Edgar Filing: VALERO ENERGY CORP/TX

VLO 9.30.12 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended September 30, 2012



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _______________ to _______________

Commission File Number 1-13175

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)



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

One Valero Way

San Antonio, Texas

(Address of principal executive offices)

78249

(Zip Code)

(210) 345-2000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No o

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



Large accelerated filer R	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o

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

Yes o No R

The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of October 31, 2012 was 553,540,069.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS




	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011	1
Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2012 and 2011	2
Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2012 and 2011	3
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011	4
Condensed Notes to Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 3. Quantitative and Qualitative Disclosures About Market Risk	61
Item 4. Controls and Procedures	63
PART II – OTHER INFORMATION
Item 1. Legal Proceedings	63
Item 1A. Risk Factors	64
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	65
Item 6. Exhibits	65
SIGNATURE	66

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Par Value)



	September 30, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	2,549		$	1,024
Receivables, net	7,451			8,706
Inventories	5,787			5,623
Income taxes receivable	40			212
Deferred income taxes	292			283
Prepaid expenses and other	148			124
Total current assets	16,267			15,972
Property, plant and equipment, at cost	33,454			32,253
Accumulated depreciation	(7,581		)	(7,076		)
Property, plant and equipment, net	25,873			25,177
Intangible assets, net	216			227
Deferred charges and other assets, net	1,436			1,407
Total assets	$	43,792		$	42,783
LIABILITIES AND EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	585		$	1,009
Accounts payable	9,286			9,472
Accrued expenses	612			595
Taxes other than income taxes	1,349			1,264
Income taxes payable	234			119
Deferred income taxes	185			249
Total current liabilities	12,251			12,708
Debt and capital lease obligations, less current portion	6,463			6,732
Deferred income taxes	5,758			5,017
Other long-term liabilities	1,934			1,881
Commitments and contingencies
Equity:
Valero Energy Corporation stockholders’ equity:
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 673,501,593 and 673,501,593 shares issued	7			7
Additional paid-in capital	7,409			7,486
Treasury stock, at cost; 120,035,210 and 116,689,450 common shares	(6,455		)	(6,475		)
Retained earnings	16,119			15,309
Accumulated other comprehensive income	252			96
Total Valero Energy Corporation stockholders’ equity	17,332			16,423
Noncontrolling interest	54			22
Total equity	17,386			16,445
Total liabilities and equity	$	43,792		$	42,783

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Millions of Dollars, Except Per Share Amounts)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Operating revenues (a)	$	34,726		$	33,713		$	104,555		$	91,314
Costs and expenses:
Cost of sales	31,312			30,033			95,968			82,981
Operating expenses:
Refining	930			870			2,762			2,427
Retail	178			177			514			508
Ethanol	76			103			248			302
General and administrative expenses	174			161			509			442
Depreciation and amortization expense	402			390			1,172			1,141
Asset impairment loss	345			—			956			—
Total costs and expenses	33,417			31,734			102,129			87,801
Operating income	1,309			1,979			2,426			3,513
Other income (expense), net	(2		)	1			(1		)	28
Interest and debt expense, net of capitalized interest	(70		)	(88		)	(243		)	(312		)
Income from continuing operations before income tax expense	1,237			1,892			2,182			3,229
Income tax expense	564			689			1,111			1,178
Income from continuing operations	673			1,203			1,071			2,051
Loss from discontinued operations, net of income taxes	—			—			—			(7		)
Net income	673			1,203			1,071			2,044
Less: Net loss attributable to noncontrolling interest	(1		)	—			(2		)	(1		)
Net income attributable to Valero Energy Corporation stockholders	$	674		$	1,203		$	1,073		$	2,045
Net income attributable to Valero Energy Corporation stockholders:
Continuing operations	$	674		$	1,203		$	1,073		$	2,052
Discontinued operations	—			—			—			(7		)
Total	$	674		$	1,203		$	1,073		$	2,045
Earnings per common share:
Continuing operations	$	1.22		$	2.12		$	1.94		$	3.61
Discontinued operations	—			—			—			(0.01		)
Total	$	1.22		$	2.12		$	1.94		$	3.60
Weighted-average common shares outstanding (in millions)	549			564			550			566
Earnings per common share – assuming dilution:
Continuing operations	$	1.21		$	2.11		$	1.93		$	3.59
Discontinued operations	—			—			—			(0.01		)
Total	$	1.21		$	2.11		$	1.93		$	3.58
Weighted-average common shares outstanding – assuming dilution (in millions)	556			569			556			572
Dividends per common share	$	0.175		$	0.050		$	0.475		$	0.150



Supplemental information:
(a) Includes excise taxes on sales by our U.S. retail system	$	248	$	229	$	723	$	670

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Net income	$	673		$	1,203		$	1,071		$	2,044

Other comprehensive income (loss):
Foreign currency translation adjustment	143			(278		)	175			(166		)

Pension and other postretirement benefits:
(Gain) loss reclassified into income related to:
Prior service credit	(5		)	(5		)	(15		)	(15		)
Net actuarial loss	8			3			25			10
Net gain (loss) on pension and other postretirement benefits	3			(2		)	10			(5		)

Derivative instruments designated and qualifying as cash flow hedges:
Net gain arising during the period	27			20			43			20
Net gain reclassified into income	(45		)	—			(81		)	—
Net gain (loss) on cash flow hedges	(18		)	20			(38		)	20

Other comprehensive income (loss), before income tax expense (benefit)	128			(260		)	147			(151		)
Income tax expense (benefit) related to items of other comprehensive income (loss)	(5		)	6			(9		)	5
Other comprehensive income (loss)	133			(266		)	156			(156		)

Comprehensive income	806			937			1,227			1,888
Less: Comprehensive loss attributable to noncontrolling interest	(1		)	—			(2		)	(1		)
Comprehensive income attributable to Valero Energy Corporation stockholders	$	807		$	937		$	1,229		$	1,889

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

(Unaudited)



	Nine Months Ended September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	1,071		$	2,044
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	1,172			1,141
Asset impairment loss	956			—
Noncash interest expense and other income, net	18			20
Stock-based compensation expense	29			34
Deferred income tax expense	576			393
Changes in current assets and current liabilities	1,351			840
Changes in deferred charges and credits and other operating activities, net	(66		)	(144		)
Net cash provided by operating activities	5,107			4,328
Cash flows from investing activities:
Capital expenditures	(2,129		)	(1,584		)
Deferred turnaround and catalyst costs	(339		)	(501		)
Acquisition of Pembroke Refinery, net of cash acquired	—			(1,675		)
Minor acquisitions	(77		)	(37		)
Other investing activities, net	(28		)	(24		)
Net cash used in investing activities	(2,573		)	(3,821		)
Cash flows from financing activities:
Non-bank debt:
Borrowings	300			—
Repayments	(862		)	(718		)
Bank credit agreements:
Borrowings	1,100			—
Repayments	(1,100		)	—
Accounts receivable sales program:
Proceeds from the sale of receivables	1,500			—
Repayments	(1,650		)	—
Purchase of common stock for treasury	(148		)	(270		)
Proceeds from the exercise of stock options	36			42
Common stock dividends	(263		)	(85		)
Contributions from noncontrolling interest	34			12
Other financing activities, net	8			17
Net cash used in financing activities	(1,045		)	(1,002		)
Effect of foreign exchange rate changes on cash	36			(10		)
Net increase (decrease) in cash and temporary cash investments	1,525			(505		)
Cash and temporary cash investments at beginning of period	1,024			3,334
Cash and temporary cash investments at end of period	$	2,549		$	2,829

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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 financial statements have been prepared in accordance with United States (U.S.) 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 U.S. GAAP for complete 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, 2012 and 2011 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited financial statements. Operating results for the three and nine months ended September 30, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012.

The balance sheet as of December 31, 2011 has been derived from our audited financial statements as of that date. For further information, refer to our financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2011.

Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, we review our estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

Comprehensive Income

Effective January 1, 2012, we adopted the provisions of Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” and have elected to present comprehensive income in a statement that is separate from the statement of income but placed directly after the statement of income.

Fair Value Measurements

Effective January 1, 2012, we adopted the provisions of ASC Topic 820, “Fair Value Measurement,” which clarified the application of existing fair value measurement requirements and changed certain fair value measurement and disclosure requirements. The adoption of these provisions did not affect our financial position or results of operations as these requirements only affected disclosures as reflected in Note 12.

New Accounting Pronouncements

In December 2011, the provisions of ASC Topic 210, “Balance Sheet,” were amended to require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of these arrangements on its financial position. The guidance requires entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the balance sheet and instruments and transactions subject to an agreement similar to a master netting arrangement. These provisions are effective for interim and annual reporting periods beginning on

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

January 1, 2013. The adoption of this guidance effective January 1, 2013 will not affect our financial position or results of operations, but may result in additional disclosures.


2.	ACQUISITIONS

The acquired refining and marketing businesses discussed below involve the production and marketing of refined petroleum products. These acquisitions are consistent with our general business strategy and complement our existing refining and marketing network.

Meraux Acquisition

On October 1, 2011, we acquired the Meraux Refinery and related logistics assets from Murphy Oil Corporation for an initial payment of $586 million, which was funded from available cash. In the fourth quarter of 2011, we recorded an adjustment related to inventories acquired that reduced the purchase price to $547 million. The assets acquired and liabilities assumed in this acquisition were recognized at their acquisition-date estimated fair values, as disclosed in Note 2 of Notes to Consolidated Financial Statements included in our annual report on Form 10-K for the year ended December 31, 2011, and no adjustments to those estimated amounts have been made during the nine months ended September 30, 2012.

Pembroke Acquisition

On August 1, 2011, we acquired 100 percent of the outstanding shares of Chevron Limited from a subsidiary of Chevron Corporation, and we subsequently changed the name of Chevron Limited to Valero Energy Ltd. On the acquisition date, we initially paid $1.8 billion from available cash, of which $1.1 billion was for working capital. Subsequent to the acquisition date, we recorded adjustments to working capital (primarily inventory), resulting in an adjusted purchase price of $1.7 billion. This acquisition is referred to as the Pembroke Acquisition.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In the third quarter of 2012, an independent appraisal of the assets acquired and liabilities assumed and certain other evaluations of the fair values related to the Pembroke Acquisition were completed and finalized. The purchase price of the Pembroke 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. The primary adjustments to the preliminary purchase price allocation disclosed in Note 2 of Notes to Consolidated Financial Statements included in our annual report on Form 10-K for the year ended December 31, 2011 consisted of a $143 million increase in property, plant and equipment, a $124 million increase in deferred income tax liabilities, and a $17 million increase in other long-term liabilities. The final amounts assigned to the assets acquired and liabilities assumed in the Pembroke Acquisition were recognized at their acquisition-date fair values and are as follows (in millions):



Current assets, net of cash acquired	$	2,215
Property, plant and equipment	947
Intangible assets	22
Deferred charges and other assets, net	37
Current liabilities, less current portion of debt and capital lease obligations	(1,294		)
Debt and capital leases assumed, including current portion	(12		)
Deferred income taxes	(159		)
Other long-term liabilities	(60		)
Noncontrolling interest	(5		)
Purchase price, net of cash acquired	$	1,691

Because of the adjustment to property, plant and equipment discussed above, we recorded an additional $6 million of depreciation expense in the third quarter of 2012 to true-up depreciation expense for the period from the date of the Pembroke Acquisition (August 1, 2011) through July 31, 2012.


3.	IMPAIRMENTS

Aruba Refinery

In September 2012, we decided to reorganize the Aruba Refinery into a crude oil and refined products terminal in response to the withdrawal of a non-binding offer to purchase the refinery. We had received the offer on March 28, 2012, and had accepted it, subject to the finalization of a purchase and sale agreement, but the interested party withdrew its offer on August 14, 2012.

We suspended the operations of the Aruba Refinery in March 2012 because of its inability to generate positive cash flows on a sustained basis subsequent to its restart in January 2011 and the sensitivity of its profitability to sour crude oil differentials, which had narrowed significantly in the fourth quarter of 2011. Shortly thereafter, we received the non-binding offer to purchase the refinery for $350 million, plus working capital as of the closing date. Because of our decision to suspend operations and the possibility of selling the refinery, we evaluated the refinery for potential impairment as of March 31, 2012 and concluded that it was impaired. We wrote down the refinery’s net book value (carrying value) of $945 million to its estimated fair value of $350 million, resulting in an asset impairment loss of $595 million that was recorded in March 2012. We determined that the best measure of the refinery’s fair value at that time was the $350 million offer because

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

it was based on the interested party’s specific knowledge of the refinery, experience in the refining and marketing industry, and extensive knowledge of the economic factors affecting our business. We did not, however, classify the Aruba Refinery as “held for sale” in our balance sheet because all of the accounting criteria required for that classification had not been met.

Because of our recent decision to reorganize the Aruba Refinery into a crude oil and refined products terminal, we bifurcated the idled crude oil processing units and related infrastructure (refining assets) from the terminal assets and evaluated the refining assets for potential impairment as of September 30, 2012. We concluded that the refining assets were impaired and determined that their carrying value of $308 million was not recoverable through the future operations and disposition of the refinery. We determined that these refining assets had no value after considering estimated salvage costs, resulting in an asset impairment loss of $308 million that was recorded in September 2012. We also recognized an asset impairment loss of $25 million related to materials and supplies inventories that supported the refining operations, resulting in a total asset impairment loss of $333 million that was recognized in September 2012 related to the Aruba Refinery. The terminal assets, which had a carrying value of $37 million as of September 30, 2012, were not impaired.

We currently intend to maintain the refining assets to allow them to be restarted and do not consider them to be abandoned. Therefore, we have not reflected the Aruba Refinery as a discontinued operation in our financial statements. It is possible, however, that we may abandon these assets in the future. Should we ultimately decide to abandon these assets, we may be required under our land lease agreement with the Government of Aruba to recognize an asset retirement obligation, and the amount recognized would be immediately charged to expense. We do not expect these amounts to be material to our financial position or results of operations.

The variation in the customary relationship between income tax expense and income from continuing operations before income tax expense for the three and nine months ended September 30, 2012 was primarily due to not recognizing a tax benefit associated with the asset impairment loss of $333 million and $928 million, respectively, related to the Aruba Refinery as we do not expect to realize this tax benefit.

See Note 6 for a discussion of the severance liability for employees who will be terminated in connection with the Aruba reorganization.

Other Assets

In March 2012, we wrote down the carrying value of equipment associated with a permanently cancelled capital project at one of our refineries, resulting in an asset impairment loss of $16 million that was recorded in March 2012.

