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 September 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 October 31, 2006 was 604,618,162.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

INDEX


		Page
PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

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

Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2006 and 2005		4

Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2006 and 2005		5

Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 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		36

Item 3. Quantitative and Qualitative Disclosures About Market Risk		56

Item 4. Controls and Procedures		60

PART II - OTHER INFORMATION

Item 1. Legal Proceedings		60

Item 1A. Risk Factors		61

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		61

Item 6. Exhibits		62

SIGNATURE		63

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Par Value)


	September 30, 2006			December 31, 2005
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	1,029		$	436
Restricted cash		31			30
Receivables, net		3,605			3,564
Inventories		4,666			4,039
Income taxes receivable		67			70
Deferred income taxes		156			142
Prepaid expenses and other		177			65

Total current assets		9,731			8,346

Property, plant and equipment, at cost		23,666			20,388
Accumulated depreciation		(3,102	)		(2,532	)

Property, plant and equipment, net		20,564			17,856

Intangible assets, net		309			298
Goodwill		4,263			4,926
Investment in Valero L.P.		480			327
Deferred charges and other assets, net		1,295			1,045

Total assets	$	36,642		$	32,798

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	238		$	222
Accounts payable		6,144			5,563
Accrued expenses		548			581
Taxes other than income taxes		550			595
Income taxes payable		176			109
Deferred income taxes		381			305

Total current liabilities		8,037			7,375

Long-term debt, less current portion		4,815			5,109

Capital lease obligations, less current portion		82			47

Deferred income taxes		4,161			3,615

Other long-term liabilities		1,506			1,602

Minority interest in consolidated subsidiary		226			—

Commitments and contingencies (Note 14)
Stockholders’ equity:
Preferred stock, $0.01 par value; 20,000,000 shares authorized; 0 and 3,164,151 shares issued and outstanding		—			68
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 627,501,593 and 621,230,266 shares issued		6			6
Additional paid-in capital		7,774			8,164
Treasury stock, at cost; 21,411,799 and 3,807,976 common shares		(1,281	)		(196	)
Retained earnings		10,885			6,673
Accumulated other comprehensive income		431			335

Total stockholders’ equity		17,815			15,050

Total liabilities and stockholders’ equity	$	36,642		$	32,798

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 September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Operating revenues (1) (2)	$	24,319		$	23,283		$	72,041		$	56,268

Costs and expenses:
Cost of sales (1)		20,419			20,638			60,801			49,389
Refining operating expenses		929			759			2,804			1,903
Retail selling expenses		208			197			601			551
General and administrative expenses		136			159			458			375
Depreciation and amortization expense		294			219			847			588

Total costs and expenses		21,986			21,972			65,511			52,806

Operating income		2,333			1,311			6,530			3,462
Equity in earnings of Valero L.P.		13			13			35			32
Other income (expense), net		143			11			138			(4	)
Interest and debt expense:
Incurred		(91	)		(85	)		(280	)		(230	)
Capitalized		45			18			129			39
Minority interest in net income of consolidated subsidiary		(4	)		—			(4	)		—

Income before income tax expense		2,439			1,268			6,548			3,299
Income tax expense		836			406			2,199			1,056

Net income		1,603			862			4,349			2,243
Preferred stock dividends		—			4			2			12

Net income applicable to common stock	$	1,603		$	858		$	4,347		$	2,231

Earnings per common share	$	2.63		$	1.56		$	7.08		$	4.25
Weighted-average common shares outstanding (in millions)		609			551			613			526

Earnings per common share – assuming dilution	$	2.55		$	1.47		$	6.83		$	3.96
Weighted-average common equivalent shares outstanding (in millions)		628			587			636			566

Dividends per common share	$	0.08		$	0.05		$	0.22		$	0.14

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		$	2.3			N/A		$	5.1
Cost of sales		N/A		$	2.3			N/A		$	5.1
(2) Includes excise taxes on sales by our U.S. retail system	$	0.2		$	0.2		$	0.6		$	0.6

See Condensed Notes to Consolidated Financial Statements.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

(Unaudited)


	Nine Months Ended September 30,
	2006			2005
Cash flows from operating activities:
Net income	$	4,349		$	2,243
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		847			588
Gain on sale of interest in Valero GP Holdings, LLC		(132	)		—
Stock-based compensation expense		70			60
Deferred income tax expense		175			34
Changes in current assets and current liabilities		(129	)		989
Changes in deferred charges and credits and other, net		(84	)		(31	)

Net cash provided by operating activities		5,096			3,883

Cash flows from investing activities:
Capital expenditures		(2,331	)		(1,289	)
Deferred turnaround and catalyst costs		(464	)		(262	)
Premcor Acquisition, net of cash acquired		—			(2,343	)
Proceeds from sale of interest in Valero GP Holdings, LLC		355			—
Contingent payments in connection with acquisitions		(101	)		(85	)
Proceeds from sale of the Denver Refinery		—			45
General partner contribution to Valero L.P.		—			(29	)
Other investing activities, net		29			(6	)

Net cash used in investing activities		(2,512	)		(3,969	)

Cash flows from financing activities:
Long-term note repayments		(249	)		(681	)
Bank credit agreements:
Borrowings		707			1,617
Repayments		(706	)		(817	)
Termination of interest rate swaps		(54	)		—
Issuance of common stock in connection with employee benefit plans		103			114
Benefit from tax deduction in excess of recognized stock-based compensation cost		160			—
Common and preferred stock dividends		(136	)		(75	)
Purchase of treasury stock		(1,818	)		(188	)
Other		(4	)		(12	)

Net cash used in financing activities		(1,997	)		(42	)

Effect of foreign exchange rate changes on cash		6			1

Net increase (decrease) in cash and temporary cash investments		593			(127	)
Cash and temporary cash investments at beginning of period		436			864

Cash and temporary cash investments at end of period	$	1,029		$	737

See Condensed Notes to Consolidated Financial Statements.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Net income	$	1,603		$	862		$	4,349		$	2,243

Other comprehensive income (loss):
Foreign currency translation adjustment		(2	)		83			70			53

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 $(17), $27, $(18) and $158		32			(50	)		34			(294	)
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $1, $(15), $4 and $(86)		(2	)		28			(8	)		161

Net gain (loss) on cash flow hedges		30			(22	)		26			(133	)

Other comprehensive income (loss)		28			61			96			(80	)

Comprehensive income	$	1,631		$	923		$	4,445		$	2,163

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. As of September 30, 2006, Valero owns a 59.4% interest in Valero GP Holdings, LLC, which, through certain of its subsidiaries, owns the general partner interest, incentive distribution rights and a 21.4% limited partner interest in Valero L.P. These financial statements consolidate Valero GP Holdings, LLC, with the 40.6% interest held by public unitholders presented as a minority interest in the consolidated balance sheet. See Note 5 under “Valero GP Holdings, LLC” for a discussion of the sale of the 40.6% interest in Valero GP Holdings, LLC.

These unaudited consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the three and nine months ended September 30, 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 nine months ended September 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 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 our 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 September 30, 2005
	Previously Reported		Reclassifications			Currently Reported
Refining operating expenses	$	772	$	(13	)	$	759
Retail selling expenses		201		(4	)		197
General and administrative expenses		129		30			159
Depreciation and amortization expense		232		(13	)		219

	Nine Months Ended September 30, 2005
	Previously Reported		Reclassifications			Currently Reported
Refining operating expenses	$	1,938	$	(35	)	$	1,903
Retail selling expenses		561		(10	)		551
General and administrative expenses		303		72			375
Depreciation and amortization expense		615		(27	)		588

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 policy.

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 $160 million and $49 million for the nine months ended September 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 nine months ended September 30, 2005 would have been less than $1 million and less than $2 million, respectively, and the impact on net income applicable to common stock and net income for the three and nine months ended September 30, 2006, would have been less than $1 million and less than $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 nine months ended September 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.

FASB Statement No. 157

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

FASB Statement No. 158

In September 2006, the FASB issued Statement No. 158, “Employers’ Accounting for Defined Benefit and Other Postretirement Plans,” which amends Statement No. 87, “Employers’ Accounting for Pensions,” Statement No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” Statement No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” and other related accounting literature.

Statement No. 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or a liability in the statement of financial position and to recognize changes in that funded status through comprehensive income in the year the changes occur. This statement also requires an employer to measure the funded status of a plan as of the date of the employer’s year-end statement of financial position. The funded status recognition and related disclosure requirements of Statement No. 158 are effective as of the end of the fiscal year ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s year-end statement of financial position is effective for fiscal years ending after December 15, 2008. Earlier application is encouraged. The adoption of Statement No. 158 is not expected to materially affect our financial position.

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 was 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. During the third quarter of 2006, the purchase price

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

allocation was finalized with immaterial adjustments to the amounts recorded as of June 30, 2006. 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 included an $898 million increase in property, plant and equipment, a $646 million decrease in goodwill and a $349 million increase in deferred income taxes resulting from the final appraisal and other evaluations. The purchase price and the final purchase price allocation 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		1,882
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		(2,027	)
Other long-term liabilities		(424	)

Purchase price, excluding unrestricted cash acquired	$	6,116

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 nine months ended September 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.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Operating revenues	$	24,319	$	27,159	$	72,041	$	69,226
Operating income		2,333		1,544		6,530		4,380
Net income		1,603		1,006		4,349		2,780
Earnings per common share		2.63		1.65		7.08		4.61
Earnings per common share – assuming dilution		2.55		1.55		6.83		4.29

4. INVENTORIES

Inventories consisted of the following (in millions):


	September 30, 2006		December 31, 2005
Refinery feedstocks	$	2,036	$	1,826
Refined products and blendstocks		2,377		1,960
Convenience store merchandise		88		91
Materials and supplies		165		162

Inventories	$	4,666	$	4,039

As of September 30, 2006 and December 31, 2005, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $3.0 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. As a result of an initial public offering by Valero GP Holdings, LLC in July 2006 discussed below, our effective ownership interest in Valero L.P. as of September 30, 2006 was reduced to 13.9%.

