.58	782,130	0	$	361 million
May 2006	6,266,182	$	62.77	544,582	5,721,600	$	0
June 2006	2,628,707	$	59.48	2,628,707	0	$	0
Total	9,677,019	$	61.70	3,955,419	5,721,600	$	0

(1)

The shares reported in this column represent purchases settled in the second quarter of 2006 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)	Our stock purchase program was publicly announced on December 3, 2001. The program authorized us to purchase up to $400 million aggregate purchase price of shares of Valero common stock. The program had no expiration date.

Item 4. Submission of Matters to a Vote of Security Holders.

Valero’s annual meeting of stockholders was held April 27, 2006. Matters voted on at the meeting and the results thereof were as follows:

(a)

a proposal to elect four Class III directors to serve until the 2009 annual meeting was approved as follows:


Directors	Affirmative	Withheld	Non-Votes
Jerry D. Choate	543,101,395	5,134,506	n/a
William R. Klesse	537,847,858	10,388,043	n/a
Donald L. Nickles	543,446,796	4,789,106	n/a
Susan Kaufman Purcell	537,669,758	10,566,143	n/a

(b)

a proposal to ratify the appointment of KPMG LLP to serve as Valero’s independent registered public accounting firm for the fiscal year ending December 31, 2006 was approved as follows:


Affirmative	Negative	Withheld	Non-Votes
541,739,546	3,051,871	3,444,484	n/a

Directors whose terms of office continued after the annual meeting were: W.E. ”Bill” Bradford, Ronald K. Calgaard, Irl F. Engelhardt, Ruben M. Escobedo, William E. Greehey, Bob Marbut and Robert A. Profusek.

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.

SIGNATURE

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


VALERO ENERGY CORPORATION (Registrant)

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

Date: August 9, 2006