We evaluated certain convenience stores operated by our retail segment for potential impairment as of September 30, 2012 and concluded that they were impaired. We wrote down the carrying values of these stores to their estimated fair values, which totaled $5 million, resulting in an asset impairment loss of $12 million that was recorded in September 2012.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


4.	INVENTORIES

Inventories consisted of the following (in millions):



	September 30, 2012		December 31, 2011
Refinery feedstocks	$	2,423	$	2,474
Refined products and blendstocks	2,904		2,633
Ethanol feedstocks and products	152		195
Convenience store merchandise	102		103
Materials and supplies	206		218
Inventories	$	5,787	$	5,623

As of September 30, 2012 and December 31, 2011, the replacement cost (market value) of last in, first out (LIFO) inventories exceeded their LIFO carrying amounts by approximately $8.7 billion and $6.8 billion, respectively.


5.	DEBT

Non-Bank Debt

During the nine months ended September 30, 2012, the following activity occurred:


•	in June 2012, we remarketed and received proceeds of $300 million related to the 4.0% Gulf Opportunity Zone Revenue Bonds Series 2010 issued by the Parish of St. Charles, State of Louisiana (GO Zone Bonds), which are due December 1, 2040, but are subject to mandatory tender on June 1, 2022;


•	in April 2012, we made scheduled debt repayments of $4 million related to our Series 1997A 5.45% industrial revenue bonds and $750 million related to our 6.875% notes; and


•	in March 2012, we exercised the call provisions on our Series 1997 5.6%, Series 1998 5.6%, Series 1999 5.7%, Series 2001 6.65%, and Series 1997A 5.45% industrial revenue bonds, which were redeemed on May 3, 2012 for $108 million, or 100 percent of their outstanding stated values.

During the nine months ended September 30, 2011, the following activity occurred:


•	in May 2011, we made a scheduled debt repayment of $200 million related to our 6.125% senior notes;


•	in April 2011, we made scheduled debt repayments of $8 million related to our Series 1997A 5.45%, Series 1997B 5.40%, and Series 1997C 5.40% industrial revenue bonds;


•	in February 2011, we made a scheduled debt repayment of $210 million related to our 6.75% senior notes; and


•	also in February 2011, we paid $300 million to acquire the GO Zone Bonds, which were subject to mandatory tender.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Bank Debt and Credit Facilities

We have a $3 billion revolving credit facility (the Revolver) that has a maturity date of December 2016. The Revolver has certain restrictive covenants, including a maximum debt-to-capitalization ratio of 60 percent. As of September 30, 2012 and December 31, 2011, our debt-to-capitalization ratios, calculated in accordance with the terms of the Revolver, were 21 percent and 29 percent, respectively. We believe that we will remain in compliance with this covenant.

In addition to the Revolver, one of our Canadian subsidiaries has a committed revolving credit facility under which it may borrow and obtain letters of credit up to C$115 million.

During the nine months ended September 30, 2012, we borrowed and repaid $1.1 billion under our Revolver. During the nine months ended September 30, 2011, we had no borrowings or repayments under our Revolver. We had no borrowings or repayments under the Canadian revolving credit facility during the nine months ended September 30, 2012 and 2011. As of September 30, 2012 and December 31, 2011, we had no borrowings outstanding under the Revolver or the Canadian revolving credit facility.

We had outstanding letters of credit under our committed lines of credit as follows (in millions):



				Amounts Outstanding
	Borrowing Capacity		Expiration	September 30, 2012		December 31, 2011
Letter of credit facilities	$	550	June 2013	$	337	$	300
Revolver	$	3,000	December 2016	$	64	$	119
Canadian revolving credit facility	C$	115	December 2012	C$	10	C$	20

As of September 30, 2012 and December 31, 2011, we had $403 million and $391 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities.

Accounts Receivable Sales Facility

We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell eligible trade receivables on a revolving basis. In July 2012, we amended our agreement to increase the facility from $1.0 billion to $1.5 billion and extended the maturity date to July 2013. Proceeds from the sale of receivables under this facility are reflected as debt. Under this program, one of our marketing subsidiaries (Valero Marketing) sells eligible receivables, without recourse, to another of our subsidiaries (Valero Capital), whereupon the receivables are no longer owned by Valero Marketing. Valero Capital, in turn, sells an undivided percentage ownership interest in the eligible receivables, without recourse, to the third-party entities and financial institutions. To the extent that Valero Capital retains an ownership interest in the receivables it has purchased from Valero Marketing, such interest is included in our financial statements solely as a result of the consolidation of the financial statements of Valero Capital with those of Valero Energy Corporation; the receivables are not available to satisfy the claims of the creditors of Valero Marketing or Valero Energy Corporation.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Changes in the amounts outstanding under our accounts receivable sales facility were as follows (in millions):



	Nine Months Ended September 30,
	2012			2011
Balance as of beginning of period	$	250		$	100
Proceeds from the sale of receivables	1,500			—
Repayments	(1,650		)	—
Balance as of end of period	$	100		$	100

Capitalized Interest

Capitalized interest was $59 million and $42 million for the three months ended September 30, 2012 and 2011, respectively, and $164 million and $102 million for the nine months ended September 30, 2012 and 2011, respectively.


6.	COMMITMENTS AND CONTINGENCIES

One-Time Severance Benefits

As described in Note 3, we decided to reorganize the Aruba Refinery into a crude oil and refined products terminal in September 2012 resulting in a decrease in required personnel for our operations in Aruba. We notified 495 employees in September 2012 of the termination of their employment effective November 15, 2012. Each terminated employee will receive benefits consisting primarily of a cash payment based on a formula that considers the employee’s current compensation and years of service, among other factors. We expect to pay these benefits in November 2012. We recognized a severance liability of $41 million in September 2012, which approximates fair value, and the entire amount was outstanding as of September 30, 2012. Because of the short discount period, the recorded liability of $41 million is not materially different from its fair value. The severance expense of $41 million is included in refining operating expenses for the three and nine months ended September 30, 2012 and relates to our refining segment.

Environmental Matters

The U.S. Environmental Protection Agency (EPA) began regulating greenhouse gases on January 2, 2011, under the Clean Air Act Amendments of 1990 (Clean Air Act). Any new construction or material expansions will require that, among other things, a greenhouse gas permit be issued at either or both the state or federal level in accordance with the Clean Air Act and regulations, and we will be required to undertake a technology review to determine appropriate controls to be implemented with the project in order to reduce greenhouse gas emissions. The determination would be on a case by case basis, and the EPA has provided only general guidance on which controls will be required.

Furthermore, the EPA is currently developing refinery-specific greenhouse gas regulations and performance standards that are expected to impose, on new and existing operations, greenhouse gas emission limits and/or technology requirements. These control requirements may affect a wide range of refinery operations but have not yet been delineated. Any such controls, however, could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

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Certain states and foreign governments have pursued regulation of greenhouse gases independent of the EPA. For example, the California Global Warming Solutions Act, also known as AB 32, directs the California Air Resources Board (CARB) to develop and issue regulations to reduce greenhouse gas emissions in California to 1990 levels by 2020. The CARB has issued a variety of regulations aimed at reaching this goal, including a Low Carbon Fuel Standard (LCFS) as well as a statewide cap-and-trade program.

•

The LCFS was scheduled to become effective in 2011, but rulings by the U.S. District Court stayed enforcement of the LCFS until certain legal challenges to the LCFS were resolved. Most notably, the court determined that the LCFS violates the Commerce Clause of the U.S. Constitution to the extent that the standard discriminates against out-of-state crude oils and corn ethanol. CARB appealed the lower court’s ruling to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit Court), which lifted the stay on April 23, 2012. The Ninth Circuit Court heard arguments on the merits of the appeal in October 2012. We await the court’s final ruling on the merits.

•

A California statewide cap-and-trade program will begin in late 2012. Initially, the program will apply only to stationary sources of greenhouse gases (e.g., refinery and power plant greenhouse gas emissions). Greenhouse gas emissions from fuels that we sell in California will be covered by the program beginning in 2015. We anticipate that free allocations of credits will be available in the early years of the program to cover most of our stationary emissions, but we expect that compliance costs will increase significantly beginning in 2015, when transportation fuels are included in the program.

•

Complying with AB 32, including the LCFS and the cap-and-trade program, could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce. To the degree we are unable to recover these increased costs, these matters could have a material adverse effect on our financial position, results of operations, and liquidity.

In the first quarter of 2012, CARB adopted amendments to its Clean Fuels Outlet (CFO) Regulation. CARB states that the CFO Regulation is intended to provide outlets of clean fuel to meet the needs of alternative fuel vehicles. We understand that CARB is preparing to submit the CFO Regulation to the State Office of Administrative Law for approval. Under the regulation, projections of zero-emission vehicle availability in the California market would trigger a requirement for major refiners and importers of gasoline, including us, to install clean fuel outlets in designated areas in proportion to each refiner or importer’s share in the California gasoline market. We expect this regulation to be challenged, but we could be required to make significant capital expenditures if the regulation is implemented as presently adopted.

The EPA has disapproved certain permitting programs of the Texas Commission on Environmental Quality (TCEQ) that historically have streamlined the environmental permitting process or provided greater operational flexibility in Texas. For example, the EPA disapproved the TCEQ flexible permit program and pollution control standard permit, thus requiring the conversion of flexible permits to a more conventional permitting program and precluding the prompt authorization of pollution control equipment. The Fifth Circuit Court of Appeals overturned the EPA’s disapproval of the flexible permit program and pollution control standard permit and sent them back to the EPA for reconsideration consistent with the court’s decision. In other instances, the EPA’s decisions have been initially upheld and others are still pending before the courts. Regardless of the EPA’s response to the courts’ various rulings, further litigation is probable. The EPA has also objected to numerous Title V permits in Texas and other states, including permits at our Port Arthur,

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Texas City, Meraux, Corpus Christi East, and McKee Refineries. Environmental activist groups have filed notices of intent to sue the EPA, seeking to require the EPA to assume control of these permits from the TCEQ. Finally, as part of its regulation of greenhouse gases discussed above, the EPA has federalized the permitting of greenhouse gas emissions in Texas. This creates a dual permitting structure that must be navigated for material projects in Texas. All of these developments have created substantial uncertainty regarding existing and future permitting. Because of this uncertainty, we are unable to determine the costs or effects of the EPA’s actions on our permitting activity. The greenhouse gas permitting regime and the EPA’s disruption of the Texas permitting system could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

Tax Matters

We are subject to extensive tax liabilities imposed by multiple jurisdictions, including income taxes, indirect taxes (excise/duty, sales/use, gross receipts, and value-added taxes), payroll taxes, franchise taxes, withholding taxes, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Many of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties.

As of September 30, 2012, the Internal Revenue Service (IRS) has ongoing tax audits related to our U.S. federal tax returns from 2002 through 2009. We have received Revenue Agent Reports on our tax years for 2002 through 2007 and we are vigorously contesting certain tax positions and assertions from the IRS. Although we believe our tax liabilities are fairly stated and properly reflected in our financial statements, should the IRS eventually prevail, it could result in a material amount of our deferred tax liabilities being reclassified to current liabilities which could have a material adverse effect on our liquidity.

Litigation Matters

We are party to claims and legal proceedings arising in the ordinary course of business. We have not recorded a loss contingency liability with respect to some of these matters because we have determined that it is remote that a loss has been incurred. For other matters, we have recorded a loss contingency liability where we have determined that it is probable that a loss has been incurred and that the loss is reasonably estimable. These loss contingency liabilities are not material to our financial position. We re-evaluate and update our loss contingency liabilities as matters progress over time, and we believe that any changes to the recorded liabilities will not be material to our financial position or results of operations.

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7.	EQUITY

The following is a reconciliation of the beginning and ending balances (in millions) of equity attributable to our stockholders, equity attributable to the noncontrolling interest, and total equity for the nine months ended September 30, 2012 and 2011:



	2012									2011
	Valero Stockholders’ Equity			Non- controlling Interest			Total Equity			Valero Stockholders’ Equity			Non- controlling Interest			Total Equity
Balance as of beginning of period	$	16,423		$	22		$	16,445		$	15,025		$	—		$	15,025
Net income (loss)	1,073			(2		)	1,071			2,045			(1		)	2,044
Dividends	(263		)	—			(263		)	(85		)	—			(85		)
Stock-based compensation expense	29			—			29			34			—			34
Tax deduction in excess of stock-based compensation expense	16			—			16			19			—			19
Transactions in connection with stock-based compensation plans:
Stock issuances	36			—			36			42			—			42
Stock repurchases	(138		)	—			(138		)	(270		)	—			(270		)
Contributions from noncontrolling interest	—			34			34			—			14			14
Recognition of noncontrolling interest in connection with Pembroke Acquisition	—			—			—			—			3			3
Other comprehensive income (loss)	156			—			156			(156		)	—			(156		)
Balance as of end of period	$	17,332		$	54		$	17,386		$	16,654		$	16		$	16,670

The noncontrolling interests relate to third-party ownership interests in Diamond Green Diesel Holdings LLC and Mainline Pipelines Limited (MLP), companies whose financial statements we consolidate due to our controlling interests. In the fourth quarter of 2011, we acquired the noncontrolling interest in MLP.

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Share Activity

Activity in the number of shares of common stock and treasury stock was as follows (in millions) for the nine months ended September 30, 2012 and 2011:



	2012			2011
	Common Stock	Treasury Stock		Common Stock	Treasury Stock
Balance as of beginning of period	673	(117	)	673	(105	)
Transactions in connection with stock-based compensation plans:
Stock issuances	—	3		—	4
Stock purchases	—	(6	)	—	(14	)
Balance as of end of period	673	(120	)	673	(115	)


8.	EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost related to our defined benefit plans were as follows (in millions) for the three and nine months ended September 30, 2012 and 2011:



	Pension Plans						Other Postretirement Benefit Plans
	2012			2011			2012			2011
Three months ended September 30:
Service cost	$	35		$	28		$	3		$	4
Interest cost	23			21			5			5
Expected return on plan assets	(31		)	(28		)	—			—
Amortization of:
Prior service cost (credit)	1			1			(6		)	(6		)
Net actuarial loss	8			3			—			—
Net periodic benefit cost	$	36		$	25		$	2		$	3

Nine months ended September 30:
Service cost	$	105		$	73		$	9		$	9
Interest cost	69			64			16			16
Expected return on plan assets	(93		)	(84		)	—			—
Amortization of:
Prior service cost (credit)	2			2			(17		)	(17		)
Net actuarial loss	25			9			—			1
Net periodic benefit cost	$	108		$	64		$	8		$	9

During the nine months ended September 30, 2012 and 2011, we contributed $132 million and $207 million, respectively, to our pension plans.