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

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 nine months ended September 30, 2006 and 2005 is summarized below (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Revenues	$	291	$	263	$	845	$	378
Operating income		55		57		158		106
Net income		41		45		112		83

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 September 30, 2006 and December 31, 2005, our “receivables, net” included $13 million from Valero L.P., representing amounts due for employee costs, insurance costs, operating expenses, administrative costs and rentals. As of September 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 September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Fees and expenses charged by us to Valero L.P.	$	32	$	30	$	89	$	52
Fees and expenses charged to us by Valero L.P.		69		64		194		177

Valero GP Holdings, LLC

On July 19, 2006, Valero GP Holdings, LLC 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. All such units were sold by subsidiaries of Valero that held various ownership interests in Valero GP Holdings, LLC. Proceeds to the selling subsidiaries from the offering totaled approximately $355 million, net of the underwriters’ discount and other offering expenses, which resulted in a pre-tax gain to Valero of $132 million on the sale of the units, which is included in “other income (expense), net” in the consolidated statements of income. The funds received from this offering are being used for general corporate purposes. 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

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

prospectus) during which we have agreed not to sell any additional units without the consent of Lehman Brothers Inc.

6. DEBT

During March 2006, we made a scheduled debt repayment of $220 million related to our 7.375% notes. In addition, during the nine months ended September 30, 2006, we made the following debt payments:

•

$1 million during March 2006 related to our 7.75% notes due in February 2012,

•

$14 million during July 2006 related to our 6.75% senior notes due in May 2014 and

•

$14 million during July 2006 related to our 7.5% senior notes due in June 2015.

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.

In July 2006, Valero GP Holdings, LLC entered into a $20 million revolving credit facility which matures in July 2009. Borrowings under this facility generally bear interest at LIBOR plus a margin. As of September 30, 2006, borrowings of $1 million were outstanding under this credit facility.

During the nine months ended September 30, 2006, we borrowed and repaid $549 million under our Canadian revolving credit facility and $5 million under our $2.5 billion revolving credit facility, and we borrowed and repaid $152 million under our short-term uncommitted bank credit facilities.

7. STOCKHOLDERS’ EQUITY

2% Mandatory Convertible Preferred Stock

During the nine months ended September 30, 2006, the remaining 3,164,151 shares of our 2% mandatory convertible preferred stock were converted into 6,271,327 shares of our common stock. July 1, 2006 was the mandatory conversion date.

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 nine months ended September 30, 2006 and 2005, we purchased 30.8 million and 5.9 million shares of our common stock at a cost of $1.8 billion and $188 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 nine months ended September 30, 2006, we issued 13.2 million treasury shares at

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

an average cost of $55.29 per share, and for the nine months ended September 30, 2005, we issued 13.9 million treasury shares at an average cost of $21.88 per share, for our employee benefit plans.

On October 19, 2006, our board of directors approved a $2 billion common stock purchase program. This new authorization is in addition to our existing authorization to purchase shares to offset dilution created by our employee stock incentive programs. Stock purchases under this program will be made from time to time at prevailing prices as permitted by securities laws and other legal requirements, and are subject to market conditions and other factors. The program does not have a scheduled expiration date.

Common Stock Dividends

On October 19, 2006, our board of directors declared a regular quarterly cash dividend of $0.08 per common share payable December 13, 2006 to holders of record at the close of business on November 8, 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 September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Earnings per Common Share:
Net income	$	1,603	$	862	$	4,349	$	2,243
Preferred stock dividends		—		4		2		12

Net income applicable to common stock	$	1,603	$	858	$	4,347	$	2,231

Weighted-average common shares outstanding		609		551		613		526

Earnings per common share	$	2.63	$	1.56	$	7.08	$	4.25

Earnings per Common Share – Assuming Dilution:
Net income applicable to common equivalent shares	$	1,603	$	862	$	4,349	$	2,243

Weighted-average common shares outstanding		609		551		613		526
Effect of dilutive securities:
Stock options		17		22		19		20
Performance awards and other benefit plans		1		6		1		6
Mandatory convertible preferred stock		1		8		3		14

Weighted-average common equivalent shares outstanding		628		587		636		566

Earnings per common share – assuming dilution	$	2.55	$	1.47	$	6.83	$	3.96

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STATEMENTS OF CASH FLOWS

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


	Nine Months Ended September 30,
	2006			2005
Decrease (increase) in current assets:
Restricted cash	$	(1	)	$	132
Receivables, net		(20	)		(828	)
Inventories		(624	)		31
Income taxes receivable		3			—
Prepaid expenses and other		(113	)		40
Increase (decrease) in current liabilities:
Accounts payable		597			1,533
Accrued expenses		(20	)		40
Taxes other than income taxes		(49	)		(100	)
Income taxes payable		98			141

Changes in current assets and current liabilities	$	(129	)	$	989

The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable consolidated balance sheets for the respective periods for the following reasons:

•

the amounts shown above exclude changes in cash and temporary cash investments, deferred income taxes, and current portion of long-term debt and capital lease obligations, as well as the effect of certain noncash investing and financing activities discussed below;

•

the amounts shown above for 2005 exclude the current assets and current liabilities acquired in connection with the Premcor Acquisition and certain minor acquisitions, as well as the current assets and current liabilities disposed of in connection with the sale of the Denver Refinery, all of which are reflected separately in the consolidated statement of cash flows;

•

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 nine months ended September 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 Ultramar Diamond Shamrock Corporation. Noncash financing activities for the nine months ended September 30, 2006 included the conversion of 3,164,151 shares of preferred stock into 6,271,327 shares of our common stock as discussed in Note 7 and the recognition of a $39 million capital lease obligation and related capital asset pertaining to certain facilities at our Lima Refinery.

Noncash investing activities for the nine months ended September 30, 2005 included adjustments to property, plant and equipment and certain current and noncurrent assets and liabilities resulting from

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

adjustments to the purchase price allocation related to the acquisition of the Aruba Refinery and related assets. Noncash financing activities for the nine months ended September 30, 2005 included (i) the issuance of $3.2 billion (85 million shares) of common stock and $596 million of vested employee stock options as partial consideration for the Premcor Acquisition, (ii) the conversion of 6,425,743 shares of preferred stock into 12,735,810 shares of Valero common stock and (iii) the recognition of a $28 million capital lease obligation and related capital lease asset pertaining to certain equipment at our Texas City Refinery.

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


	Nine Months Ended September 30,
	2006		2005
Interest paid (net of amount capitalized)	$	165	$	132
Income taxes paid (net of tax refunds received)		1,759		881

10. PRICE RISK MANAGEMENT ACTIVITIES

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Fair value hedges	$	(2	)	$	10		$	(8	)	$	13
Cash flow hedges		2			(28	)		7			(28	)

The above amounts were included in “cost of sales” in the consolidated statements of income. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness. No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges.

For cash flow hedges, gains and losses reported in “accumulated other comprehensive income” in the consolidated balance sheets are reclassified into cost of sales when the forecasted transactions affect income. During the nine months ended September 30, 2005, we recognized in “accumulated other comprehensive income” unrealized after-tax losses of $294 million on certain cash flow hedges, primarily related to forward sales of distillates and associated forward purchases of crude oil. During the nine months ended September 30, 2006, we recognized in “accumulated other comprehensive income” unrealized after-tax gains of $34 million on certain cash flow hedges, primarily related to forward sales of gasoline and distillates and associated forward purchases of crude oil, with $31 million of cumulative after-tax gains on cash flow hedges remaining in “accumulated other comprehensive income” as of September 30, 2006. We expect that all of these cash flow hedges will be reclassified into income over the next six months as a result of hedged transactions that are forecasted to occur. The amount ultimately realized in income, however, will differ as commodity prices change. For the nine months ended September 30, 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.