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9.	EARNINGS PER COMMON SHARE

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



	Three Months Ended September 30,
	2012				2011
	Restricted Stock		Common Stock		Restricted Stock		Common Stock
Earnings per common share from continuing operations:
Net income attributable to Valero stockholders from continuing operations			$	674			$	1,203
Less dividends paid:
Common stock			96				28
Nonvested restricted stock			1				—
Undistributed earnings			$	577			$	1,175
Weighted-average common shares outstanding	3		549		3		564
Earnings per common share from continuing operations:
Distributed earnings	$	0.18	$	0.18	$	0.05	$	0.05
Undistributed earnings	1.04		1.04		2.07		2.07
Total earnings per common share from continuing operations	$	1.22	$	1.22	$	2.12	$	2.12

Earnings per common share from continuing operations – assuming dilution:
Net income attributable to Valero stockholders from continuing operations			$	674			$	1,203
Weighted-average common shares outstanding			549				564
Common equivalent shares:
Stock options			4				3
Performance awards and nonvested restricted stock			3				2
Weighted-average common shares outstanding – assuming dilution			556				569
Earnings per common share from continuing operations – assuming dilution			$	1.21			$	2.11

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	Nine Months Ended September 30,
	2012				2011
	Restricted Stock		Common Stock		Restricted Stock		Common Stock
Earnings per common share from continuing operations:
Net income attributable to Valero stockholders from continuing operations			$	1,073			$	2,052
Less dividends paid:
Common stock			261				85
Nonvested restricted stock			2				—
Undistributed earnings			$	810			$	1,967

Weighted-average common shares outstanding	3		550		3		566

Earnings per common share from continuing operations:
Distributed earnings	$	0.48	$	0.48	$	0.15	$	0.15
Undistributed earnings	1.46		1.46		3.46		3.46
Total earnings per common share from continuing operations	$	1.94	$	1.94	$	3.61	$	3.61

Earnings per common share from continuing operations – assuming dilution:
Net income attributable to Valero stockholders from continuing operations			$	1,073			$	2,052
Weighted-average common shares outstanding			550				566
Common equivalent shares:
Stock options			4				4
Performance awards and nonvested restricted stock			2				2
Weighted-average common shares outstanding – assuming dilution			556				572
Earnings per common share from continuing operations – assuming dilution			$	1.93			$	3.59

The following table reflects potentially dilutive securities (in millions) that were excluded from the calculation of “earnings per common share from continuing operations – assuming dilution” as the effect of including such securities would have been antidilutive. These potentially dilutive securities included stock options for which the exercise prices were greater than the average market price of our common shares during each respective reporting period.



	Three Months Ended September 30,		Nine Months Ended September 30,
	2012	2011	2012	2011
Stock options	5	6	6	6

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10.	SEGMENT INFORMATION

The following table reflects activity related to continuing operations (in millions):



	Refining		Retail		Ethanol			Corporate			Total
Three months ended September 30, 2012:
Operating revenues from external customers	$	30,543	$	3,092	$	1,091		$	—		$	34,726
Intersegment revenues	2,348		—		15			—			2,363
Operating income (loss)	1,528		41		(73		)	(187		)	1,309

Three months ended September 30, 2011:
Operating revenues from external customers	29,177		3,053		1,483			—			33,713
Intersegment revenues	2,258		—		25			—			2,283
Operating income (loss)	1,947		97		107			(172		)	1,979

Nine Months Ended September 30, 2012:
Operating revenues from external customers	92,181		9,089		3,285			—			104,555
Intersegment revenues	6,806		—		75			—			6,881
Operating income (loss)	2,773		253		(59		)	(541		)	2,426

Nine Months Ended September 30, 2011:
Operating revenues from external customers	78,660		8,865		3,789			—			91,314
Intersegment revenues	6,566		—		125			—			6,691
Operating income (loss)	3,476		298		215			(476		)	3,513

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



	September 30, 2012		December 31, 2011
Refining	$	38,198	$	38,164
Retail	2,098		1,999
Ethanol	900		943
Corporate	2,596		1,677
Total assets	$	43,792	$	42,783

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Possible Divestiture of Retail Business

In July 2012, we announced our intention to pursue a plan to separate our retail business from Valero. We are currently reviewing several potential separation transactions, including a tax-efficient distribution of the retail business to our shareholders.


11.	SUPPLEMENTAL CASH FLOW INFORMATION

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



	Nine Months Ended September 30,
	2012			2011
Decrease (increase) in current assets:
Receivables, net	$	1,293		$	(1,963	)
Inventories	(116		)	891
Income taxes receivable	172			333
Prepaid expenses and other	(25		)	12
Increase (decrease) in current liabilities:
Accounts payable	(150		)	1,191
Accrued expenses	10			137
Taxes other than income taxes	55			99
Income taxes payable	112			140
Changes in current assets and current liabilities	$	1,351		$	840

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


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


•	the amounts shown above exclude the current assets and current liabilities acquired in connection with the Pembroke Acquisition in August 2011;


•	amounts accrued for capital expenditures and deferred turnaround and catalyst costs are reflected in investing activities when such amounts are paid;


•	amounts accrued for common stock purchases in the open market that are not settled as of the balance sheet date are reflected in financing activities when the purchases are settled and paid; and


•	certain differences between balance sheet changes and the changes reflected above result from translating foreign currency denominated balances at the applicable exchange rates as of each balance sheet date.

There were no significant noncash investing or financing activities for the nine months ended September 30, 2012 and 2011.

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



	Nine Months Ended September 30,
	2012		2011
Interest paid in excess of amount capitalized	$	206	$	276
Income taxes paid, net	238		289


12.	FAIR VALUE MEASUREMENTS

General

GAAP requires that certain financial instruments, such as derivative instruments, be recognized at their fair values in our balance sheets. However, other financial instruments, such as debt obligations, are not required to be recognized at their fair values, but GAAP provides an option to elect fair value accounting for these instruments. GAAP requires the disclosure of the fair values of all financial instruments, regardless of whether they are recognized at their fair values or carrying amounts in our balance sheets. For financial instruments recognized at fair value, GAAP requires the disclosure of their fair values by type of instrument, along with other information, including changes in the fair values of certain financial instruments recognized in income or other comprehensive income, and this information is provided below under “Recurring Fair Value Measurements.” For financial instruments not recognized at fair value, the disclosure of their fair values is provided below under “Other Financial Instruments.”

Nonfinancial assets, such as property, plant and equipment, and nonfinancial liabilities are recognized at their carrying amounts in our balance sheets. GAAP does not permit nonfinancial assets and liabilities to be remeasured at their fair values. However, GAAP requires the remeasurement of such assets and liabilities to their fair values upon the occurrence of certain events, such as the impairment of property, plant and equipment. In addition, if such an event occurs, GAAP requires the disclosure of the fair value of the asset or liability along with other information, including the gain or loss recognized in income in the period the remeasurement occurred. This information is provided below under “Nonrecurring Fair Value Measurements.”

GAAP provides a framework for measuring fair value and establishes a three-level fair value hierarchy that prioritizes inputs to valuation techniques based on the degree to which objective prices in external active markets are available to measure fair value. Following is a description of each of the levels of the fair value hierarchy.


•	Level 1 - Observable inputs, such as unadjusted quoted prices in active markets for identical assets or liabilities.


•	Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.


•	Level 3 - Unobservable inputs for the asset or liability for which there is little, if any, market activity at the measurement date. Unobservable inputs reflect our own assumptions about what market participants would use to price the asset or liability. The inputs are developed based on the best information available in the circumstances, which might include occasional market quotes or sales

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of similar instruments or our own financial data such as internally developed pricing models, discounted cash flow methodologies, as well as instruments for which the fair value determination requires significant judgment.

The financial instruments and nonfinancial assets and liabilities included in our disclosure of recurring and nonrecurring fair value measurements are categorized according to the fair value hierarchy based on the inputs used to measure their fair values.

Recurring Fair Value Measurements

The tables below present information (in millions) about our financial instruments recognized at their fair values in our balance sheets categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of September 30, 2012 and December 31, 2011.

Cash collateral deposits of $213 million and $136 million with brokers under master netting arrangements are included in the fair value of the commodity derivatives reflected in Level 1 as of September 30, 2012 and December 31, 2011, respectively. Certain of our commodity derivative contracts under master netting arrangements include both asset and liability positions. We have elected to offset the fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty, including any related cash collateral asset or obligation under the column “Netting Adjustments” below; however, fair value amounts by hierarchy level are presented on a gross basis in the tables below.



	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments			Total Fair Value as of September 30, 2012
Assets:
Commodity derivative contracts	$	3,351	$	105	$	—	$	(3,292	)	$	164
Physical purchase contracts	—		3		—		—			3
Investments of certain benefit plans	88		—		11		—			99
Foreign currency contracts	3		—		—		—			3
Other investments	—		—		—		—			—
Liabilities:
Commodity derivative contracts	3,191		117		—		(3,292		)	16
Biofuels blending obligation	6		—		—		—			6
Foreign currency contracts	1		—		—		—			1

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	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Netting Adjustments			Total Fair Value as of December 31, 2011
Assets:
Commodity derivative contracts	$	2,038	$	78		$	—	$	(1,940	)	$	176
Physical purchase contracts	—		(2		)	—		—			(2		)
Investments of certain benefit plans	84		—			11		—			95
Other investments	—		—			—		—			—
Liabilities:
Commodity derivative contracts	1,864		101			—		(1,940		)	25
Foreign currency contracts	3		—			—		—			3

A description of our financial instruments and the valuation methods used to measure those instruments at fair value are as follows:

•

Commodity derivative contracts consist primarily of exchange-traded futures and swaps, and as disclosed in Note 13, some of these contracts are designated as hedging instruments. These contracts are measured at fair value using the market approach. Exchange-traded futures are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy. Swaps are priced using third-party broker quotes, industry pricing services, and exchange-traded curves, with appropriate consideration of counterparty credit risk, but because they have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, these financial instruments are categorized in Level 2 of the fair value hierarchy.

•

Physical purchase contracts to purchase inventories represent the fair value of firm commitments to purchase crude oil feedstocks and the fair value of fixed-price corn purchase contracts, and as disclosed in Note 13, some of these contracts are designated as hedging instruments. The fair values of these firm commitments and purchase contracts are measured using a market approach based on quoted prices from the commodity exchange, but because these commitments have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, they are categorized in Level 2 of the fair value hierarchy.

•

Investments of certain benefit plans consist of investment securities held by trusts for the purpose of satisfying a portion of our obligations under certain U.S. nonqualified benefit plans. The assets categorized in Level 1 of the fair value hierarchy are measured at fair value using a market approach based on quoted prices from national securities exchanges. The assets categorized in Level 3 of the fair value hierarchy represent insurance contracts, the fair value of which is provided by the insurer.

•

Foreign currency contracts consist of foreign currency exchange and purchase contracts entered into by our international operations to manage our exposure to exchange rate fluctuations on transactions denominated in currencies other than the local (functional) currencies of those operations. These contracts are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy.


•	Other investments consist of (i) equity securities of private companies over which we do not exercise significant influence nor whose financial statements are consolidated into our financial statements

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and (ii) debt securities of a private company whose financial statements are not consolidated into our financial statements. We have elected to account for these investments at their fair values. These investments are categorized in Level 3 of the fair value hierarchy as the fair values of these investments are determined using the income approach based on internally developed analyses.

•

Our biofuels blending obligation represents a liability for the purchase of RINs and RTFCs, as defined and described in Note 13 under “Compliance Program Price Risk,” to satisfy our obligation to blend biofuels into the products we produce. Our obligation is based on our deficiency in RINs and RTFCs and the price of these instruments as of the balance sheet date. Our obligation is categorized in Level 1 of the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.

During the nine months ended September 30, 2012 and 2011, there were no transfers between assets classified as Level 1 and Level 2.

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The following is a reconciliation of the beginning and ending balances (in millions) for fair value measurements developed using significant unobservable inputs (Level 3) for the three and nine months ended September 30, 2012 and 2011.



	2012				2011
	Investments of Certain Benefit Plans		Other Investments		Investments of Certain Benefit Plans		Other Investments
Three months ended September 30:
Balance as of beginning of period	$	11	$	—	$	11	$	—
Purchases	—		—		—		5
Total gains (losses):
Included in refining operating expenses	—		—		—		(5		)
Transfers in and/or out of Level 3	—		—		—		—
Balance as of end of period	$	11	$	—	$	11	$	—
The amount of total gains (losses) included in income attributable to the change in unrealized gains (losses) relating to assets still held at end of period	$	—	$	—	$	—	$	(5	)

Nine months ended September 30:
Balance as of beginning of period	$	11	$	—	$	10	$	—
Purchases	—		—		—		21
Total gains (losses):
Included in refining operating expenses	—		—		1		(21		)
Transfers in and/or out of Level 3	—		—		—		—
Balance as of end of period	$	11	$	—	$	11	$	—
The amount of total gains (losses) included in income attributable to the change in unrealized gains (losses) relating to assets still held at end of period	$	—	$	—	$	1	$	(21	)

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Nonrecurring Fair Value Measurements

The table below presents the fair value (in millions) of our nonfinancial assets measured on a nonrecurring basis during the nine months ended September 30, 2012 and categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of September 30, 2012.



	Fair Value Measurements Using								Total Loss Recognized During the Nine Months Ended September 30, 2012
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value as of September 30, 2012
Assets:
Long-lived assets of the Aruba Refinery	$	—	$	—	$	—	$	—	$	903
Materials and supplies inventories of the Aruba Refinery	—		—		—		—		25
Cancelled capital project	—		—		2		2		16
Property, plant and equipment of convenience stores	—		—		5		5		12

There were no liabilities that were measured at fair value on a nonrecurring basis during the nine months ended September 30, 2012. There were no assets or liabilities that were measured at fair value on a nonrecurring basis during the nine months ended September 30, 2011.

Aruba Refinery

As discussed in Note 3, we concluded that the Aruba Refinery was impaired as of March 31, 2012. As a result, we were required to determine the fair value of the Aruba Refinery and to write down its carrying value to that amount. We determined that the best measure of the refinery’s fair value as of March 31, 2012 was the $350 million offer received and accepted, subject to the finalization of the purchase and sale agreement. The fair value of the Aruba Refinery was measured using the market approach and was categorized in Level 3 within the fair value hierarchy. The carrying value of the Aruba Refinery’s long-lived assets as of March 31, 2012 was $945 million; therefore, we recognized an asset impairment loss of $595 million in March 2012.

As further discussed in Note 3, in September 2012, we decided to reorganize the Aruba Refinery into a crude oil and refined products terminal in response to the August 2012 withdrawal of a non-binding offer to purchase the refinery. Because of our decision to reorganize the Aruba Refinery into a crude oil and refined products terminal, we evaluated the refining assets for potential impairment as of September 30, 2012. We concluded that these refining assets were impaired and determined that their carrying value of $308 million was not recoverable through the future operations and disposition of the refinery. We determined that these refining assets had no value after considering estimated salvage costs, resulting in an asset impairment loss of $308 million that was recorded in September 2012. We also recognized an asset impairment loss of $25 million related to materials and supplies inventories that supported the refining operations, resulting in a total asset impairment loss of $333 million in September 2012.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Other Assets

We recognized an asset impairment loss of $16 million in March 2012 related to equipment associated with a capital project that was cancelled permanently in 2009. We had written down the carrying value of this equipment to fair value in 2009, but we had been unable to sell the equipment. As a result, we wrote down the carrying amount of the equipment to scrap value.

Other Financial Instruments

Financial instruments that we recognize in our balance sheets at their carrying amounts are shown in the table below (in millions):



	September 30, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash and temporary cash investments	$	2,549	$	2,549	$	1,024	$	1,024
Financial liabilities:
Debt (excluding capital leases)	6,997		8,576		7,690		9,298

The methods and significant assumptions used to estimate the fair value of these financial instruments are as follows:


•	The fair value of cash and temporary cash investments approximates the carrying value due to the low level of credit risk of these assets combined with their short maturities and market interest rates (Level 1).


•	The fair value of debt is determined primarily using the market approach based on quoted prices provided by third-party brokers and vendor pricing services, but are not exchange-traded (Level 2).

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


13.	PRICE RISK MANAGEMENT ACTIVITIES

We are exposed to market risks related to the volatility in the price of commodities, the price of financial instruments associated with governmental and regulatory compliance programs, interest rates, and foreign currency exchange rates, and we enter into derivative instruments to manage some of these risks. We also enter into derivative instruments to manage the price risk on other contractual derivatives into which we have entered. The only types of derivative instruments we enter into are those related to the various commodities we purchase or produce, financial instruments we must purchase to maintain compliance with various governmental and regulatory programs, interest rate swaps, and foreign currency exchange and purchase contracts, as described below. All derivative instruments are recorded as either assets or liabilities measured at their fair values (see Note 12).

When we enter into a derivative instrument, it is designated as a fair value hedge, a cash flow hedge, an economic hedge, or a trading derivative. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting loss or gain on the hedged item attributable to the hedged risk, is recognized currently in income in the same period. The effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is initially reported as a component of other comprehensive income and is then recorded in income in the period or periods during which the hedged forecasted transaction affects income. The ineffective portion of the gain or loss on the cash flow derivative instrument, if any, is recognized in income as incurred. For our economic hedges (derivative instruments not designated as fair value or cash flow hedges) and for derivative instruments entered into by us for trading purposes, the derivative instrument is recorded at fair value and changes in the fair value of the derivative instrument are recognized currently in income. The cash flow effects of all of our derivative instruments are reflected in operating activities in our statements of cash flows for all periods presented.

Commodity Price Risk

We are exposed to market risks related to the volatility in the price of crude oil, refined products (primarily gasoline and distillate), grain (primarily corn), and natural gas used in our operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, including futures, swaps, and options. We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations. We use swaps primarily to manage our price exposure. Our positions in commodity derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.

For risk management purposes, we use fair value hedges, cash flow hedges, and economic hedges. In addition to the use of derivative instruments to manage commodity price risk, we also enter into certain commodity derivative instruments for trading purposes. Our objective for entering into each type of hedge or trading derivative is described below.

Fair Value Hedges

Fair value hedges are used to hedge price volatility in certain refining inventories and firm commitments to purchase inventories. The level of activity for our fair value hedges is based on the level of our operating inventories, and generally represents the amount by which our inventories differ from our previous year-end LIFO inventory levels.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of September 30, 2012, we had the following outstanding commodity derivative instruments that were entered into to hedge crude oil and refined product inventories and commodity derivative instruments related to the physical purchase of crude oil and refined products at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).



		Notional Contract Volumes by Year of Maturity
Derivative Instrument		2012
Crude oil and refined products:
Futures – long		776
Futures – short		4,691
Physical contracts - long		3,915

Cash Flow Hedges

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

As of September 30, 2012, we had the following outstanding commodity derivative instruments that were entered into to hedge forecasted purchases or sales of crude oil and refined products. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).



		Notional Contract Volumes by Year of Maturity
Derivative Instrument		2012
Crude oil and refined products:
Swaps – long		6,441
Swaps – short		6,441
Futures – long		15,422
Futures – short		5,749
Physical contracts – short		9,673

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Economic Hedges

Economic hedges represent commodity derivative instruments that are not designated as fair value or cash flow hedges and are used to manage price volatility in certain (i) refinery feedstock, refined product, and corn inventories, (ii) forecasted refinery feedstock, refined product, and corn purchases, and refined product sales, and (iii) fixed-price corn purchase contracts. Our objective for entering into economic hedges is consistent with the objectives discussed above for fair value hedges and cash flow hedges. However, the economic hedges are not designated as a fair value hedge or a cash flow hedge for accounting purposes, usually due to the difficulty of establishing the required documentation at the date that the derivative instrument is entered into that would allow us to achieve “hedge deferral accounting.”

As of September 30, 2012, we had the following outstanding commodity derivative instruments that were used as economic hedges and commodity derivative instruments related to the physical purchase of corn at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as corn contracts that are presented in thousands of bushels).



	Notional Contract Volumes by Year of Maturity
Derivative Instrument	2012	2013	2014
Crude oil and refined products:
Swaps – long	15,017	55	—
Swaps – short	12,364	—	—
Futures – long	56,978	502	—
Futures – short	77,908	—	—
Options – long	6	10	—
Corn:
Futures – long	13,395	385	5
Futures – short	25,440	7,245	20
Physical contracts – long	11,778	7,073	15

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Trading Derivatives

Our objective in entering into commodity derivative instruments for trading purposes is to take advantage of existing market conditions related to future results of operations and cash flows.

As of September 30, 2012, we had the following outstanding commodity derivative instruments that were entered into for trading purposes. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes represent thousands of barrels, except those identified as natural gas contracts that are presented in billions of British thermal units and corn contracts that are presented in thousands of bushels).



	Notional Contract Volumes by Year of Maturity
Derivative Instrument	2012	2013
Crude oil and refined products:
Swaps – long	19,180	46,540
Swaps – short	18,599	46,601
Futures – long	122,349	34,764
Futures – short	122,928	33,958
Options – long	12,115	500
Options – short	11,260	500
Natural gas:
Futures – long	8,550	200
Futures – short	8,550	200
Corn:
Swaps - long	9,705	1,830
Swaps - short	11,520	5,045
Futures – long	14,030	4,250
Futures – short	14,030	4,250

Compliance Program Price Risk

Obligation to Blend Biofuels

We are obligated to blend biofuels into the products we produce in most of the countries in which we operate, and these countries set annual quotas for the percentage of biofuels that must be blended into the motor fuels consumed in these countries. As a producer of motor fuels from petroleum, we are obligated to blend biofuels into the products we produce at a rate that is at least equal to the applicable quota. To the degree we are unable to blend at the applicable rate in the U.S. and the United Kingdom (U.K.), we must purchase Renewable Identification Numbers (RINs) in the U.S. and Renewable Transport Fuel Obligation certificates (RTFCs) in the U.K., and as such, we are exposed to the volatility in the market price of these financial instruments.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We have not entered into derivative instruments to manage this risk, but we purchase RINs and RTFCs when the price of these instruments is deemed favorable. The cost of meeting our obligations under this compliance program was $72 million and $86 million for the three months ended September 30, 2012 and 2011, respectively, and $198 million and $181 million for the nine months ended September 30, 2012 and 2011. These amounts are reflected in cost of sales.

Maintaining Minimum Inventory Quantities

In the U.K., we are required to maintain a minimum quantity of crude oil and refined products as a reserve against shortages or interruptions in the supply of these products. To the degree we decide not to physically hold the minimum quantity of crude oil and refined products, we must purchase Compulsory Stock Obligation (CSO) tickets from other suppliers of refined products in the U.K. or other European Union (EU) member countries, and we make economic decisions as to the cost of maintaining certain quantities of crude oil and refined products versus the cost of purchasing CSO tickets. We have not entered into derivative instruments to manage the price volatility of CSO tickets. The cost of purchasing CSO tickets to help meet our obligations under this compliance program was $3 million and $1 million for the three months ended September 30, 2012 and 2011, respectively, and $6 million and $1 million for the nine months ended September 30, 2012 and 2011. These amounts are reflected in cost of sales. We had no obligations under this compliance program prior to completing the Pembroke Acquisition in 2011.

Emission Allowances

Our Pembroke Refinery is subject to a maximum amount of carbon dioxide that it can emit each year under the EU Emissions Trading Scheme. Under this cap-and-trade program, we purchase emission allowances on the open market for the difference between the amount of carbon dioxide emitted and the maximum amount allowed under the program. Therefore, we are exposed to the volatility in the market price of these allowances. For the three months ended September 30, 2012, no costs were incurred to meet our obligation under this compliance program. For the nine months ended September 30, 2012, the cost of meeting our obligation under this compliance program was $1 million, which is reflected in refining operating expenses. We had no obligations under this compliance program prior to completing the Pembroke Acquisition in 2011.

We enter into derivative instruments (futures) to reduce the impact of this risk on our results of operations and cash flows. Our positions in these derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors. As of September 30, 2012, we had purchased futures contracts – long for 55,000 metric tons of EU emission allowances that were entered into as economic hedges. As of September 30, 2012, the fair value of these futures contracts was immaterial and therefore not separately presented in the table below under “Fair Values of Derivative Instruments.” For the three and nine months ended September 30, 2012, the gain (loss) recognized in income on these derivative instruments designated as economic hedges were also immaterial and therefore not separately presented in the table below under “Effect of Derivative Instruments on Income and Other Comprehensive Income.”

Interest Rate Risk

Our primary market risk exposure for changes in interest rates relates to our debt obligations. We manage our exposure to changing interest rates through the use of a combination of fixed-rate and floating-rate debt. In addition, at times we have used interest rate swap agreements to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt. We had no interest rate derivative

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

instruments outstanding as of September 30, 2012 or December 31, 2011, or during the three and nine months ended September 30, 2012 and 2011.

Foreign Currency Risk

We are exposed to exchange rate fluctuations on transactions entered into by our international operations that are denominated in currencies other than the local (functional) currencies of those operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of September 30, 2012, we had commitments to purchase $579 million of U.S. dollars. These commitments matured on or before October 24, 2012, resulting in a loss of less than $1 million in the fourth quarter of 2012.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Fair Values of Derivative Instruments

The following tables provide information about the fair values of our derivative instruments as of September 30, 2012 and December 31, 2011 (in millions) and the line items in the balance sheets in which the fair values are reflected. See Note 12 for additional information related to the fair values of our derivative instruments.

As indicated in Note 12, we net fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty under master netting arrangements. The tables below, however, are presented on a gross asset and gross liability basis, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts. In addition, in Note 12, we included cash collateral on deposit with or received from brokers in the fair value of the commodity derivatives; these cash amounts are not reflected in the tables below.



	Balance Sheet Location	September 30, 2012
	Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	67	$	40
Swaps	Receivables, net	44		38
Swaps	Accrued expenses	—		2
Total		$	111	$	80

Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	3,071	$	3,150
Swaps	Receivables, net	6		11
Swaps	Prepaid expenses and other	2		1
Swaps	Accrued expenses	48		62
Options	Receivables, net	4		3
Options	Accrued expenses	1		1
Physical purchase contracts	Inventories	3		—
Foreign currency contracts	Receivables, net	3		—
Foreign currency contracts	Accrued expenses	—		1
Total		$	3,138	$	3,229
Total derivatives		$	3,249	$	3,309

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Balance Sheet Location	December 31, 2011
	Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	264	$	240
Swaps	Accrued expenses	36		46
Total		$	300	$	286

Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	1,636	$	1,624
Swaps	Prepaid expenses and other	4		2
Swaps	Accrued expenses	38		51
Options	Receivables, net	2		—
Options	Accrued expenses	—		2
Physical purchase contracts	Inventories	—		2
Foreign currency contracts	Accrued expenses	—		3
Total		$	1,680	$	1,684
Total derivatives		$	1,980	$	1,970

Market and Counterparty Risk

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

As of September 30, 2012 and December 31, 2011, we had net receivables related to derivative instruments from counterparties in the refining industry of $1 million and $2 million, respectively. These amounts represent the aggregate amount payable to us by companies in those industries, reduced by payables from us to those companies under master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party. We do not require any collateral or other security to support derivative instruments into which we enter. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments on Income and Other Comprehensive Income

The following tables provide information about the gain or loss recognized in income and other comprehensive income on our derivative instruments and the line items in the financial statements in which such gains and losses are reflected (in millions).



Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended September 30,						Nine Months Ended September 30,
Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2012			2011			2012			2011
Commodity contracts:
Gain (loss) recognized in income on derivatives	Cost of sales	$	(127	)	$	170		$	(307	)	$	219
Gain (loss) recognized in income on hedged item	Cost of sales	101			(161		)	238			(222		)
Gain (loss) recognized in income on derivatives (ineffective portion)	Cost of sales	(26		)	9			(69		)	(3		)

For fair value hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and nine months ended September 30, 2012 and 2011. There were no amounts recognized in income for hedged firm commitments that no longer qualified as fair value hedges during the three months ended September 30, 2012; however, a gain of $28 million was recognized in income during the nine months ended September 30, 2012 for hedged firm commitments that no longer qualified as fair value hedges. No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges for the three and nine months ended September 30, 2011.



Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended September 30,					Nine Months Ended September 30,
Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2012			2011		2012		2011
Commodity contracts:
Gain recognized in OCI on derivatives (effective portion)		$	27		$	20	$	43	$	20
Gain reclassified from accumulated OCI into income (effective portion)	Cost of sales	45			—		81		—
Gain (loss) recognized in income on derivatives (ineffective portion)	Cost of sales	(3		)	4		23		4

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For cash flow hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and nine months ended September 30, 2012 and 2011. For the three and nine months ended September 30, 2012, cash flow hedges primarily related to forward sales of gasoline and distillates, and associated forward purchases of crude oil, with $6 million of cumulative after-tax losses on cash flow hedges remaining in accumulated other comprehensive income. We estimate that $9 million of the deferred loss as of September 30, 2012 will be reclassified into cost of sales over the next 12 months as a result of hedged transactions that are forecasted to occur. For the three and nine months ended September 30, 2012 and 2011, there were no amounts reclassified from accumulated other comprehensive income into income as a result of the discontinuance of cash flow hedge accounting.