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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 September 30, 2006:
Operating revenues from external customers	$	22,055	$	2,264	$	—		$	24,319
Intersegment revenues		1,547		—		—			1,547
Operating income (loss)		2,385		96		(148	)		2,333

Three months ended September 30, 2005:
Operating revenues from external customers		21,170		2,113		—			23,283
Intersegment revenues		1,484		—		—			1,484
Operating income (loss)		1,457		24		(170	)		1,311

Nine months ended September 30, 2006:
Operating revenues from external customers		65,621		6,420		—			72,041
Intersegment revenues		4,459		—		—			4,459
Operating income (loss)		6,856		163		(489	)		6,530

Nine months ended September 30, 2005:
Operating revenues from external customers		50,767		5,501		—			56,268
Intersegment revenues		3,691		—		—			3,691
Operating income (loss)		3,776		88		(402	)		3,462

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


	September 30, 2006		December 31, 2005
Refining	$	32,723	$	29,609
Retail		1,833		1,865
Corporate		2,086		1,324

Total consolidated assets	$	36,642	$	32,798

The entire balance of goodwill as of September 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 nine months ended September 30, 2005 was $20 million and $39 million, respectively, net of tax benefits of $10 million and $21 million, respectively. Because we accounted for our employee stock compensation plans using the intrinsic value

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

method, compensation cost was not recognized in the consolidated statements of income for the three or nine months ended September 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 nine months ended September 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			Nine Months Ended
	September 30, 2005
Net income applicable to common stock, as reported	$	858		$	2,231
Deduct: Compensation expense on stock options determined under fair value method for all awards, net of related tax effects		(4	)		(13	)

Pro forma net income applicable to common stock	$	854		$	2,218

Earnings per common share:
As reported	$	1.56		$	4.25
Pro forma		1.55			4.22

Net income, as reported	$	862		$	2,243
Deduct: Compensation expense on stock options determined under fair value method for all awards, net of related tax effects		(4	)		(13	)

Pro forma net income	$	858		$	2,230

Earnings per common share – assuming dilution:
As reported	$	1.47		$	3.96
Pro forma		1.46			3.94

Subsequent to the adoption of Statement No. 123R, our total stock-based compensation expense recognized for the three and nine months ended September 30, 2006 was $12 million and $46 million, respectively, net of tax benefits of $6 million and $24 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 nine months ended September 30, 2005 would have been less than $1 million and less than $2 million, respectively, and the impact on net income applicable to common stock and net income for the three and nine months ended September 30, 2006, would have been less than $1 million and less than $3 million, respectively.

As of September 30, 2006, we had 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 September 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 with initial grants of 5,000 stock options to purchase our common stock upon their election to our board of directors and annual grants of 1,000 stock options upon their continued service on the board of directors. As of September 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 September 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 September 30, 2006, a total of 5,530,827 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 $249 million and $177 million, respectively, for the nine months ended September 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	24,296			59.79
Exercised	(7,127,366	)		11.36
Forfeited	(137,182	)		29.72

Outstanding at September 30, 2006	35,002,725			13.68	5.1	$	1,323

Exercisable at September 30, 2006	24,222,671			8.63	4.2		1,038

There were no significant stock options granted during the nine months ended September 30, 2006 and 2005. As of September 30, 2006, there was $54 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 1.3 years. The total intrinsic value of stock options exercised during the three months ended September 30, 2006 and 2005 was $105 million and $82 million, respectively, and during the nine months ended September 30, 2006 and 2005 was $355 million and $173 million, respectively. Cash received from stock option exercises for the three months ended September 30, 2006 and 2005 was $29 million and $67 million, respectively, and for the nine months ended September 30, 2006 and 2005 was $70 million and $89 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	13,078			61.72
Vested	(66,222	)		18.33
Forfeited	(8,860	)		39.08

Nonvested shares at September 30, 2006	1,501,674			28.11

As of September 30, 2006, there was $34 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 are subject to vesting in three annual amounts beginning generally one year after the date of grant. The number of shares earned each year is based on the vested award adjusted by a factor 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 nine months ended September 30, 2006, 78,660 performance awards were granted and 11,033 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 nine months ended September 30, 2006 and 2005 was $263 million and $14 million, respectively.

Restricted Stock Units

As of September 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 nine months ended September 30, 2006. Based on the price of our common stock on September 30, 2006, the fair value of the unvested restricted stock units was $35 million, of which $24 million was recognized as of September 30, 2006.

October 2006 Grants

On October 19, 2006, the compensation committee of our board of directors approved the grant of 2,316,875 stock options and 465,560 shares of restricted stock to our employees. The stock options were granted at an exercise price equal to the market price of our common stock on the date of grant.

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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 nine months ended September 30, 2006 and 2005 (in millions):


	Pension Plans						Other Postretirement Benefit Plans
	2006			2005			2006			2005
Three months ended September 30:
Components of net periodic benefit cost:
Service cost	$	23		$	17		$	3		$	3
Interest cost		16			14			6			5
Expected return on plan assets		(14	)		(13	)		—			—
Amortization of:
Prior service cost		1			1			(2	)		(2	)
Net loss		3			3			2			1

Net periodic benefit cost	$	29		$	22		$	9		$	7

Nine months ended September 30:
Components of net periodic benefit cost:
Service cost	$	73		$	50		$	10		$	7
Interest cost		48			41			18			13
Expected return on plan assets		(43	)		(36	)		—			—
Amortization of:
Prior service cost		2			2			(7	)		(5	)
Net loss		10			7			5			5

Net periodic benefit cost	$	90		$	64		$	26		$	20

Our minimum required contribution to our qualified pension plans during 2006 under the Employee Retirement Income Security Act was less than $5 million. For the nine months ended September 30, 2006 and 2005, we contributed $143 million and $60 million, respectively, to our qualified pension plans.

14. COMMITMENTS AND CONTINGENCIES

Accounts Receivable Sales Facility

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

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table summarizes the aggregate payments we have made through September 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 September 30, 2006		Annual Maximum Limit		Aggregate Limit
Basis Petroleum, Inc.	$	200	$	35	$	200
St. Charles Refinery		100		50		175
Delaware City Refinery		25		25		50

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 September 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 and third quarters of 2006, we received $13 million and $30 million, respectively, related to our business interruption insurance claims for which income recognition has been deferred as of September 30, 2006 pending final settlement with the insurance carriers.

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 $1.4 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 November 1, 2006, we were named as a defendant in 72 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, are likely to be set for trial in 2008. Activity in the “non-focus” cases is generally stayed. We believe that we have strong defenses to these claims and are vigorously defending the cases. We have recorded a loss contingency liability with respect to this matter in accordance with FASB Statement No. 5. However, due to the inherent uncertainty of litigation, we believe that it is reasonably possible (as defined in FASB Statement No. 5) that we may suffer a loss with respect to one or more of the lawsuits in excess of the amount accrued. We believe that such an outcome in any one of these lawsuits would not have a material adverse effect on our results of operations or financial position. However, we believe that an adverse result in all or a substantial number of these cases could have a material effect on our results of operations and financial position. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.

Rosolowski

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. The lawsuit, filed October 11, 1995, relates in part to a release to the atmosphere of spent catalyst containing low levels of metals from the now-closed Blue Island, Illinois refinery on October 7, 1994. The release resulted in a temporary evacuation of certain areas near the refinery. The case was certified as a class action in 2000 with three classes: (i) Class A: persons purportedly affected by the 1994 catalyst release, but with no permanent health effects; (ii) Class B: persons with medical expenses for dependents purportedly affected by the 1994 release; and (iii) Class C: local residents claiming property damage or loss of use and enjoyment of their property over a period of several years. In November 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. On November 3, 2006, the trial judge (i) upheld the jury’s award of $100,000 for Class A and no damages for Class B, (ii) decertified Class C, and (iii) vacated the jury’s award to Class C of $80 million in compensatory damages and $40 million in punitive damages. We have recorded a loss contingency liability with respect to this matter in accordance with FASB Statement No. 5. 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 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 September 30, 2006

(unaudited, in millions)


	Valero Energy Corporation			PRG			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and temporary cash investments	$	621		$	—		$	408		$	—		$	1,029
Restricted cash		22			2			7			—			31
Receivables, net		—			71			3,534			—			3,605
Inventories		—			364			4,302			—			4,666
Income taxes receivable		—			1			78			(12	)		67
Deferred income taxes		—			—			156			—			156
Prepaid expenses and other		—			13			164			—			177

Total current assets		643			451			8,649			(12	)		9,731

Property, plant and equipment, at cost		—			7,181			16,485			—			23,666
Accumulated depreciation		—			(212	)		(2,890	)		—			(3,102	)

Property, plant and equipment, net		—			6,969			13,595			—			20,564

Intangible assets, net		—			3			306			—			309
Goodwill		—			1,872			2,391			—			4,263
Investment in Valero Energy affiliates		5,716			1,385			882			(7,983	)		—
Long-term notes receivable from affiliates		16,924			—			—			(16,924	)		—
Investment in Valero L.P.		—			—			480			—			480
Deferred charges and other assets, net		120			233			942			—			1,295

Total assets	$	23,403		$	10,913		$	27,245		$	(24,919	)	$	36,642

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	234		$	1		$	3		$	—		$	238
Accounts payable		69			341			5,734			—			6,144
Accrued expenses		114			72			362			—			548
Taxes other than income taxes		—			18			532			—			550
Income taxes payable		188			—			—			(12	)		176
Deferred income taxes		109			272			—			—			381

Total current liabilities		714			704			6,631			(12	)		8,037

Long-term debt and capital lease obligations, less current portion		3,329			1,523			45			—			4,897

Long-term notes payable to affiliates		—			7,400			9,524			(16,924	)		—

Deferred income taxes		915			181			3,065			—			4,161

Other long-term liabilities		630			223			653			—			1,506

Minority interest in consolidated subsidiary		—			—			226			—			226

Stockholders’ equity:
Common stock		6			—			2			(2	)		6
Additional paid-in capital		7,774			100			1,621			(1,721	)		7,774
Treasury stock		(1,281	)		—			—			—			(1,281	)
Retained earnings		10,885			782			5,478			(6,260	)		10,885
Accumulated other comprehensive income		431			—			—			—			431

Total stockholders’ equity		17,815			882			7,101			(7,983	)		17,815

Total liabilities and stockholders’ equity	$	23,403		$	10,913		$	27,245		$	(24,919	)	$	36,642