Derivatives Designated as Economic Hedges and Other Derivative Instruments	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended September 30,					Nine Months Ended September 30,
	Location of Gain (Loss) Recognized in Income on Derivatives	2012			2011		2012			2011
Commodity contracts	Cost of sales	$	(333	)	$	9	$	90		$	(362	)
Foreign currency contracts	Cost of sales	(21		)	41		(43		)	32
Other contract	Cost of sales	—			29		—			29
Total		$	(354	)	$	79	$	47		$	(301	)

The gain of $29 million on the other contract for the three and nine months ended September 30, 2011 is related to the difference between the fair value of inventories acquired in connection with the Pembroke Acquisition and the amount paid for such inventories based on the terms of the purchase agreement.



Trading Derivatives	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended September 30,					Nine Months Ended September 30,
Trading Derivatives	Location of Gain (Loss) Recognized in Income on Derivatives	2012			2011		2012			2011
Commodity contracts	Cost of sales	$	(13	)	$	3	$	(9	)	$	17

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

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

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

These forward-looking statements include, among other things, statements regarding:


•	future refining margins, including gasoline and distillate margins;


•	future retail margins, including gasoline, diesel, home heating oil, and convenience store merchandise margins;


•	future ethanol margins;


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


•	anticipated levels of crude oil and refined product inventories;


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


•	anticipated trends in the supply of and demand for crude oil and other feedstocks and refined products globally and in the regions where we operate;


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


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

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


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


•	political and economic conditions in nations that produce crude oil or consume refined products;


•	demand for, and supplies of, refined products such as gasoline, diesel fuel, jet fuel, home heating oil, petrochemicals, and ethanol;


•	demand for, and supplies of, crude oil and other feedstocks;


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


•	the level of consumer demand, including seasonal fluctuations;


•	refinery overcapacity or undercapacity;


•	our ability to successfully integrate any acquired businesses into our operations;


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

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•	the level of competitors’ imports into markets that we supply;


•	accidents, unscheduled shutdowns, or other catastrophes affecting our refineries, machinery, pipelines, equipment, and information systems, 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;


•	the levels of government subsidies for ethanol and other alternative fuels;


•	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, grain and other feedstocks, and refined products and ethanol;


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

•

legislative or regulatory action, including the introduction or enactment of legislation or rulemakings by governmental authorities, including tax and environmental regulations, such as those being implemented under the California Global Warming Solutions Act (also known as AB 32) and the United States (U.S.) Environmental Protection Agency’s (EPA) regulation of greenhouse gases, 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, the pound sterling, and the euro relative to the U.S. dollar; and


•	overall economic conditions, including the stability and liquidity of financial markets.

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

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

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OVERVIEW AND OUTLOOK

Overview

For the third quarter of 2012, we reported net income attributable to Valero stockholders from continuing operations of $674 million, or $1.21 per share (assuming dilution), compared to $1.2 billion, or $2.11 per share (assuming dilution), for the third quarter of 2011. The decline in net income attributable to Valero stockholders from continuing operations of $529 million was primarily due to the decrease of $670 million in our operating income as outlined by business segment in the following table (in millions):



	Three Months Ended September 30,
	2012			2011			Change
Operating income (loss) by business segment:
Refining	$	1,528		$	1,947		$	(419	)
Retail	41			97			(56		)
Ethanol	(73		)	107			(180		)
Corporate	(187		)	(172		)	(15		)
Total	$	1,309		$	1,979		$	(670	)

The results for the third quarter of 2012 were significantly impacted by an asset impairment loss of $345 million, of which $333 million related to our Aruba Refinery, and severance expense of $41 million, which was also related to our Aruba Refinery. Excluding these significant items, total operating income would have been $1.7 billion and refining operating income would have been $1.9 billion for the third quarter of 2012. The remaining decrease of $284 million in total operating income was primarily due to the decrease of $180 million in our ethanol segment’s operating income due to significantly lower ethanol margins, which was primarily due to high corn prices and excess supplies of ethanol in the U.S.

For the first nine months of 2012, we reported net income attributable to Valero stockholders from continuing operations of $1.1 billion, or $1.93 per share (assuming dilution), compared to $2.1 billion, or $3.59 per share (assuming dilution), for the first nine months of 2011. The decrease in net income attributable to Valero stockholders from continuing operations of $979 million was primarily due to the decrease of $1.1 billion in our operating income as outlined by business segment in the following table (in millions):



	Nine Months Ended September 30,
	2012			2011			Change
Operating income (loss) by business segment:
Refining	$	2,773		$	3,476		$	(703	)
Retail	253			298			(45		)
Ethanol	(59		)	215			(274		)
Corporate	(541		)	(476		)	(65		)
Total	$	2,426		$	3,513		$	(1,087	)

The results for the first nine months of 2012 were significantly impacted by an asset impairment loss of $956 million, of which $928 million related to our Aruba Refinery, and severance expense of $41 million, which was also related to our Aruba Refinery. In addition, the results of the first nine months of 2011 were significantly impacted by a $542 million loss on commodity derivative contracts related to forward sales of refined product, which were closed and realized in the first quarter of 2011. Excluding these significant items, total operating income for the first nine months of 2012 and the first nine months of 2011 would have

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been $3.4 billion and $4.1 billion, respectively, and our refining operating income for the first nine months of 2012 and the first nine months of 2011 would have been $3.8 billion and $4.0 billion, respectively.

The decrease of $632 million in total operating income was primarily due to:


•	a decrease of $260 million in our refining segment’s operating income that resulted from a $294 million increase in refining operating expenses attributable to our Pembroke and Meraux Refineries which were acquired in August 2011 and October 2011, respectively, and


•	a decrease of $274 million in our ethanol segment’s operating income that was attributable to lower ethanol margins caused by excess supplies of ethanol due to reduced demand for ethanol associated with the decline in gasoline demand in the U.S. and increased imports of ethanol from Brazil.

In September 2012, we decided to reorganize the Aruba Refinery into a crude oil and refined products terminal in response to the withdrawal of a non-binding offer by an interested party to purchase the refinery. Because of our decision, we recorded an asset impairment loss of $333 million in September 2012. We had previously recorded an asset impairment loss of $595 million in March 2012 in connection with our decision to suspend operations at the refinery due to its inability to generate positive cash flows on a sustained basis subsequent to its restart in January 2011 and the sensitivity of its profitability to sour crude oil differentials. The reorganization of the Aruba Refinery into terminal operations will result in the termination of a majority of our employees in Aruba, who will receive termination benefits. As a result, we recognized a severance liability of $41 million in September 2012. These matters are more fully discussed in Notes 3 and 6, respectively, of Notes to Condensed Consolidated Financial Statements.

Outlook

Throughout 2011 and the first nine months of 2012, our refining business has benefited from processing sweet crude oils sourced from the inland U.S., such as West Texas Intermediate (WTI) crude oil, due to the favorable difference between the price of these crude oils versus the price of benchmark sweet crude oils, such as Louisiana Light Sweet (LLS) and Brent crude oils. Historically, the price of WTI-type crude oil has closely approximated LLS and Brent crude oils, but due to the significant development of crude oil reserves within the U.S. Mid-Continent region and increased deliveries of crude oil from Canada into the U.S. Mid-Continent region, the increased supply of WTI-type crude oil has resulted in WTI-type crude oil being priced at a significant discount to LLS and Brent crude oils. This benefit, however, may decline as various crude oil pipeline and logistics projects are completed. These projects will allow sweet crude oils from the inland U.S. to be transported to the U.S. Gulf Coast region, which is expected to result in a narrowing of the price differential of WTI-priced crude oils relative to Brent-priced crude oil. As a result, the margins for refined products for refiners that process WTI-priced crude oils may decline.

The U.S. and worldwide refining business continues to experience capacity rationalization, particularly in Europe, the U.S. East Coast, and the Caribbean, where declining product margins have negatively impacted refineries in those regions. Refineries in those regions have closed, such as the Aruba Refinery discussed above, and others may close in the future. However, some of these refineries may continue to be operated, which could have a negative impact on refined product margins.

Thus far in the fourth quarter of 2012, ethanol margins, while still unfavorable, have begun to recover from the depressed margins experienced during the first nine months of 2012.

We expect energy markets and margins to continue to be volatile in the near to mid-term.

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RESULTS OF OPERATIONS

The following tables highlight our results of operations, our operating performance, and market prices that directly impact our operations. The narrative following these tables provides an analysis of our results of operations.

Financial Highlights (a) (b)

(millions of dollars, except per share amounts)



	Three Months Ended September 30,
	2012			2011			Change
Operating revenues	$	34,726		$	33,713		$	1,013
Costs and expenses:
Cost of sales	31,312			30,033			1,279
Operating expenses:
Refining (c)	930			870			60
Retail	178			177			1
Ethanol	76			103			(27		)
General and administrative expenses	174			161			13
Depreciation and amortization expense:
Refining	345			340			5
Retail	32			29			3
Ethanol	12			10			2
Corporate	13			11			2
Asset impairment loss (d)	345			—			345
Total costs and expenses	33,417			31,734			1,683
Operating income	1,309			1,979			(670		)
Other income (expense), net	(2		)	1			(3		)
Interest and debt expense, net of capitalized interest	(70		)	(88		)	18
Income from continuing operations before income tax expense	1,237			1,892			(655		)
Income tax expense	564			689			(125		)
Net income	673			1,203			(530		)
Less: Net loss attributable to noncontrolling interests	(1		)	—			(1		)
Net income attributable to Valero stockholders	$	674		$	1,203		$	(529	)

Earnings per common share – assuming dilution	$	1.21		$	2.11		$	(0.90	)

________________

See note references on page 46.

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Operating Highlights

(millions of dollars, except per barrel amounts)



	Three Months Ended September 30,
	2012		2011		Change
Refining (a) (b):
Operating income (c) (d)	$	1,528	$	1,947	$	(419	)
Throughput margin per barrel (e)	$	13.12	$	13.24	$	(0.12	)
Operating costs per barrel:
Operating expenses	3.72		3.65		0.07
Depreciation and amortization expense	1.45		1.43		0.02
Total operating costs per barrel (d)	5.17		5.08		0.09
Operating income per barrel	$	7.95	$	8.16	$	(0.21	)

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude	464		540		(76		)
Medium/light sour crude	483		455		28
Acidic sweet crude	69		150		(81		)
Sweet crude	969		739		230
Residuals	204		310		(106		)
Other feedstocks	130		123		7
Total feedstocks	2,319		2,317		2
Blendstocks and other	281		275		6
Total throughput volumes	2,600		2,592		8

Yields (thousand barrels per day):
Gasolines and blendstocks	1,262		1,196		66
Distillates	902		894		8
Other products (f)	458		519		(61		)
Total yields	2,622		2,609		13

_______________

See note references on page 46.

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Refining Operating Highlights by Region (g)

(millions of dollars, except per barrel amounts)



	Three Months Ended September 30,
	2012			2011		Change
U.S. Gulf Coast (a):
Operating income (c) (d)	$	755		$	1,167	$	(412	)
Throughput volumes (thousand barrels per day)	1,415			1,522		(107		)
Throughput margin per barrel (e)	$	11.05		$	13.08	$	(2.03	)
Operating costs per barrel:
Operating expenses	3.75			3.31		0.44
Depreciation and amortization expense	1.50			1.43		0.07
Total operating costs per barrel (c) (d)	5.25			4.74		0.51
Operating income per barrel	$	5.80		$	8.34	$	(2.54	)

U.S. Mid-Continent:
Operating income	$	708		$	586	$	122
Throughput volumes (thousand barrels per day)	452			400		52
Throughput margin per barrel (e)	$	22.07		$	22.27	$	(0.20	)
Operating costs per barrel:
Operating expenses	3.56			4.76		(1.20		)
Depreciation and amortization expense	1.47			1.59		(0.12		)
Total operating costs per barrel	5.03			6.35		(1.32		)
Operating income per barrel	$	17.04		$	15.92	$	1.12

North Atlantic (b):
Operating income	$	384		$	65	$	319
Throughput volumes (thousand barrels per day)	453			386		67
Throughput margin per barrel (e)	$	13.25		$	5.46	$	7.79
Operating costs per barrel:
Operating expenses	3.21			2.91		0.30
Depreciation and amortization expense	0.84			0.74		0.10
Total operating costs per barrel	4.05			3.65		0.40
Operating income per barrel	$	9.20		$	1.81	$	7.39

U.S. West Coast:
Operating income	$	55		$	129	$	(74	)
Throughput volumes (thousand barrels per day)	280			284		(4		)
Throughput margin per barrel (e)	$	8.91		$	11.96	$	(3.05	)
Operating costs per barrel:
Operating expenses	4.63			4.94		(0.31		)
Depreciation and amortization expense	2.15			2.08		0.07
Total operating costs per barrel	6.78			7.02		(0.24		)
Operating income per barrel	$	2.13		$	4.94	$	(2.81	)

Operating income for regions above	$	1,902		$	1,947	$	(45	)
Severance expense (c)	(41		)	—		(41		)
Asset impairment loss (d)	(333		)	—		(333		)
Total refining operating income	$	1,528		$	1,947	$	(419	)

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See note references on page 46.

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Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)



	Three Months Ended September 30,
	2012			2011		Change
Feedstocks:
Brent crude oil	$	109.48		$	112.28	$	(2.80	)
Brent less WTI crude oil	17.30			22.54		(5.24		)
Brent less Alaska North Slope (ANS) crude oil	0.66			0.67		(0.01		)
Brent less LLS crude oil	(1.06		)	0.10		(1.16		)
Brent less Mars crude oil	4.13			2.66		1.47
Brent less Maya crude oil	11.89			13.56		(1.67		)
LLS crude oil	110.54			112.18		(1.64		)
LLS less Mars crude oil	5.19			2.56		2.63
LLS less Maya crude oil	12.95			13.46		(0.51		)
WTI crude oil	92.18			89.74		2.44

Natural gas (dollars per million British thermal units)	2.87			4.09		(1.22		)

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less Brent	11.80			8.03		3.77
Ultra-low-sulfur diesel less Brent	19.60			14.07		5.53
Propylene less Brent	(41.82		)	12.37		(54.19		)
Conventional 87 gasoline less LLS	10.74			8.13		2.61
Ultra-low-sulfur diesel less LLS	18.54			14.17		4.37
Propylene less LLS	(42.88		)	12.47		(55.35		)
U.S. Mid-Continent:
Conventional 87 gasoline less WTI	34.33			31.99		2.34
Ultra-low-sulfur diesel less WTI	39.47			38.29		1.18
North Atlantic:
Conventional 87 gasoline less Brent	16.45			8.76		7.69
Ultra-low-sulfur diesel less Brent	21.16			15.86		5.30
U.S. West Coast:
CARBOB 87 gasoline less ANS	19.63			10.19		9.44
CARB diesel less ANS	22.90			15.75		7.15
CARBOB 87 gasoline less WTI	36.27			32.06		4.21
CARB diesel less WTI	39.54			37.62		1.92
New York Harbor corn crush (dollars per gallon)	(0.27		)	0.36		(0.63		)

_______________

See note references on page 46.

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Operating Highlights (continued)

(millions of dollars, except per gallon amounts)



	Three Months Ended September 30,
	2012			2011			Change
Retail–U.S.:
Operating income (d)	$	17		$	59		$	(42	)
Company-operated fuel sites (average)	1,025			994			31
Fuel volumes (gallons per day per site)	5,143			5,168			(25		)
Fuel margin per gallon	$	0.089		$	0.155		$	(0.066	)
Merchandise sales	$	328		$	324		$	4
Merchandise margin (percentage of sales)	30.2		%	29.2		%	1.0		%
Margin on miscellaneous sales	$	21		$	22		$	(1	)
Operating expenses	$	115		$	111		$	4
Depreciation and amortization expense	$	19		$	19		$	—
Asset impairment loss (d)	$	12		$	—		$	12

Retail–Canada:
Operating income	$	24		$	38		$	(14	)
Fuel volumes (thousand gallons per day)	3,117			3,214			(97		)
Fuel margin per gallon	$	0.235		$	0.273		$	(0.038	)
Merchandise sales	$	71		$	72		$	(1	)
Merchandise margin (percentage of sales)	29.5		%	29.4		%	0.1		%
Margin on miscellaneous sales	$	11		$	11		$	—
Operating expenses	$	63		$	66		$	(3	)
Depreciation and amortization expense	$	13		$	10		$	3

Ethanol:
Operating income (loss)	$	(73	)	$	107		$	(180	)
Production (thousand gallons per day)	2,384			3,272			(888		)
Gross margin per gallon of production (e)	$	0.06		$	0.73		$	(0.67	)
Operating costs per gallon of production:
Operating expenses	0.34			0.34			—
Depreciation and amortization expense	0.05			0.04			0.01
Total operating costs per gallon of production	0.39			0.38			0.01
Operating income (loss) per gallon of production	$	(0.33	)	$	0.35		$	(0.68	)

_______________

See note references on page 46.

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The following notes relate to references on pages 41 through 45.


(a)	For the three months ended September 30, 2012, the financial highlights and operating highlights for the refining segment and U.S. Gulf Coast region include the results of operations of our Meraux Refinery, including related logistics assets, from the date of its acquisition on October 1, 2011.


(b)	For the three months ended September 30, 2012, the financial highlights and operating highlights for the refining segment and North Atlantic region include the results of operations of our Pembroke Refinery, including the related marketing and logistics business, from the date of its acquisition on August 1, 2011.

(c)

In September 2012, we decided to reorganize our Aruba Refinery into a crude oil and refined products terminal. These terminal operations will require a considerably smaller workforce; therefore, the reorganization will result in the termination of the majority of our employees in Aruba. We informed the employees who will be terminated and reached agreement on termination benefits with them in September. As such, we recognized severance expense of $41 million in the third quarter of 2012. This expense is reflected in refining segment operating income for the three months ended September 30, 2012, but it is excluded from operating costs per barrel for the refining segment and the U.S. Gulf Coast region. No income tax benefits were recognized related to this severance expense.

(d)

As described in note (c), we decided to reorganize the Aruba Refinery into a crude oil and refined products terminal in September 2012. We had previously suspended refining operations in March 2012, and as a result of our recent decision, these operations will remain suspended indefinitely. We will, however, continue to maintain the refining assets to allow them to be restarted; therefore, we do not consider these assets to be abandoned. We evaluated the Aruba Refinery for potential impairment in connection with our decision and determined that the net book value (carrying amount) of the refining assets of $308 million was not recoverable through the future operations and disposition of the refinery. We determined that these refining assets had no value after considering estimated salvage costs, and we recognized an asset impairment loss of $308 million in the third quarter of 2012. In addition, we recognized an asset impairment loss of $25 million related to supplies inventories that supported the refining operations, resulting in an asset impairment loss totaling $333 million in the third quarter of 2012 related to the refinery. These asset impairment losses are reflected in refining segment operating income for the three months ended September 30, 2012, but they are excluded from operating costs per barrel for the refining segment and from operating income and operating costs per barrel for the U.S. Gulf Coast region. No income tax benefit was recognized related to this asset impairment loss. We also recognized asset impairment losses of $12 million ($8 million after taxes) related to certain retail stores in the third quarter of 2012.


(e)	Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.


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

(g)

The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, St. Charles, Aruba, Port Arthur, and Meraux Refineries; the U.S. Mid-Continent region includes the McKee, Ardmore, and Memphis Refineries; the North Atlantic region includes the Pembroke and Quebec City Refineries; and the U.S.West Coast region includes the Benicia and Wilmington Refineries.

General

Operating revenues increased 3 percent (or $1.0 billion) for the third quarter of 2012 compared to the third quarter of 2011 primarily as a result of higher refined product prices between the two periods related to our refining segment operations. Throughput volumes were essentially unchanged between the two quarters because the incremental throughputs of 55,000 barrels per day and 52,000 barrels per day from the Meraux and Pembroke Refineries, which were acquired on October 1, 2011 and August 1, 2011, respectively, were offset by a 180,000 barrel per day decline in throughput volumes at the Aruba Refinery due to the suspension of its operations in March 2012. Operating income decreased $670 million and income from continuing operations before income tax expense decreased $655 million for the third quarter of 2012 compared to amounts reported for the third quarter of 2011 due to a $419 million decrease in refining segment operating income, a $56 million decrease in retail segment operating income, and a $180 million decrease in ethanol segment operating income, which are discussed below.

Refining

Refining segment operating income decreased 22 percent (or $419 million) from $1.9 billion for the third quarter of 2011 to $1.5 billion for the third quarter of 2012. The $419 million decrease in operating income was impacted by a $333 million asset impairment loss and $41 million in severance expense in the third quarter of 2012 related to our Aruba Refinery. (See Notes 3 and 6 of Condensed Notes to Consolidated Financial Statements for discussion of the asset impairment loss and severance loss, respectively.) Excluding

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these amounts, refining segment operating income decreased $45 million primarily due to a $21 million decrease in refining margin and a $19 million increase in operating expenses.

The decrease in our refining margin of $21 million in the third quarter of 2012 as compared to the third quarter of 2011 resulted from a decrease in sour crude oil discounts and lower margins for propylene. These decreases were offset by higher gasoline and distillate margins.

The increase of $19 million in refining operating expenses discussed above was primarily due to $47 million in operating expenses incurred by the Meraux Refinery, which was acquired on October 1, 2011, and $34 million in operating expenses incurred by the Pembroke Refinery, which was acquired on August 1, 2011, partially offset by a $44 million decrease in operating expenses incurred by the Aruba Refinery, whose operations were suspended throughout the third quarter of 2012. The remaining decrease in refining operating expenses of $18 million was primarily due to a $14 million decrease in energy costs.

Retail

Retail segment operating income was $41 million for the third quarter of 2012 compared to $97 million for the third quarter of 2011. This 58 percent (or $56 million) decrease was primarily due to decreases in the fuel margins generated by both our U.S. and Canadian retail operations of $30 million and $14 million, respectively. The significant decrease in fuel margins in our retail operations was largely the result of increases in the wholesale prices for gasoline and diesel. Although we generally increase retail prices as wholesale prices increase, we are unable to increase retail prices at the same rate as wholesale price increases, which results in reduced fuel margins. Retail segment operating income was also negatively impacted in the third quarter of 2012 by a $12 million asset impairment loss related to certain convenience stores in the U.S.

Ethanol

Ethanol segment operating loss was $73 million for the third quarter of 2012 compared to operating income of $107 million for the third quarter of 2011. The $180 million decrease in operating income was primarily due to a $205 million decrease in gross margin, partially offset by a $27 million decrease in operating expenses.

The gross margin per gallon decreased 92 percent ($0.67 per gallon) between the third quarter of 2011 and the third quarter of 2012 primarily due to higher corn prices and lower ethanol prices between the periods. The increase in average corn prices from the third quarter of 2011 to the third quarter of 2012 was primarily caused by the drought in corn-producing regions of the U.S. Mid-Continent, which negatively impacted gross margin by $0.35 cents per gallon. Gross margin per gallon was further impacted by a decrease of $0.26 cents per gallon in the price of ethanol between the comparable periods. Ethanol prices in the third quarter of 2012 were pressured by a surplus of ethanol supply during the quarter due to reduced demand for ethanol resulting from a decline in gasoline demand in the U.S. and increased imports of ethanol from Brazil. In addition, ethanol production decreased 888,000 gallons per day between the comparable periods, resulting from lower utilization rates during the third quarter of 2012 in response to the surplus of ethanol supply. The reduction in operating expenses was primarily due to a $19 million decrease in energy costs due to decreased consumption combined with lower natural gas prices and an $8 million decrease in chemical expenses compared to the third quarter of 2011.

Corporate Expenses and Other

General and administrative expenses increased $13 million from the third quarter of 2011 to the third quarter of 2012 primarily due to a $12 million increase in employee-related expenses.

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“Interest and debt expense, net of capitalized interest” for the third quarter of 2012 decreased $18 million from the third quarter of 2011. This decrease was primarily due to a $17 million increase in capitalized interest due to a corresponding increase in capital expenditures between the quarters.

Income tax expense decreased $125 million from the third quarter of 2011 to the third quarter of 2012 mainly as a result of lower income from continuing operations before income tax expense. However, the variation in the customary relationship between income tax expense and income from continuing operations before income tax expense for the third quarter of 2012 was primarily due to not recognizing the tax benefits associated with the asset impairment loss of $333 million and the severance loss of $41 million recognized in the third quarter of 2012 related to the Aruba Refinery as we do not expect to realize a tax benefit from these losses.

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Financial Highlights (a) (b)

(millions of dollars, except per share amounts)



	Nine Months Ended September 30,
	2012			2011			Change
Operating revenues	$	104,555		$	91,314		$	13,241
Costs and expenses:
Cost of sales (c)	95,968			82,981			12,987
Operating expenses:
Refining (d)	2,762			2,427			335
Retail	514			508			6
Ethanol	248			302			(54		)
General and administrative expenses	509			442			67
Depreciation and amortization expense:
Refining	1,020			995			25
Retail	88			84			4
Ethanol	32			28			4
Corporate	32			34			(2		)
Asset impairment loss (e)	956			—			956
Total costs and expenses	102,129			87,801			14,328
Operating income	2,426			3,513			(1,087		)
Other income, net	(1		)	28			(29		)
Interest and debt expense, net of capitalized interest	(243		)	(312		)	69
Income from continuing operations before income tax expense	2,182			3,229			(1,047		)
Income tax expense	1,111			1,178			(67		)
Income from continuing operations	1,071			2,051			(980		)
Loss from discontinued operations, net of income taxes	—			(7		)	7
Net income	1,071			2,044			(973		)
Less: Net loss attributable to noncontrolling interests	(2		)	(1		)	(1		)
Net income attributable to Valero stockholders	$	1,073		$	2,045		$	(972	)

Net income attributable to Valero stockholders:
Continuing operations	$	1,073		$	2,052		$	(979	)
Discontinued operations	—			(7		)	7
Total	$	1,073		$	2,045		$	(972	)

Earnings per common share – assuming dilution:
Continuing operations	$	1.93		$	3.59		$	(1.66	)
Discontinued operations	—			(0.01		)	0.01
Total	$	1.93		$	3.58		$	(1.65	)

_______________

See note references on page 54.

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Operating Highlights

(millions of dollars, except per barrel amounts)



	Nine Months Ended September 30,
	2012		2011		Change
Refining (a) (b):
Operating income (c) (d) (e)	$	2,773	$	3,476	$	(703	)
Throughput margin per barrel (f)	$	10.51	$	11.65	$	(1.14	)
Operating costs per barrel:
Operating expenses (d)	3.81		3.80		0.01
Depreciation and amortization expense	1.43		1.56		(0.13		)
Total operating costs per barrel (e)	5.24		5.36		(0.12		)
Operating income per barrel	$	5.27	$	6.29	$	(1.02	)

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude	435		455		(20		)
Medium/light sour crude	549		415		134
Acidic sweet crude	92		117		(25		)
Sweet crude	913		695		218
Residuals	196		284		(88		)
Other feedstocks	132		122		10
Total feedstocks	2,317		2,088		229
Blendstocks and other	287		252		35
Total throughput volumes	2,604		2,340		264

Yields (thousand barrels per day):
Gasolines and blendstocks	1,249		1,069		180
Distillates	911		793		118
Other products (g)	465		491		(26		)
Total yields	2,625		2,353		272

_______________

See note references on page 54.

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Refining Operating Highlights by Region (h)

(millions of dollars, except per barrel amounts)



	Nine Months Ended September 30,
	2012			2011			Change
U.S. Gulf Coast (a):
Operating income (c) (d) (e)	$	1,627		$	2,436		$	(809	)
Throughput volumes (thousand barrels per day)	1,460			1,418			42
Throughput margin per barrel (c) (f)	$	9.14		$	11.44		$	(2.30	)
Operating costs per barrel:
Operating expenses	3.60			3.62			(0.02		)
Depreciation and amortization expense	1.47			1.53			(0.06		)
Total operating costs per barrel (d) (e)	5.07			5.15			(0.08		)
Operating income per barrel	$	4.07		$	6.29		$	(2.22	)

U.S. Mid-Continent:
Operating income (c)	$	1,406		$	1,268		$	138
Throughput volumes (thousand barrels per day)	418			401			17
Throughput margin per barrel (c) (f)	$	18.02		$	17.29		$	0.73
Operating costs per barrel:
Operating expenses	4.25			4.14			0.11
Depreciation and amortization expense	1.50			1.56			(0.06		)
Total operating costs per barrel	5.75			5.70			0.05
Operating income per barrel	$	12.27		$	11.59		$	0.68

North Atlantic (b):
Operating income	$	617		$	104		$	513
Throughput volumes (thousand barrels per day)	463			268			195
Throughput margin per barrel (f)	$	8.95		$	5.32		$	3.63
Operating costs per barrel:
Operating expenses	3.32			2.92			0.40
Depreciation and amortization expense	0.76			0.98			(0.22		)
Total operating costs per barrel	4.08			3.90			0.18
Operating income per barrel	$	4.87		$	1.42		$	3.45

U.S. West Coast:
Operating income (c)	$	108		$	210		$	(102	)
Throughput volumes (thousand barrels per day)	263			253			10
Throughput margin per barrel (c) (f)	$	8.94		$	10.56		$	(1.62	)
Operating costs per barrel:
Operating expenses	5.16			5.21			(0.05		)
Depreciation and amortization expense	2.28			2.31			(0.03		)
Total operating costs per barrel	7.44			7.52			(0.08		)
Operating income per barrel	$	1.50		$	3.04		$	(1.54	)

Operating income for regions above	$	3,758		$	4,018		$	(260	)
Loss on derivative contracts related to the forward sales of refined product (c)	—			(542		)	542
Severance expense (d)	(41		)	—			(41		)
Asset impairment loss (e)	(944		)	—			(944		)
Total refining operating income	$	2,773		$	3,476		$	(703	)

_______________

See note references on page 54.