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			69			3,494			—			3,564
Inventories		—			380			3,659			—			4,039
Income taxes receivable		68			379			1			(378	)		70
Deferred income taxes		—			—			195			(53	)		142
Prepaid expenses and other		—			7			58			—			65

Total current assets		102			842			7,833			(431	)		8,346

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	$	19,898		$	8,990		$	24,866		$	(20,956	)	$	32,798

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		121			1			365			(378	)		109
Deferred income taxes		—			358			—			(53	)		305

Total current liabilities		508			872			6,426			(431	)		7,375

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	$	19,898		$	8,990		$	24,866		$	(20,956	)	$	32,798

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

(unaudited, in millions)


	Valero Energy Corporation			PRG			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues	$	—		$	7,395		$	23,915		$	(6,991	)	$	24,319

Costs and expenses:
Cost of sales		—			6,985			20,425			(6,991	)		20,419
Refining operating expenses		—			222			707			—			929
Retail selling expenses		—			—			208			—			208
General and administrative expenses		—			—			136			—			136
Depreciation and amortization expense		—			68			226			—			294

Total costs and expenses		—			7,275			21,702			(6,991	)		21,986

Operating income		—			120			2,213			—			2,333
Equity in earnings of subsidiaries		1,429			353			294			(2,076	)		—
Equity in earnings of Valero L.P.		—			—			13			—			13
Other income (expense), net		320			(82	)		365			(460	)		143
Interest and debt expense:
Incurred		(101	)		(152	)		(298	)		460			(91	)
Capitalized		—			18			27			—			45

Minority interest in net income of consolidated subsidiary		—			—			(4	)		—			(4	)

Income before income tax expense		1,648			257			2,610			(2,076	)		2,439
Income tax expense (1)		45			(37	)		828			—			836

Net income	$	1,603		$	294		$	1,782		$	(2,076	)	$	1,603

(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 Statements of Income for the Three Months Ended September 30, 2005

(unaudited, in millions)


	Valero Energy Corporation			PRG (1)			Other Non-Guarantor Subsidiaries (1)			Eliminations			Consolidated
Operating revenues	$	—		$	5,447		$	17,995		$	(159	)	$	23,283

Costs and expenses:
Cost of sales		—			5,726			15,071			(159	)		20,638
Refining operating expenses		—			82			677			—			759
Retail selling expenses		—			—			197			—			197
General and administrative expenses		—			15			144			—			159
Depreciation and amortization expense		—			11			208			—			219

Total costs and expenses		—			5,834			16,297			(159	)		21,972

Operating income (loss)		—			(387	)		1,698			—			1,311
Equity in earnings (loss) of subsidiaries		836			77			(154	)		(759	)		—
Equity in earnings of Valero L.P.		—			—			13			—			13
Other income (expense), net		126			3			9			(127	)		11
Interest and debt expense:
Incurred		(85	)		(9	)		(118	)		127			(85	)
Capitalized		—			3			15			—			18

Income (loss) before income tax expense		877			(313	)		1,463			(759	)		1,268
Income tax expense (benefit) (2)		15			(159	)		550			—			406

Net income (loss)		862			(154	)		913			(759	)		862
Preferred stock dividends		4			—			—			—			4

Net income (loss) applicable to common stock	$	858		$	(154	)	$	913		$	(759	)	$	858

(1)	Includes the operations related to PRG and other Premcor subsidiaries commencing on September 1, 2005.

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

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2006

(unaudited, in millions)


	Valero Energy Corporation			PRG			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues	$	—		$	21,401		$	71,095		$	(20,455	)	$	72,041

Costs and expenses:
Cost of sales		—			19,788			61,468			(20,455	)		60,801
Refining operating expenses		—			678			2,126			—			2,804
Retail selling expenses		—			—			601			—			601
General and administrative expenses		2			26			430			—			458
Depreciation and amortization expense		—			215			632			—			847

Total costs and expenses		2			20,707			65,257			(20,455	)		65,511

Operating income (loss)		(2	)		694			5,838			—			6,530
Equity in earnings of subsidiaries		3,899			681			782			(5,362	)		—
Equity in earnings of Valero L.P.		—			—			35			—			35
Other income (expense), net		1,041			(86	)		943			(1,760	)		138
Interest and debt expense:
Incurred		(379	)		(548	)		(1,113	)		1,760			(280	)
Capitalized		—			49			80			—			129

Minority interest in net income of consolidated subsidiary		—			—			(4	)		—			(4	)

Income before income tax expense		4,559			790			6,561			(5,362	)		6,548
Income tax expense (1)		210			8			1,981			—			2,199

Net income		4,349			782			4,580			(5,362	)		4,349
Preferred stock dividends		2			—			—			—			2

Net income applicable to common stock	$	4,347		$	782		$	4,580		$	(5,362	)	$	4,347

(1)	The income tax expense 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 Statements of Income for the Nine Months Ended September 30, 2005

(unaudited, in millions)


	Valero Energy Corporation			PRG (1)			Other Non-Guarantor Subsidiaries (1)			Eliminations			Consolidated
Operating revenues	$	—		$	5,447		$	51,371		$	(550	)	$	56,268

Costs and expenses:
Cost of sales		—			5,726			44,213			(550	)		49,389
Refining operating expenses		—			82			1,821			—			1,903
Retail selling expenses		—			—			551			—			551
General and administrative expenses		2			15			358			—			375
Depreciation and amortization expense		—			11			577			—			588

Total costs and expenses		2			5,834			47,520			(550	)		52,806

Operating income (loss)		(2	)		(387	)		3,851			—			3,462
Equity in earnings (loss) of subsidiaries		2,151			77			(154	)		(2,074	)		—
Equity in earnings of Valero L.P.		—			—			32			—			32
Other income (expense), net		396			3			13			(416	)		(4	)
Interest and debt expense:
Incurred		(250	)		(9	)		(387	)		416			(230	)
Capitalized		—			3			36			—			39

Income (loss) before income tax expense		2,295			(313	)		3,391			(2,074	)		3,299
Income tax expense (benefit) (2)		52			(159	)		1,163			—			1,056

Net income (loss)		2,243			(154	)		2,228			(2,074	)		2,243
Preferred stock dividends		12			—			—			—			12

Net income (loss) applicable to common stock	$	2,231		$	(154	)	$	2,228		$	(2,074	)	$	2,231

(1)	Includes the operations related to PRG and other Premcor subsidiaries commencing on September 1, 2005.

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

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2006

(unaudited, in millions)


	Valero Energy Corporation			PRG			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	823		$	349		$	3,924		$	—		$	5,096

Cash flows from investing activities:
Capital expenditures		—			(796	)		(1,535	)		—			(2,331	)
Deferred turnaround and catalyst costs		—			(146	)		(318	)		—			(464	)
Contingent payments in connection with acquisitions		—			(25	)		(76	)		—			(101	)
Proceeds from sale of interest in Valero GP Holdings, LLC		—			—			355			—			355
Net intercompany receipts		1,755			—			—			(1,755	)		—
Other investing activities, net		—			(3	)		32			—			29

Net cash provided by (used in) investing activities		1,755			(970	)		(1,542	)		(1,755	)		(2,512	)

Cash flows from financing activities:
Long-term note repayments		(221	)		(28	)		—			—			(249	)
Bank credit agreements:
Borrowings		8			—			699			—			707
Repayments		(8	)		—			(698	)		—			(706	)
Termination of interest rate swaps		(54	)		—			—			—			(54	)
Purchase of treasury stock		(1,818	)		—			—			—			(1,818	)
Benefit from tax deduction in excess of recognized stock-based compensation cost		160			—			—			—			160
Net intercompany borrowings (repayments)		—			644			(2,399	)		1,755			—
Other financing activities, net		(35	)		—			(2	)		—			(37	)

Net cash provided by (used in) financing activities		(1,968	)		616			(2,400	)		1,755			(1,997	)

Effect of foreign exchange rate changes on cash		—			—			6			—			6

Net increase (decrease) in cash and temporary cash investments		610			(5	)		(12	)		—			593
Cash and temporary cash investments at beginning of period		11			5			420			—			436

Cash and temporary cash investments at end of period	$	621		$	—		$	408		$	—		$	1,029

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2005

(unaudited, in millions)


	Valero Energy Corporation			PRG (1)			Other Non- Guarantor Subsidiaries (1)			Eliminations			Consolidated
Net cash provided by operating activities	$	145		$	79		$	3,659		$	—		$	3,883

Cash flows from investing activities:
Capital expenditures		—			(66	)		(1,223	)		—			(1,289	)
Deferred turnaround and catalyst costs		—			(6	)		(256	)		—			(262	)
Premcor Acquisition, net of cash acquired		(2,343	)		—			—			—			(2,343	)
Contingent payments in connection with acquisitions		—			—			(85	)		—			(85	)
Net intercompany receipts		1,947			—			—			(1,947	)		—
Other investing activities, net		—			—			10			—			10

Net cash used in investing activities		(396	)		(72	)		(1,554	)		(1,947	)		(3,969	)

Cash flows from financing activities:
Long-term note repayments		(491	)		(190	)		—			—			(681	)
Bank credit agreements:
Borrowings		1,597			—			20			—			1,617
Repayments		(797	)		—			(20	)		—			(817	)
Purchase of treasury stock		(188	)		—			—			—			(188	)
Net intercompany borrowings (repayments)		—			208			(2,155	)		1,947			—
Other financing activities, net		29			—			(2	)		—			27

Net cash provided by (used in) financing activities		150			18			(2,157	)		1,947			(42	)

Effect of foreign exchange rate changes on cash		—			—			1			—			1

Net increase (decrease) in cash and temporary cash investments		(101	)		25			(51	)		—			(127	)
Cash and temporary cash investments at beginning of period		322			—			542			—			864

Cash and temporary cash investments at end of period	$	221		$	25		$	491		$	—		$	737

(1)	Includes the operations related to PRG and other Premcor subsidiaries commencing on September 1, 2005.