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Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)



	Nine Months Ended September 30,
	2012			2011			Change
Feedstocks:
Brent crude oil	$	112.26		$	111.54		$	0.72
Brent less WTI crude oil	16.09			16.15			(0.06		)
Brent less ANS crude oil	0.22			2.25			(2.03		)
Brent less LLS crude oil	(0.95		)	(0.18		)	(0.77		)
Brent less Mars crude oil	3.58			3.88			(0.30		)
Brent less Maya crude oil	10.36			14.39			(4.03		)
LLS crude oil	113.21			111.72			1.49
LLS less Mars crude oil	4.53			4.06			0.47
LLS less Maya crude oil	11.31			14.57			(3.26		)
WTI crude oil	96.17			95.39			0.78

Natural gas (dollars per million British thermal units)	2.50			4.19			(1.69		)

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less Brent	9.08			7.58			1.50
Ultra-low-sulfur diesel less Brent	16.16			13.27			2.89
Propylene less Brent	(21.56		)	19.56			(41.12		)
Conventional 87 gasoline less LLS	8.13			7.40			0.73
Ultra-low-sulfur diesel less LLS	15.21			13.09			2.12
Propylene less LLS	(22.51		)	19.38			(41.89		)
U.S. Mid-Continent:
Conventional 87 gasoline less WTI	26.65			24.77			1.88
Ultra-low-sulfur diesel less WTI	32.51			30.74			1.77
North Atlantic:
Conventional 87 gasoline less Brent	12.20			7.28			4.92
Ultra-low-sulfur diesel less Brent	17.71			15.04			2.67
U.S. West Coast:
CARBOB 87 gasoline less ANS	17.35			13.36			3.99
CARB diesel less ANS	18.76			18.56			0.20
CARBOB 87 gasoline less WTI	33.22			27.26			5.96
CARB diesel less WTI	34.63			32.46			2.17
New York Harbor corn crush (dollars per gallon)	(0.12		)	0.17			(0.29		)

_______________

See note references on page 54.

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Operating Highlights (continued)

(millions of dollars, except per gallon amounts)



	Nine Months Ended September 30,
	2012			2011			Change
Retail–U.S.:
Operating income (e)	$	162		$	165		$	(3	)
Company-operated fuel sites (average)	1,007			994			13
Fuel volumes (gallons per day per site)	5,114			5,053			61
Fuel margin per gallon	$	0.147		$	0.146		$	0.001
Merchandise sales	$	936		$	930		$	6
Merchandise margin (percentage of sales)	29.9		%	28.6		%	1.3		%
Margin on miscellaneous sales	$	67		$	66		$	1
Operating expenses	$	325		$	312		$	13
Depreciation and amortization expense	$	57		$	56		$	1
Asset impairment loss (e)	$	12		$	—		$	12

Retail–Canada:
Operating income	$	91		$	133		$	(42	)
Fuel volumes (thousand gallons per day)	3,110			3,210			(100		)
Fuel margin per gallon	$	0.259		$	0.303		$	(0.044	)
Merchandise sales	$	194		$	197		$	(3	)
Merchandise margin (percentage of sales)	29.4		%	29.6		%	(0.2		)%
Margin on miscellaneous sales	$	33		$	33		$	—
Operating expenses	$	189		$	196		$	(7	)
Depreciation and amortization expense	$	31		$	28		$	3

Ethanol:
Operating income (loss)	$	(59	)	$	215		$	(274	)
Production (thousand gallons per day)	3,069			3,317			(248		)
Gross margin per gallon of production (f)	$	0.26		$	0.60		$	(0.34	)
Operating costs per gallon of production:
Operating expenses	0.29			0.33			(0.04		)
Depreciation and amortization expense	0.04			0.03			0.01
Total operating costs per gallon of production	0.33			0.36			(0.03		)
Operating income (loss) per gallon of production	$	(0.07	)	$	0.24		$	(0.31	)

_______________

See note references on page 54.

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The following notes relate to references on pages 49 through 53.


(a)	For the nine months ended September 30, 2012, the financial highlights and operating highlights for the refining segment and U.S. Gulf Coast region include the results of operations of our Meraux Refinery, including related logistics assets, from the date of its acquisition on October 1, 2011.


(b)	For the nine months ended September 30, 2012, the financial highlights and operating highlights for the refining segment and North Atlantic region include the results of operations of our Pembroke Refinery, including the related marketing and logistics business, from the date of its acquisition on August 1, 2011.

(c)

Cost of sales for the nine months ended September 30, 2011 includes a loss of $542 million ($352 million after taxes) on commodity derivative contracts related to the forward sales of refined product. These contracts were closed and realized during the first quarter of 2011. The loss is reflected in refining segment operating income for the nine months ended September 30, 2011, but throughput margin per barrel for the refining segment has been restated from the amount previously presented to exclude this $542 million loss ($0.85 per barrel). In addition, operating income and throughput margin per barrel for the U.S. Gulf Coast, U.S. Mid-Continent, and U.S. West Coast regions for the nine months ended September 30, 2011 have been restated from the amounts previously presented to exclude the portion of this loss that had been allocated to them of $372 million ($0.96 per barrel); $122 million ($1.11 per barrel), and $48 million ($0.69 per barrel), respectively.

(d)

In September 2012, we decided to reorganize our Aruba Refinery into a crude oil and refined products terminal. These terminal operations will require a considerably smaller workforce; therefore, the reorganization will result in the termination of the majority of our employees in Aruba. We informed the employees who will be terminated and reached agreement on termination benefits with them in September. As such, we recognized severance expense of $41 million in the third quarter of 2012. This expense is reflected in refining segment operating income for the nine months ended September 30, 2012, but it is excluded from operating costs per barrel for the refining segment and the U.S. Gulf Coast region . No income tax benefits were recognized related to this severance expense.

(e)

As described in note (d), we decided to reorganize the Aruba Refinery into a crude oil and refined products terminal in September 2012. We had previously suspended refining operations in March 2012, and as a result of our recent decision, these operations will remain suspended indefinitely. We will, however, continue to maintain the refining assets to allow them to be restarted; therefore, we do not consider these assets to be abandoned. We evaluated the Aruba Refinery for potential impairment in connection with our decision and determined that the net book value (carrying amount) of the refining assets of $308 million was not recoverable through the future operations and disposition of the refinery. We determined that these refining assets had no value after considering estimated salvage costs, and we recognized an asset impairment loss of $308 million in the third quarter of 2012. In addition, we recognized an asset impairment loss of $25 million related to supplies inventories that supported the refining operations, resulting in an asset impairment loss totaling $333 million in the third quarter of 2012 related to the refinery. In the first quarter of 2012, we recognized an asset impairment loss of $595 million in connection with our decision to suspend refining operations at that time. Therefore, for the nine months ended September 30, 2012, we recognized an asset impairment loss of $928 million related to the refinery. These asset impairment losses are reflected in refining segment operating income for the nine months ended September 30, 2012, but they are excluded from operating costs per barrel for the refining segment and from operating income and operating costs per barrel for the U.S. Gulf Coast region. No income tax benefit was recognized related to this asset impairment loss. We also recognized asset impairment losses of $12 million ($8 million after taxes) related to certain retail stores in the third quarter of 2012 and $16 million ($10 million after taxes) related to equipment associated with a permanently cancelled capital project at one of our other refineries in the first quarter of 2012. The asset impairment loss related to one of our other refineries is included in refining segment operating income for the nine months ended September 30, 2012, but it is excluded from operating costs per barrel for the refining segment and from operating income and operating costs per barrel for the U.S. Gulf Coast region.


(f)	Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.


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

(h)

The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, St. Charles, Aruba, Port Arthur, and Meraux Refineries; the U.S. Mid-Continent region includes the McKee, Ardmore, and Memphis Refineries; the North Atlantic region includes the Pembroke and Quebec City Refineries; and the U.S. West Coast region includes the Benicia and Wilmington Refineries.

General

Operating revenues increased 15 percent (or $13.2 billion) for the first nine months of 2012 compared to the first nine months of 2011 primarily as a result of higher refined product prices and higher throughput volumes between the two periods related to our refining segment operations. The higher throughput volumes resulted primarily from the incremental throughput of 105,000 barrels per day from the Meraux Refinery, which was acquired on October 1, 2011, and incremental throughput of 182,000 barrels per day from the Pembroke Refinery, which was acquired on August 1, 2011. However, operating income decreased

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$1.1 billion and income from continuing operations before income tax expense decreased $1.0 billion for the first nine months of 2012 compared to amounts reported for the first nine months of 2011 primarily due to a $703 million decrease in refining segment operating income, a $45 million decrease in retail segment operating income, and a $274 million decrease in ethanol segment operating income discussed below.

Refining

Refining segment operating income decreased 20 percent (or $703 million) from $3.5 billion for the first nine months of 2011 to $2.8 billion for the first nine months of 2012. This decrease was impacted by the $542 million loss on derivative contracts in the first quarter of 2011, the $41 million severance expense, and $928 million in asset impairment losses related to the Aruba Refinery in the first nine months of 2012, and a $16 million asset impairment loss related to a cancelled capital project in the first nine months of 2012. (See Notes 3 and 6 of Condensed Notes to Consolidated Financial Statements for further discussions of the asset impairment losses and the severance expense, respectively). Excluding these amounts, our refining segment operating income decreased $260 million from $4.0 billion in the first nine months of 2011 to $3.8 billion in the first nine months of 2012. This $260 million decrease was due primarily to a $294 million increase in operating expenses, partially offset by a $59 million increase in refining margin.

The increase of $294 million in operating expenses was primarily due to an increase of $120 million in operating expenses incurred by the Meraux Refinery and an increase of $218 million in operating expenses incurred by the Pembroke Refinery, partially offset by an $84 million decrease in operating expenses incurred by the Aruba Refinery. We acquired the Pembroke Refinery on August 1, 2011 and the Meraux Refinery on October 1, 2011; therefore, operating expenses for the first nine months of 2011 only reflected two months of operating expenses of the Pembroke Refinery and no operating expenses of the Meraux Refinery. In addition, in March 2012, we suspended the operations of the Aruba Refinery, which resulted in a significant decrease in operating expenses related to that refinery in 2012. The remaining increase in operating expenses of $40 million was primarily due to an increase of $26 million in maintenance expenses, an increase of $23 million in employee-related expenses, and an increase of $72 million in ad valorem taxes and insurance expense, offset by a decrease of $78 million in energy costs. Even though operating expenses increased period over period, operating expenses per barrel increased by only $0.01 per barrel in the first nine months of 2012 over the comparable 2011 period due to the incremental throughput of 264,000 barrels per day. As previously discussed, this increased throughput was due to the incremental throughput of our Pembroke and Meraux Refineries.

The $59 million improvement in refining margin resulted from higher gasoline and distillate margins throughout all our regions, which were largely offset by a decrease in sour crude oil discounts and lower margins for propylene.

Retail

Retail segment operating income was $253 million for the first nine months of 2012 compared to $298 million for the first nine months of 2011. This 15 percent (or $45 million) decrease was primarily due to a $45 million decrease in fuel margins from our Canadian retail operations. The decline in fuel volumes and fuel margin per gallon in our Canadian retail operations from the first nine months of 2011 to the first nine months of 2012 was primarily due to the impact of increases in the wholesale prices for gasoline and diesel, which resulted in reduced fuel margins. Retail segment operating income was also negatively impacted in the first nine months of 2012 by a $12 million asset impairment loss related to certain convenience stores. However, this loss was largely offset by an increase in U.S. fuel margins due to higher fuel volumes, and an increase in U.S. merchandise margins.

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Ethanol

Ethanol segment operating loss was $59 million for the first nine months of 2012 compared to operating income of $215 million for the first nine months of 2011. The $274 million decrease in operating income was primarily due to a $324 million decrease in gross margin, partially offset by a $54 million decrease in operating expenses.

The decrease in gross margin was due to a 57 percent decrease in the gross margin per gallon of ethanol production (a $0.34 per gallon decrease between the comparable periods) primarily due to lower ethanol prices in the first nine months of 2012 versus the first nine months of 2011. Ethanol prices in the first nine months of 2012 were pressured by a surplus of ethanol supply due to reduced demand for ethanol associated with the decline in gasoline demand in the U.S. and increased imports of ethanol from Brazil. In addition, ethanol production decreased 248,000 gallons per day between the comparable periods, resulting from lower utilization rates during the first nine months of 2012. The reduction in operating expenses was due primarily to a $51 million decrease in energy costs due to decreased consumption combined with lower natural gas prices versus the comparable period of 2011 and a $4 million decrease in chemical expenses between the periods.

Corporate Expenses and Other

General and administrative expenses increased $67 million from the first nine months of 2011 to the first nine months of 2012 primarily due to $58 million in administrative costs related to our European operations, which we acquired on August 1, 2011.

“Interest and debt expense, net of capitalized interest” for the first nine months of 2012 decreased $69 million from the first nine months of 2011. This decrease was primarily due to an increase of $62 million in capitalized interest due to a corresponding increase in capital expenditures between the nine-month periods.

Income tax expense decreased $67 million from the first nine months of 2011 to the first nine months of 2012 mainly as a result of lower income from continuing operations before income tax expense. The variation in the customary relationship between income tax expense and income from continuing operations before income tax expense for the nine months ended September 30, 2012 was primarily due to not recognizing the tax benefits associated with the asset impairment loss of $928 million and the severance expense of $41 million related to the Aruba Refinery as we do not expect to realize a tax benefit from these losses.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Nine Months Ended September 30, 2012 and 2011

Net cash provided by operating activities for the first nine months of 2012 was $5.1 billion compared to $4.3 billion for the first nine months of 2011. The increase in cash generated from operating activities was primarily due to a $511 million favorable effect from changes in working capital between the periods. The changes in cash provided by or used in working capital during the first nine months of 2012 and 2011 are shown in Note 11 of Condensed Notes to Consolidated Financial Statements.

The net cash provided by operating activities during the first nine months of 2012 combined with $300 million of proceeds from the remarketing of the 4.0% Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds), $1.1 billion in borrowings under our revolving credit facility, and $1.5 billion of proceeds from the sale of receivables under our accounts receivable sales facility were used mainly to:


•	fund $2.5 billion of capital expenditures and deferred turnaround and catalyst costs;


•	redeem our Series 1997 5.6%, Series 1998 5.6%, Series 1999 5.7%, Series 2001 6.65%, and Series 1997A 5.45% industrial revenue bond for $108 million;

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•	make scheduled long-term note repayments of $754 million;


•	repay borrowings under our revolving credit facility of $1.1 billion;


•	make repayments under our accounts receivable sales facility of $1.7 billion;


•	purchase common stock for treasury of $148 million;


•	pay common stock dividends of $263 million; and


•	increase available cash on hand by $1.5 billion.