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 have continued during the first nine months 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 have resulted in tighter supplies of refined products and strong margins during most of the nine-month period. Although gasoline margins declined significantly during the latter half of the third quarter of 2006, distillate margins and sour crude oil discounts remained strong throughout the quarter. We also continued to benefit from the addition of the four former Premcor refineries, which generated $716 million of operating income with average throughput volumes of 797,000 barrels per day during the third quarter of 2006 and $2.0 billion of operating income with average throughput volumes of 789,000 barrels per day for the first nine months of 2006. However, during the first nine months of 2006, we had significant unplanned downtime at several of our refineries that partially offset these positive factors.

Favorable gasoline and distillate margins, continuing wide sour crude oil discounts and the full-year effect of the Premcor Acquisition on September 1, 2005 contributed to strong operating results in the third quarter and first nine months of 2006. In addition, during the third quarter of 2006, we recognized a pre-tax gain of $132 million related to the sale of 40.6% of our ownership interest in Valero GP Holdings, LLC. We reported net income of $1.6 billion, or $2.55 per share, for the third quarter of 2006, compared to $862 million, or $1.47 per share, for the third quarter of 2005, and net income of $4.3 billion, or $6.83 per share, for the first nine months of 2006 compared to $2.2 billion, or $3.96 per share, for the first nine months of 2005.

Thus far in the fourth quarter, gasoline margins have recovered from the low margins experienced in September, and distillate margins and sour crude oil discounts remain favorable. Refinery maintenance in the industry is reducing utilization rates, thereby lowering production and imports. In addition, refined product demand remains strong, supported by declining retail fuel prices. 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.

RESULTS OF OPERATIONS

Third Quarter 2006 Compared to Third Quarter 2005

Financial Highlights

(millions of dollars, except per share amounts)


	Three Months Ended September 30,
	2006 (a)			2005 (a)			Change
Operating revenues (b)	$	24,319		$	23,283		$	1,036

Costs and expenses:
Cost of sales (a) (b)		20,419			20,638			(219	)
Refining operating expenses		929			759			170
Retail selling expenses		208			197			11
General and administrative expenses		136			159			(23	)
Depreciation and amortization expense:
Refining		261			186			75
Retail		21			22			(1	)
Corporate		12			11			1

Total costs and expenses		21,986			21,972			14

Operating income		2,333			1,311			1,022
Equity in earnings of Valero L.P.		13			13			—
Other income, net		143			11			132
Interest and debt expense:
Incurred		(91	)		(85	)		(6	)
Capitalized		45			18			27
Minority interest in net income of consolidated subsidiary		(4	)		—			(4	)

Income before income tax expense		2,439			1,268			1,171
Income tax expense		836			406			430

Net income		1,603			862			741
Preferred stock dividends		—			4			(4	)

Net income applicable to common stock	$	1,603		$	858		$	745

Earnings per common share – assuming dilution	$	2.55		$	1.47		$	1.08

See the footnote references on page 42.

Operating Highlights

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


	Three Months Ended September 30,
	2006 (a)			2005 (a)			Change
Refining:
Operating income (a)	$	2,385		$	1,457		$	928
Throughput margin per barrel (c)	$	12.98		$	13.43		$	(0.45	)
Operating costs per barrel:
Refining operating expenses	$	3.37		$	3.37		$	—
Depreciation and amortization		0.95			0.83			0.12

Total operating costs per barrel	$	4.32		$	4.20		$	0.12

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		619			484			135
Medium/light sour crude		637			579			58
Acidic sweet crude		83			125			(42	)
Sweet crude		916			668			248
Residuals		308			248			60
Other feedstocks		134			114			20

Total feedstocks		2,697			2,218			479
Blendstocks and other		297			227			70

Total throughput volumes		2,994			2,445			549

Yields (thousand barrels per day):
Gasolines and blendstocks		1,448			1,165			283
Distillates		952			741			211
Petrochemicals		86			66			20
Other products (d)		503			464			39

Total yields		2,989			2,436			553

Retail – U.S.:
Operating income	$	80		$	7		$	73
Company-operated fuel sites (average)		976			1,026			(50	)
Fuel volumes (gallons per day per site)		5,012			4,967			45
Fuel margin per gallon	$	0.275		$	0.121		$	0.154
Merchandise sales	$	255		$	250		$	5
Merchandise margin (percentage of sales)		29.3	%		30.1	%		(0.8	)%
Margin on miscellaneous sales	$	44		$	33		$	11
Retail selling expenses	$	149		$	142		$	7
Depreciation and amortization expense	$	15		$	16		$	(1	)

Retail – Canada:
Operating income	$	16		$	17		$	(1	)
Fuel volumes (thousand gallons per day)		3,136			3,122			14
Fuel margin per gallon	$	0.209		$	0.206		$	0.003
Merchandise sales	$	46		$	42		$	4
Merchandise margin (percentage of sales)		27.0	%		25.0	%		2.0	%
Margin on miscellaneous sales	$	9		$	8		$	1
Retail selling expenses	$	59		$	55		$	4
Depreciation and amortization expense	$	6		$	6		$	—

See the footnote references on page 42.

Refining Operating Highlights by Region (e)

(millions of dollars, except per barrel amounts)


	Three Months Ended September 30,
	2006 (a)		2005 (a)			Change
Gulf Coast:
Operating income	$	1,377	$	1,171		$	206
Throughput volumes (thousand barrels per day) (f)		1,530		1,328			202
Throughput margin per barrel (c)	$	13.92	$	13.82		$	0.10
Operating costs per barrel:
Refining operating expenses	$	3.27	$	3.46		$	(0.19	)
Depreciation and amortization		0.86		0.77			0.09

Total operating costs per barrel	$	4.13	$	4.23		$	(0.10	)

Mid-Continent:
Operating income	$	436	$	347		$	89
Throughput volumes (thousand barrels per day) (f)		568		352			216
Throughput margin per barrel (c)	$	12.43	$	14.85		$	(2.42	)
Operating costs per barrel:
Refining operating expenses	$	3.22	$	3.35		$	(0.13	)
Depreciation and amortization		0.89		0.80			0.09

Total operating costs per barrel	$	4.11	$	4.15		$	(0.04	)

Northeast:
Operating income	$	311	$	281		$	30
Throughput volumes (thousand barrels per day) (f)		583		451			132
Throughput margin per barrel (c)	$	10.61	$	10.27		$	0.34
Operating costs per barrel:
Refining operating expenses	$	3.72	$	2.74		$	0.98
Depreciation and amortization		1.09		0.76			0.33

Total operating costs per barrel	$	4.81	$	3.50		$	1.31

West Coast:
Operating income	$	261	$	279		$	(18	)
Throughput volumes (thousand barrels per day)		313		314			(1	)
Throughput margin per barrel (c)	$	13.78	$	14.78		$	(1.00	)
Operating costs per barrel:
Refining operating expenses	$	3.49	$	3.91		$	(0.42	)
Depreciation and amortization		1.23		1.22			0.01

Total operating costs per barrel	$	4.72	$	5.13		$	(0.41	)

Operating income for regions above	$	2,385	$	2,078		$	307
LIFO charge (a)		—		(621	)		621

Total refining operating income	$	2,385	$	1,457		$	928

See the footnote references on page 42.

Average Market Reference Prices and Differentials (g)

(dollars per barrel)


	Three Months Ended September 30,
	2006		2005			Change
Feedstocks:
West Texas Intermediate (WTI) crude oil	$	70.37	$	63.05		$	7.32
WTI less sour crude oil at U.S. Gulf Coast (h)		6.14		5.26			0.88
WTI less Alaska North Slope (ANS) crude oil		1.43		2.26			(0.83	)
WTI less Maya crude oil		14.87		15.46			(0.59	)

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		12.00		19.38			(7.38	)
No. 2 fuel oil less WTI		8.99		13.48			(4.49	)
Propylene less WTI		13.08		(4.95	)		18.03
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		15.18		17.41			(2.23	)
Low-sulfur diesel less WTI		22.89		16.35			6.54
U.S. Northeast:
Conventional 87 gasoline less WTI		11.83		15.98			(4.15	)
No. 2 fuel oil less WTI		7.96		12.47			(4.51	)
Lube oils less WTI		57.85		32.32			25.53
U.S. West Coast:
CARBOB 87 gasoline less ANS		20.15		25.54			(5.39	)
Low-sulfur diesel less ANS		22.88		24.56			(1.68	)

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

(a)

Includes the operations related to the Premcor Acquisition commencing on September 1, 2005. Cost of sales and refining operating income presented for the three months ended September 30, 2005 include the effect of a $621 million LIFO charge related to the difference between the fair market value recorded for the inventories acquired in the Premcor Acquisition under purchase accounting and the amounts required to be recorded in applying Valero’s LIFO accounting policy. This charge was excluded from the consolidated and regional throughput margins per barrel and the regional operating income amounts presented herein in order to make the information presented comparable between periods.

(b)

Operating revenues and cost of sales both include approximately $2.3 billion for the three months ended September 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.

(f)

Throughput volumes for the Gulf Coast, Mid-Continent and Northeast regions for the three months ended September 30, 2006 include 277,000, 321,000 and 199,000 barrels per day, respectively, related to the operations of the refineries acquired from Premcor on September 1, 2005. Throughput volumes for the Gulf Coast, Mid-Continent and Northeast regions for the three months ended September 30, 2005 include 66,000, 100,000 and 66,000 barrels per day, respectively, related to the operations of the refineries acquired from Premcor commencing on September 1, 2005. Throughput volumes for those acquired refineries for the 30 days of their operations subsequent to the acquisition date of September 1, 2005 were 203,000, 306,000, and 203,000 barrels per day, respectively, for the Gulf Coast, Mid-Continent and Northeast regions.

(g)

Commodity Information Services-London Oil Reports. The average market reference prices and differentials are presented to provide users of the consolidated financial statements with economic indicators that significantly affect our operations and profitability.

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

General

Operating revenues increased 4% for the third quarter of 2006 compared to the third quarter of 2005 primarily as a result of the additional throughput volumes from the former Premcor refinery operations. Operating income of $2.3 billion and net income of $1.6 billion increased significantly from the third quarter of 2005 to the third quarter of 2006 due to a $928 million increase in refining segment operating income, a $72 million increase in retail segment operating income and a $22 million decrease in general and administrative expenses (including corporate depreciation and amortization expense). The increase in third quarter 2006 results was partially attributable to the unfavorable impact in the third quarter of 2005 of a $621 million pre-tax, or $0.72 per share, LIFO charge related to the difference between the fair market value recorded for the inventories acquired in the Premcor Acquisition under purchase accounting and the amounts required to be recorded in applying Valero’s LIFO accounting policy.

Refining

Operating income for our refining segment increased from $1.5 billion for the third quarter of 2005 to $2.4 billion for the third quarter of 2006, resulting from a 22% increase in throughput volumes and the 2005 LIFO charge discussed above, partially offset by increased refining operating expenses (including depreciation and amortization expense) of $245 million and a 3% decline in the refining throughput margin per barrel.

Refining throughput margins for the third quarter of 2006 compared to the third quarter of 2005 were impacted by the following factors:

•

Throughput volumes increased 549,000 barrels per day in the third quarter of 2006 compared to the third quarter of 2005 due to 565,000 barrels per day of incremental throughput from the four former Premcor refineries.

•

Overall gasoline and distillate margins decreased in the third quarter of 2006 compared to the very strong margins in the third quarter of 2005. The decline in refined product margins for the third quarter of 2006 was primarily due to excess refined product supply and the higher margins experienced in the third quarter of 2005 due to the impact of Hurricanes Katrina and Rita.

•

Discounts on sour crude oil feedstocks during the third quarter of 2006 were essentially unchanged from the strong discounts in the third quarter of 2005, and remained wide 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.

Refining operating expenses, excluding depreciation and amortization expense, were 22% higher for the quarter ended September 30, 2006 compared to the quarter ended September 30, 2005, due primarily to the Premcor Acquisition on September 1, 2005. Excluding the effect of the Premcor Acquisition, operating expenses decreased 2% due mainly to decreases in energy and insurance costs, partially offset by increases in maintenance expense, employee compensation and related benefits, catalyst and chemicals and outside services. Refining depreciation and amortization expense increased 40% from the third quarter of 2005 to the third quarter of 2006 primarily due to the Premcor Acquisition, the implementation of new capital projects and increased turnaround and catalyst amortization.

Retail

Retail operating income of $96 million for the quarter ended September 30, 2006 was 300% higher than the $24 million reported for the quarter ended September 30, 2005. This significant increase in operating income was mainly attributable to a $0.15 per gallon increase in average fuel margins in our U.S. retail operations.

Corporate Expenses and Other

General and administrative expenses, including corporate depreciation and amortization expense, decreased $22 million from the third quarter of 2005 to the third quarter of 2006. The decrease was primarily due to a decline in variable compensation expense.

“Other income, net” for the third quarter of 2006 includes a pre-tax gain of $132 million related to the sale of 40.6% of our ownership interest in Valero GP Holdings, LLC in July 2006.

Interest and debt expense incurred increased from the third quarter of 2005 to the third 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 $430 million from the third quarter of 2005 to the third quarter of 2006 mainly as a result of higher operating income. Our effective tax rate for the quarter ended September 30, 2006 increased from the quarter ended September 30, 2005 as a lower percentage of our pre-tax income was contributed by the Aruba Refinery, the profits of which are non-taxable in Aruba through December 31, 2010.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Financial Highlights

(millions of dollars, except per share amounts)


	Nine Months Ended September 30,
	2006 (a)			2005 (a)			Change
Operating revenues (b)	$	72,041		$	56,268		$	15,773

Costs and expenses:
Cost of sales (a) (b)		60,801			49,389			11,412
Refining operating expenses		2,804			1,903			901
Retail selling expenses		601			551			50
General and administrative expenses		458			375			83
Depreciation and amortization expense:
Refining		754			502			252
Retail		62			59			3
Corporate		31			27			4

Total costs and expenses		65,511			52,806			12,705

Operating income		6,530			3,462			3,068
Equity in earnings of Valero L.P.		35			32			3
Other income (expense), net		138			(4	)		142
Interest and debt expense:
Incurred		(280	)		(230	)		(50	)
Capitalized		129			39			90
Minority interest in net income of consolidated subsidiary		(4	)		—			(4	)

Income before income tax expense		6,548			3,299			3,249
Income tax expense		2,199			1,056			1,143

Net income		4,349			2,243			2,106
Preferred stock dividends		2			12			(10	)

Net income applicable to common stock	$	4,347		$	2,231		$	2,116

Earnings per common share – assuming dilution	$	6.83		$	3.96		$	2.87

See the footnote references on page 48.

Operating Highlights

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


	Nine Months Ended September 30,
	2006 (a)			2005 (a)			Change
Refining:
Operating income (a)	$	6,856		$	3,776		$	3,080
Throughput margin per barrel (c)	$	12.88		$	10.80		$	2.08
Operating costs per barrel:
Refining operating expenses	$	3.47		$	3.02		$	0.45
Depreciation and amortization		0.93			0.80			0.13

Total operating costs per barrel	$	4.40		$	3.82		$	0.58

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude		685			495			190
Medium/light sour crude		611			582			29
Acidic sweet crude		67			112			(45	)
Sweet crude		891			591			300
Residuals		247			183			64
Other feedstocks		156			124			32

Total feedstocks		2,657			2,087			570
Blendstocks and other		304			220			84

Total throughput volumes		2,961			2,307			654

Yields (thousand barrels per day):
Gasolines and blendstocks		1,432			1,086			346
Distillates		929			697			232
Petrochemicals		86			67			19
Other products (d)		513			459			54

Total yields		2,960			2,309			651

Retail – U.S.:
Operating income	$	104		$	28		$	76
Company-operated fuel sites (average)		987			1,029			(42	)
Fuel volumes (gallons per day per site)		4,937			4,863			74
Fuel margin per gallon	$	0.174		$	0.118		$	0.056
Merchandise sales	$	725		$	710		$	15
Merchandise margin (percentage of sales)		29.8	%		29.7	%		0.1	%
Margin on miscellaneous sales	$	125		$	91		$	34
Retail selling expenses	$	427		$	393		$	34
Depreciation and amortization expense	$	43		$	42		$	1

Retail – Canada:
Operating income	$	59		$	60		$	(1	)
Fuel volumes (thousand gallons per day)		3,178			3,192			(14	)
Fuel margin per gallon	$	0.224		$	0.210		$	0.014
Merchandise sales	$	125		$	112		$	13
Merchandise margin (percentage of sales)		27.6	%		25.4	%		2.2	%
Margin on miscellaneous sales	$	24		$	23		$	1
Retail selling expenses	$	174		$	158		$	16
Depreciation and amortization expense	$	19		$	17		$	2

See the footnote references on page 48.

Refining Operating Highlights by Region (e)

(millions of dollars, except per barrel amounts)


	Nine Months Ended September 30,
	2006 (a)		2005 (a)			Change
Gulf Coast:
Operating income	$	4,095	$	2,637		$	1,458
Throughput volumes (thousand barrels per day) (f)		1,543		1,289			254
Throughput margin per barrel (c)	$	13.79	$	11.17		$	2.62
Operating costs per barrel:
Refining operating expenses	$	3.24	$	2.95		$	0.29
Depreciation and amortization		0.83		0.72			0.11

Total operating costs per barrel	$	4.07	$	3.67		$	0.40

Mid-Continent (g):
Operating income	$	1,119	$	496		$	623
Throughput volumes (thousand barrels per day) (f)		552		302			250
Throughput margin per barrel (c)	$	11.54	$	9.93		$	1.61
Operating costs per barrel:
Refining operating expenses	$	3.23	$	3.23		$	—
Depreciation and amortization		0.89		0.70			0.19

Total operating costs per barrel	$	4.12	$	3.93		$	0.19

Northeast:
Operating income	$	781	$	506		$	275
Throughput volumes (thousand barrels per day) (f)		560		406			154
Throughput margin per barrel (c)	$	10.24	$	7.88		$	2.36
Operating costs per barrel:
Refining operating expenses	$	4.04	$	2.54		$	1.50
Depreciation and amortization		1.09		0.78			0.31

Total operating costs per barrel	$	5.13	$	3.32		$	1.81

West Coast:
Operating income	$	861	$	758		$	103
Throughput volumes (thousand barrels per day)		306		310			(4	)
Throughput margin per barrel (c)	$	15.56	$	13.94		$	1.62
Operating costs per barrel:
Refining operating expenses	$	3.98	$	3.73		$	0.25
Depreciation and amortization		1.26		1.24			0.02

Total operating costs per barrel	$	5.24	$	4.97		$	0.27

Operating income for regions above	$	6,856	$	4,397		$	2,459
LIFO charge (a)		—		(621	)		621

Total refining operating income	$	6,856	$	3,776		$	3,080

See the footnote references on page 48.