The net cash provided by operating activities during the first nine months of 2011 combined with $505 million from available cash on hand were used mainly to:


•	fund $2.1 billion of capital expenditures and deferred turnaround and catalyst costs;


•	purchase the Pembroke Refinery and the related marketing and logistics business for $1.7 billion,


•	make scheduled long-term note repayments of $418 million and acquire the GO Zone Bonds for $300 million;


•	purchase our common stock for $270 million; and


•	pay common stock dividends of $85 million.

Capital Investments

Our operations, especially those of our refining segment, are highly capital intensive. Each of our refineries comprises a large base of property assets, consisting of a series of interconnected, highly integrated and interdependent crude oil processing facilities and supporting logistical infrastructure (Units), and these Units are improved continuously. The cost of improvements, which consist of the addition of new Units and betterments of existing Units, can be significant. We have historically acquired our refineries at amounts significantly below their replacement costs, whereas our improvements are made at full replacement value. As such, the costs for improving our refinery assets increase over time and are significant in relation to the amounts we paid to acquire our refineries. We plan for these improvements by developing a multi-year capital program that is updated and revised based on changing internal and external factors.

We make improvements to our refineries in order to maintain and enhance their operating reliability, to meet environmental obligations with respect to reducing emissions and removing prohibited elements from the products we produce, or to enhance their profitability. Reliability and environmental improvements generally do not increase the throughput capacities of our refineries. Improvements that enhance refinery profitability may increase throughput capacity, but many of these improvements allow our refineries to process higher volumes of sour crude oil, which lowers our feedstock costs, and enables us to refine crude oil into products with higher market values. Therefore, many of our improvements do not increase throughput capacity significantly.

During the nine months ended September 30, 2012, we expended $2.1 billion for capital expenditures and $339 million for deferred turnaround and catalyst costs. Capital expenditures for the nine months ended September 30, 2012 included $116 million of costs related to environmental projects.

For 2012, we expect to incur approximately $3.0 billion for capital investments (approximately $150 million of which is for environmental projects) and $495 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes expenditures related to strategic business acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.

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Contractual Obligations

As of September 30, 2012, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities.

During the nine months ended September 30, 2012, we had no material changes outside the ordinary course of our business with respect to our debt, capital lease obligations, operating leases, purchase obligations, or other long-term liabilities.

During the nine months ended September 30, 2012, the following debt activity occurred:


•	in March 2012, we exercised the call provisions on our Series 1997 5.6%, Series 1998 5.6%, Series 1999 5.7%, Series 2001 6.65%, and Series 1997A 5.45% industrial revenue bonds, which were redeemed on May 3, 2012 for $108 million, or 100 percent of their outstanding stated values;


•	in April 2012, we made scheduled debt repayments of $4 million related to our Series 1997A 5.45% industrial revenue bonds and $750 million related to our 6.875% notes; and


•	in June 2012, we received proceeds of $300 million from the remarketing of the 4.0% GO Zone Bonds, which are due December 1, 2040, but are subject to mandatory tender on June 1, 2022.

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, Standard & Poor’s Ratings Services, and Fitch Ratings, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. All of our ratings on our senior unsecured debt are at or above investment grade level as follows:



Rating Agency		Rating
Standard & Poor’s Ratings Services		BBB (negative outlook)
Moody’s Investors Service		Baa2 (stable outlook)
Fitch Ratings		BBB (stable outlook)

We cannot provide assurance that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell, or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction below investment grade or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing and the cost of such financings.

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Other Commercial Commitments

As of September 30, 2012, we had outstanding letters of credit under our committed lines of credit as follows (in millions):



	Borrowing Capacity		Expiration	Outstanding Letters of Credit
Letter of credit facilities	$	550	June 2013	$	337
Revolving credit facility	$	3,000	December 2016	$	64
Canadian revolving credit facility	C$	115	December 2012	C$	10

As of September 30, 2012, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of September 30, 2012 expire during 2012 and 2013.

Other Matters Impacting Liquidity and Capital Resources

Pension Plan Funded Status

We have minimum required contributions of $2 million during 2012 to our pension plans that have minimum funding requirements; however, during the nine months ended September 30, 2012, we contributed $132 million to our pension plans.

Stock Purchase Programs

As of September 30, 2012, we have approvals under common stock purchase programs to purchase approximately $3.5 billion of our common stock.

Environmental Matters

Our operations are subject to extensive environmental regulations by governmental authorities 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 operating facilities could require material additional expenditures to comply with environmental laws and regulations. See Note 6 of Condensed Notes to Consolidated Financial Statements for a further discussion of our environmental matters.

Tax Matters

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should the IRS eventually prevail, it could result in a material amount of our deferred tax liabilities being reclassified to current liabilities which could have a material adverse effect on our liquidity.

Cash Held by Our International Subsidiaries

We operate in countries outside the U.S. through subsidiaries incorporated in these countries, and the earnings of these subsidiaries are taxed by the countries in which they are incorporated. We intend to reinvest these earnings indefinitely in our international operations even though we are not restricted from repatriating such earnings to the U.S. in the form of cash dividends. Should we decide to repatriate such earnings, we would incur and pay taxes on the amounts repatriated. In addition, such repatriation could cause us to record deferred tax expense that could significantly impact our results of operations. We believe, however, that a substantial portion of our international cash can be returned to the U.S. without significant tax consequences through means other than a repatriation of earnings. As of September 30, 2012, $1.4 billion of our cash and temporary cash investments was held by our international subsidiaries.

Financial Regulatory Reform

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Wall Street Reform Act). Key provisions of the Wall Street Reform Act create new statutory requirements that require most derivative instruments to be traded on exchanges and routed through clearinghouses, as well as impose new recordkeeping and reporting responsibilities on market participants. While certain final rules implementing the Wall Street Reform Act have started to become effective in the fourth quarter of 2012, others will not become effective until early 2013; therefore, the ultimate impact to our operations is yet unknown. However, the implementation could result in higher clearing costs and more reporting requirements with respect to our derivative activities.

Concentration of Customers

Our refining and marketing operations have a concentration of customers in the refining industry and customers who are refined product wholesalers and retailers. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively, in that these customers may be similarly affected by changes in economic or other conditions. However, we believe that our portfolio of accounts receivable is sufficiently diversified to the extent necessary to minimize potential credit risk. Historically, we have not had any significant problems collecting our accounts receivable.

Sources of Liquidity

We believe that we have sufficient funds from operations and, to the extent necessary, from borrowings under our credit facilities, to fund our ongoing operating requirements. We expect that, to the extent necessary, we can raise additional funds from time to time through equity or debt financings in the public and private capital markets or the arrangement of additional credit facilities. However, there can be no assurances regarding the availability of any future financings or additional credit facilities or whether such financings or additional credit facilities can be made available on terms that are acceptable to us.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with U. S. generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported in our 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, 2011.

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Item 3.	Quantitative and Qualitative Disclosures About Market Risk

COMMODITY PRICE RISK


•	inventories and firm commitments to purchase inventories generally for amounts by which our current year inventory levels (determined on a last-in, first-out (LIFO) basis) differ from our previous year-end LIFO inventory levels and


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

We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations. We use swaps primarily to manage our price exposure. We also enter into certain commodity derivative instruments for trading purposes to take advantage of existing market conditions related to future results of operations and cash flows.

Our positions in commodity derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.

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



	Derivative Instruments Held For
	Non-Trading Purposes			Trading Purposes
September 30, 2012:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	$	(183	)	$	10
10% decrease in underlying commodity prices	183			(9		)

December 31, 2011:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	(156		)	1
10% decrease in underlying commodity prices	156			2

See Note 13 of Condensed Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of September 30, 2012.

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COMPLIANCE PROGRAM PRICE RISK

We are exposed to market risks related to the volatility in the price of financial instruments associated with various governmental and regulatory compliance programs that we must purchase in the open market to comply with these programs. To reduce the impact of this risk on our results of operations and cash flows, we may enter into derivative instruments, such as futures. As of September 30, 2012, there was no significant gain or loss in the fair value of derivative instruments that would result from a 10 percent increase or decrease in the underlying price of the futures contracts. See Note 13 of Condensed Notes to Consolidated Financial Statements for a discussion about these compliance programs and notional volumes associated with these derivative contracts as of September 30, 2012.

INTEREST RATE RISK

The following table provides information about our debt instruments, excluding capital lease obligations (dollars in millions), the fair values of which are sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented. We had no interest rate derivative instruments outstanding as of September 30, 2012 or December 31, 2011.



	September 30, 2012
	Expected Maturity Dates
	2012			2013			2014			2015			2016			There- after			Total			Fair Value
Debt:
Fixed rate	$	—		$	480		$	200		$	475		$	—		$	5,774		$	6,929		$	8,476
Average interest rate	—		%	5.5		%	4.8		%	5.2		%	—		%	7.1		%	6.8		%
Floating rate	$	—		$	100		$	—		$	—		$	—		$	—		$	100		$	100
Average interest rate	—		%	0.9		%	—		%	—		%	—		%	—		%	0.9		%

	December 31, 2011
	Expected Maturity Dates
	2012			2013			2014			2015			2016			There- after			Total			Fair Value
Debt:
Fixed rate	$	754		$	484		$	200		$	475		$	—		$	5,578		$	7,491		$	9,048
Average interest rate	6.9		%	5.5		%	4.8		%	5.2		%	—		%	7.3		%	6.9		%
Floating rate	$	250		$	—		$	—		$	—		$	—		$	—		$	250		$	250
Average interest rate	0.6		%	—		%	—		%	—		%	—		%	—		%	0.6		%

FOREIGN CURRENCY RISK

As of September 30, 2012, we had commitments to purchase $579 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before October 24, 2012, resulting in a loss of less than $1 million in the fourth quarter of 2012.

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Item 4. Controls and Procedures


(a)	Evaluation of disclosure controls and procedures.

Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of September 30, 2012.


(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, 2011, or our quarterly reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012.

Litigation

We hereby incorporate by reference into this Item our disclosures made in Part I, Item 1 of this Report included in Note 6 of Condensed Notes to Consolidated Financial Statements under the caption “Litigation Matters.”

Environmental Enforcement Matters

While it is not possible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against us, we believe that there would be no material effect on our financial position or results of operations. We are reporting these proceedings to comply with SEC regulations, which require us to disclose certain information about proceedings arising under federal, state, or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.

EPA (mobile source enforcement). In our annual report on Form 10-K for the year ended December 31, 2011, we disclosed that the EPA was seeking penalties in connection with eight alleged violations of U.S. federal fuels regulations (most of which were self-reported) purportedly occurring from March 2004 to 2006 at various refineries and terminals. In the third quarter of 2012, we entered into an administrative settlement agreement with the EPA and paid a revised penalty amount to resolve this matter.

EPA (Port Arthur Refinery). In our annual report on Form 10-K for the year ended December 31, 2011, and in our quarterly report on Form 10-Q for the quarter ended March 31, 2012, we reported potential stipulated penalties payable to the EPA and the Texas Commission on Environmental Quality (TCEQ) relating to certain flaring events at our Port Arthur Refinery. In the third quarter of 2012, we received a total stipulated penalty demand of $5,197,500 for the flaring events. We have paid the demanded amount into escrow pending final resolution with the EPA.

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EPA (Three Rivers Refinery). In our annual report on Form 10-K for the year ended December 31, 2011, and in our quarterly report on Form 10-Q for the quarter ended March 31, 2012, we reported potential stipulated penalties payable to the EPA and the TCEQ relating to a flaring event at our Three Rivers Refinery. We paid the demanded amount in the third quarter of 2012, thus resolving this matter.

EPA (Linden ethanol plant). In the third quarter of 2012, the EPA issued a notice of violation (NOV) to our Linden, Indiana ethanol plant. The EPA seeks penalties of $208,000, alleging excess air emissions and failure to maintain properly the plant’s thermal oxider. We are evaluating our response to the NOV.

South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). In our quarterly report on Form 10-Q for the quarter ended June 30, 2012, we reported that the SCAQMD had issued 27 NOVs to our Wilmington Refinery and asphalt plant for alleged excess emission events, reporting issues, and administrative errors in 2010 and 2011. In the third quarter of 2012, we entered into settlement agreements and paid the negotiated settlement amounts to resolve these NOVs.

Item 1A. Risk Factors

We are updating one of our risk factors to describe the cybersecurity risks that we face. Except for the modified risk factor presented below, there have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2011.

A significant interruption in one or more of our refineries could adversely affect our business.

Our refineries are our principal operating assets. As a result, our operations could be subject to significant interruption if one or more of our refineries were to experience a major accident or mechanical failure, encounter work stoppages relating to organized labor issues, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs. Significant interruptions in our refining system could also lead to increased volatility in prices for crude oil feedstocks and refined products, and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain insurance coverage that we consider adequate.

In addition, our information technology systems and network infrastructure are subject to unauthorized access or attack, which could result in a loss of sensitive business information, systems interruption, or the disruption of our business operations. To protect against unauthorized access or attacks, we have implemented infrastructure protection technologies and disaster recovery plans, but there can be no assurance that a technology systems breach or systems failure will not have a material adverse effect on our financial condition or results of operations.

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


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


(b)	Use of Proceeds. Not applicable.


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



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Not Purchased as Part of Publicly Announced Plans or Programs (a)	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (b)
July 2012	2,219	$	25.17	2,219	—	$3.46 billion
August 2012	26,907	$	28.23	26,907	—	$3.46 billion
September 2012	9,504	$	32.15	9,504	—	$3.46 billion
Total	38,630	$	29.02	38,630	—	$3.46 billion

(a)

The shares reported in this column represent purchases settled during the three months ended September 30, 2012 relating to (a) our purchases of shares in open-market transactions to meet our obligations under employee stock compensation 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.

(b)

On April 26, 2007, we publicly announced an increase in our common stock purchase program from $2 billion to $6 billion, as authorized by our board of directors on April 25, 2007. The $6 billion common stock purchase program has no expiration date. On February 28, 2008, we announced that our board of directors approved a $3 billion common stock purchase program. This program is in addition to the $6 billion program. This $3 billion program has no expiration date.

Item 6. Exhibits



Exhibit No.	Description

12.01	Statements of Computations of Ratios of Earnings to Fixed Charges.

31.01	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer.

31.02	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer.

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

101	Interactive Data Files

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SIGNATURE

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




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

Date: November 6, 2012