Average Market Reference Prices and Differentials (h)

(dollars per barrel)


	Nine Months Ended September 30,
	2006		2005		Change
Feedstocks:
WTI crude oil	$	68.02	$	55.26	$	12.76
WTI less sour crude oil at U.S. Gulf Coast (i)		7.12		6.68		0.44
WTI less ANS crude oil		1.82		3.36		(1.54	)
WTI less Maya crude oil		15.39		15.20		0.19

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less WTI		13.34		11.63		1.71
No. 2 fuel oil less WTI		9.87		10.15		(0.28	)
Propylene less WTI		10.25		6.61		3.64
U.S. Mid-Continent:
Conventional 87 gasoline less WTI		14.10		11.70		2.40
Low-sulfur diesel less WTI		18.96		13.09		5.87
U.S. Northeast:
Conventional 87 gasoline less WTI		11.84		9.60		2.24
No. 2 fuel oil less WTI		9.57		10.80		(1.23	)
Lube oils less WTI		51.53		29.74		21.79
U.S. West Coast:
CARBOB 87 gasoline less ANS		22.82		22.04		0.78
Low-sulfur diesel less ANS		23.32		20.94		2.38

The following notes relate to references on pages 45 through 48.

(a)

Includes the operations related to the Premcor Acquisition commencing on September 1, 2005. Cost of sales and refining operating income presented for the nine months ended September 30, 2005 include the effect of a $621 million LIFO charge related to the difference between the fair market value recorded for the inventories acquired in the Premcor Acquisition under purchase accounting and the amounts required to be recorded in applying Valero’s LIFO accounting policy. This charge was excluded from the consolidated and regional throughput margins per barrel and the regional operating income amounts presented herein in order to make the information presented comparable between periods.

(b)

Operating revenues and cost of sales both include approximately $5.1 billion for the nine months ended September 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 nine months ended September 30, 2006 include 291,000, 297,000 and 201,000 barrels per day, respectively, related to the operations of the refineries acquired from Premcor on September 1, 2005. Throughput volumes for the Gulf Coast, Mid-Continent and Northeast regions for the nine months ended September 30, 2005 include 22,000, 34,000, and 22,000 barrels per day, respectively, related to the operations of the refineries acquired from Premcor commencing on September 1, 2005. Throughput volumes for those acquired refineries for the 30 days of their operations subsequent to the acquisition date of September 1, 2005 were 203,000, 306,000, and 203,000 barrels per day, respectively, for the Gulf Coast, Mid-Continent and Northeast regions.

(g)	For the nine months ended September 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 nine months ended September 30, 2005 include 21,000 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 28% for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 primarily as a result of higher refined product prices combined with additional throughput volumes from the former Premcor refinery operations. Operating income and net income for the first nine months of 2006 nearly doubled compared to the first nine months of 2005. Operating income increased $3.1 billion, or 89%, and net income increased $2.1 billion, or 94%, from the nine months ended September 30, 2005 to the nine months ended September 30, 2006 primarily due to a $3.1 billion increase in refining segment operating income, including $621 million attributable to the 2005 LIFO charge discussed in the quarter-to-quarter results of operations above.

Refining

Operating income for our refining segment increased from $3.8 billion for the nine months ended September 30, 2005 to $6.9 billion for the nine months ended September 30, 2006, resulting from a 28% increase in throughput volumes, the 2005 LIFO charge discussed above, and an increase in refining throughput margin of $2.08 per barrel, or 19%, partially offset by increased refining operating expenses (including depreciation and amortization expense) of $1.2 billion.

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

•

Throughput volumes increased 654,000 barrels per day during the first nine months of 2006 compared to the first nine months of 2005 due to 711,000 barrels per day of 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 in 2006.

•

Overall, gasoline and distillate margins increased in the first nine months of 2006 compared to the first nine months of 2005 due to significantly improved margins in the first six months of 2006 attributable to increased foreign and U.S. demand, limited capacity additions, major industry turnaround activity, and continuing outages from last season’s hurricanes. However, the year-to-date increase in gasoline and distillate margins diminished somewhat in the third quarter of 2006 due to the factors discussed in the quarter-to-quarter results of operations above.

•

Throughput margin improved due to the negative impact in the first nine months of 2005 of pre-tax losses of approximately $360 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 and sulfur due to a significant increase in the price of crude oil from the first nine months of 2005 to the first nine months of 2006.

Refining operating expenses, excluding depreciation and amortization expense, were 47% higher for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, due

primarily to the Premcor Acquisition on September 1, 2005. Excluding the effect of the Premcor Acquisition, operating expenses increased 7% due mainly to increases in maintenance expense, employee compensation and related benefits, catalyst and chemicals and outside services, partially offset by reduced energy costs. Refining depreciation and amortization expense increased 50% from the first nine months of 2005 to the first nine 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 $163 million for the nine months ended September 30, 2006 compared to $88 million for the nine months ended September 30, 2005. This 85% increase in operating income was primarily attributable to significantly higher U.S. retail fuel margins.

Corporate Expenses and Other

General and administrative expenses, including corporate depreciation and amortization expense, increased $87 million from the first nine months of 2005 to the first nine months of 2006. The increase was primarily due to increases in employee compensation and benefits, stock-based compensation expense, legal and regulatory costs, charitable contributions and environmental expenses, 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.

“Other income (expense), net” for the first nine months of 2006 includes a pre-tax gain of $132 million related to the sale of 40.6% of our ownership interest in Valero GP Holdings, LLC in July 2006.

Interest and debt expense incurred increased from the first nine months of 2005 to the first nine 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 $1.1 billion from the first nine months of 2005 to the first nine months of 2006 mainly as a result of higher operating income. Our effective tax rate for the nine months ended September 30, 2006 increased from the nine months ended September 30, 2005 as a lower percentage of our pre-tax income was contributed by the Aruba Refinery, the profits 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

Despite the volatility in gasoline margins experienced in the third quarter, we expect refining industry fundamentals to be favorable during the fourth quarter of 2006. While the gasoline margins experienced thus far in the fourth quarter of 2006 have improved from September levels, they are expected to remain below the above-average margins experienced in the fourth quarter of 2005 which were supported by last year’s hurricanes. Distillate demand, like gasoline demand, has been strong thus far in the fourth quarter, but average Gulf Coast on-road diesel margins have been below the very strong margins experienced in the fourth quarter of 2005.

Despite a third quarter decline in the price of crude oil, sour crude oil discounts remained wide during the month of October 2006 and only somewhat below the sour crude oil discounts experienced in the fourth quarter of 2005. Sour crude oil discounts are expected to remain favorable for the foreseeable future due to ample supplies of sour crude oil and residual fuel oil.

Operationally, we do not have significant turnaround activity scheduled for the fourth quarter. In addition, we expect to benefit during the fourth quarter of 2006 from the completion of significant turnaround and capital improvement projects during the first nine months of 2006.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Nine Months Ended September 30, 2006 and 2005

Net cash provided by operating activities for the nine months ended September 30, 2006 was $5.1 billion compared to $3.9 billion for the nine months ended September 30, 2005. The increase in cash generated from operating activities was due primarily to the significant increase in net income discussed above under “Results of Operations,” partially offset by a $1.1 billion decrease from an unfavorable change in working capital between the years. Changes in cash provided by or used for working capital during the first nine 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 resulted from an approximate 10 million barrel increase in feedstock and refined product inventories during the first nine months of 2006 attributable mainly to a seasonal increase in refinery run rates and a build-up of refined product inventories due to the forward markets reflecting an expectation of higher prices in the future.

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

•

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

•

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

•

make long-term note repayments of $249 million,

•

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

•

terminate our interest rate swap contracts for $54 million,

•

pay common and preferred stock dividends of $136 million, and

•

increase available cash on hand by $593 million.

The net cash generated from operating activities during the first nine months of 2005, combined with $800 million of net borrowings under our bank credit facilities, $114 million of proceeds from the issuance of common stock related to Valero’s employee benefit plans, $127 million of available cash on hand, and $45 million of proceeds from the sale of the Denver Refinery were used mainly to:

•

fund $2.3 billion of the Premcor Acquisition, net of cash acquired,

•

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

•

make long-term note repayments of $681 million,

•

purchase 5.9 million shares of treasury stock at a cost of $188 million,

•

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

•

make a general partner contribution to Valero L.P. of $29 million, and

•

pay common and preferred stock dividends of $75 million.

Capital Investments

During the nine months ended September 30, 2006, we expended $2.3 billion for capital expenditures and $464 million for deferred turnaround and catalyst costs. Capital expenditures for the nine months ended September 30, 2006 included $1.2 billion 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 the third quarter of 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 $3.7 billion for capital investments, including approximately $3.2 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 our purchase of treasury stock to satisfy employee benefit plan requirements as well as purchases under our publicly announced stock purchase programs. Under these authorizations, we have purchased approximately 5% of our outstanding shares during 2006. We purchased approximately 25.1 million shares for $1.5 billion related to our employee benefit plans and approximately 5.7 million shares for $361 million under our former stock purchase program.

On October 19, 2006, our board of directors approved a new $2 billion common stock purchase program. This new authorization is in addition to our existing authorization for employee benefit plan requirements. Stock purchases under the new $2 billion program will be made from time to time at prevailing prices as permitted by securities laws and other legal requirements, and are subject to market conditions and other factors. The program does not have a scheduled expiration date.

Contractual Obligations

As of September 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 nine months ended September 30, 2006.

In March 2006, we made a scheduled debt repayment of $220 million related to our 7.375% notes. In addition, during the nine months ended September 30, 2006, we made debt payments of $29 million related to various notes prior to their maturity dates as discussed in Note 6 of Condensed Notes to Consolidated Financial Statements.

Our agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt to below investment grade ratings by Moody’s Investors Service and Standard & Poor’s Ratings Services, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. In November 2006, Standard & Poor’s Ratings Services upgraded its rating of our senior unsecured debt to BBB with a stable outlook. 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 September 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
3-year revolving credit facility	$ 20 million	July 2009

In July 2006, Valero GP Holdings, LLC entered into a $20 million three-year revolving credit facility which matures in July 2009. Borrowings under this facility generally bear interest at LIBOR plus a margin.

As of September 30, 2006, we had $450 million of letters of credit outstanding under our U.S. uncommitted short-term bank credit facilities and $295 million of letters of credit outstanding under our 5-year revolving credit facility. Under our Canadian revolving credit facility, we had Cdn. $8 million of letters of credit outstanding as of September 30, 2006.

Sale of Investment in Valero GP Holdings, LLC

On July 19, 2006, Valero GP Holdings, LLC 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. All such units were sold by subsidiaries of Valero that held various ownership interests in Valero GP Holdings, LLC. Proceeds to the selling subsidiaries from the offering totaled approximately $355 million, net of the underwriters’ discount and other offering expenses, which resulted in a pre-tax gain to Valero of $132 million on the sale of the units. The funds received from this offering are being used for general corporate purposes. 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.

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 September 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 contributed $143 million to our qualified pension plans during the first nine months of 2006. We expect to contribute additional amounts to our qualified pension plans during 2006 with the intention of substantially fully funding our pension benefit obligation by the end of the year, which is currently expected to require approximately $200 million of additional contributions.

We are subject to extensive federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our refineries could require material additional expenditures to comply with environmental laws and regulations. For additional information regarding our environmental matters, see Note 14 of Condensed Notes to Consolidated Financial Statements.

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 September 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 September 30, 2006 and December 31, 2005, respectively, and a fair value of $7.4 billion and $7.1 billion as of September 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.


	September 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)	40,276	$	65.00			N/A		$	2,618		$	2,537		$	(81	)
Futures – short:
2006 (crude oil and refined products)	48,915		N/A		$	67.06			3,280			3,089			191

*Cash Flow Hedges:*
Swaps – long:
2006 (crude oil and refined products)	9,050		72.43			65.57			N/A			(62	)		(62	)
2007 (crude oil and refined products)	18,855		73.77			70.19			N/A			(68	)		(68	)
Swaps – short:
2006 (crude oil and refined products)	9,050		65.68			74.95			N/A			84			84
2007 (crude oil and refined products)	18,855		72.94			77.85			N/A			93			93
Futures – long:
2006 (crude oil and refined products)	3,428		63.82			N/A			219			216			(3	)
2007 (crude oil and refined products)	690		75.86			N/A			52			49			(3	)
Futures – short:
2006 (crude oil and refined products)	2,796		N/A			68.71			192			176			16
2007 (crude oil and refined products)	690		N/A			77.22			53			51			2

*Economic Hedges:*
Swaps – long:
2006 (crude oil and refined products)	8,815		6.07			4.99			N/A			(9	)		(9	)
2007 (crude oil and refined products)	1,812		(14.67	)		(13.88	)		N/A			1			1
2007 (natural gas)	320		(1.64	)		(1.36	)		N/A			—			—
Swaps – short:
2006 (crude oil and refined products)	5,192		18.51			19.52			N/A			5			5
2007 (crude oil and refined products)	150		4.51			6.51			N/A			—			—
2007 (natural gas)	470		1.60			1.72			N/A			—			—
Futures – long:
2006 (crude oil and refined products)	58,449		68.20			N/A			3,986			3,830			(156	)
2007 (crude oil and refined products)	534		91.36			N/A			48			42			(6	)
2006 (natural gas)	120		11.51			N/A			1			1			—
Futures – short:
2006 (crude oil and refined products)	59,037		N/A			68.86			4,065			3,859			206
2007 (crude oil and refined products)	537		N/A			89.89			48			42			6
2006 (natural gas)	200		N/A			11.44			2			2			—
Options – short:
2006 (crude oil and refined products)	144		N/A			91.02			(1	)		(2	)		1
2007 (crude oil and refined products)	1,478		N/A			61.94			1			(2	)		3

*Trading Activities:*
Swaps – long:
2006 (crude oil and refined products)	400		30.28			27.01			N/A			(1	)		(1	)
Swaps – short:
2006 (crude oil and refined products)	450		24.63			28.19			N/A			2			2
Futures – long:
2006 (crude oil and refined products)	9,531		71.63			N/A			683			617			(66	)
2006 (natural gas)	550		7.54			N/A			4			4			—
Futures – short:
2006 (crude oil and refined products)	8,929		N/A			69.94			624			570			54
2007 (crude oil and refined products)	600		N/A			88.29			53			47			6
2006 (natural gas)	550		N/A			7.66			4			4			—

Total pre-tax fair value of open positions														$	215


	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.


	September 30, 2006
	Expected Maturity Dates																		Total			Fair Value
	2006			2007			2008			2009			2010			Thereafter			Total			Fair Value
Long-term Debt:
Fixed rate	$	—		$	287		$	6		$	209		$	208		$	4,364		$	5,074		$	5,399
Average interest rate		—	%		6.1	%		6.0	%		3.6	%		8.9	%		7.0	%		6.9	%
Floating rate	$	—		$	—		$	—		$	1		$	—		$	—		$	1		$	1
Average interest rate		—	%		—	%		—	%		5.9	%		—	%		—	%		5.9	%

	December 31, 2005
	Expected Maturity Dates																		Total			Fair Value
	2006			2007			2008			2009			2010			Thereafter			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 September 30, 2006, we had commitments to purchase $359 million of U.S. dollars. Our market risk was immaterial on these contracts, as they matured on or before October 23, 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 September 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 reports on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006.

Litigation

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

• Rosolowski v. Clark Refining & Marketing, Inc., et al.

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.

Delaware Department of Natural Resources and Environmental Control (DNREC) (Delaware City Refinery). In October 2006, the DNREC issued a Notice of Violation (NOV) to our Delaware City Refinery. The NOV alleges that certain emissions of nickel from the refinery’s FCC unit during the first half of 2006 exceeded Maximum Available Control Technology standards. The NOV does not state a penalty amount.

New Jersey Department of Environmental Protection (NJDEP) (Paulsboro Refinery). In July 2006, the NJDEP issued two Administrative Order and Notice of Civil Administrative Penalty Assessments (Notices) to our Paulsboro Refinery. The Notices allege certain excess air emissions in the second and fourth quarters of 2005. Combined, the Notices propose an aggregate penalty of $145,000.

Item 1A. Risk Factors.

There have been no material changes from the risk factors disclosed in the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2005.

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

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

(b) Use of Proceeds. Not applicable.

(c) Issuer Purchases of Equity Securities. The following table discloses purchases of shares of 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	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (2)
July 2006	2,620,939	$	65.47	2,620,939	0	$	0
August 2006	3,909,037	$	64.56	3,909,037	0	$	0
September 2006	3,948,029	$	52.36	3,948,029	0	$	0
Total	10,478,005	$	60.19	10,478,005	0	$	0

(1)

The shares reported in this column represent purchases settled in the third 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)	On October 23, 2006, we publicly announced a $2 billion stock purchase program that was authorized by our board of directors on October 19, 2006. The program has no expiration date.

Item 6. Exhibits.


Exhibit No.		Description
*10.01		Valero Energy Corporation Restricted Stock Plan for Non-Employee Directors, as amended and restated on September 28, 2006, to be effective January 1, 2007.

*10.02		Valero Energy Corporation Non-Employee Director Stock Option Plan, as amended and restated on September 28, 2006, to be effective January 1, 2007.

*10.03		Form of Restricted Stock Agreement pursuant to the Restricted Stock Plan for Non-Employee Directors.

*10.04		Form of Stock Option Agreement pursuant to the Non-Employee Director Stock Option Plan.

*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.

S IGNATURE

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


VALERO ENERGY CORPORATION
(Registrant)

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

Date: November 9, 2006