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, 2011~~March 31, 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 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, 2011~~April 30, 2012 was ~~559,726,988~~552,872,012.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

INDEX




	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of ~~September 30, 2011~~March 31, 2012 and December 31, ~~2010~~2011	3
Consolidated Statements of Income for the Three ~~and Nine~~ Months Ended March 31~~September 30, 2011~~, 2012 and ~~2010~~2011	4
~~Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010~~	5
Consolidated Statements of Comprehensive Income for the Three ~~and Nine~~ Months Ended ~~September 30, 2011~~March 31, 2012 and ~~2010~~2011	5
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011	6
Condensed Notes to Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	3834
Item 3. Quantitative and Qualitative Disclosures About Market Risk	6450
Item 4. Controls and Procedures	6652
PART II – OTHER INFORMATION
Item 1. Legal Proceedings	6753
Item 1A. Risk Factors	6753
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	6854
Item 6. Exhibits	6854
SIGNATURE	6955

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Par Value)


	September 30, 2011			December 31, 2010			March 31, 2012			December 31, 2011
	(Unaudited)						(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	2,829		$	3,334		$	1,559		$	1,024
Receivables, net	7,509			4,583			7,418			8,706
Inventories	5,164			4,947			6,145			5,623
Income taxes receivable	5			343			226			212
Deferred income taxes	254			190			358			283
Prepaid expenses and other	109			121			118			124
Total current assets	15,870			13,518			15,824			15,972
Property, plant and equipment, at cost	31,066			28,921			32,253			32,253
Accumulated depreciation	(6,847		)	(6,252		)	(7,098		)	(7,076		)
Property, plant and equipment, net	24,219			22,669			25,155			25,177
Intangible assets, net	251			224			227			227
Deferred charges and other assets, net	1,343			1,210			1,428			1,407
Total assets	$	41,683		$	37,621		$	42,634		$	42,783
LIABILITIES AND EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	867		$	822		$	1,143		$	1,009
Accounts payable	8,520			6,441			9,941			9,472
Accrued expenses	785			590			483			595
Taxes other than income taxes	1,053			671			1,294			1,264
Income taxes payable	136			3			26			119
Deferred income taxes	322			257			189			249
Total current liabilities	11,683			8,784			13,076			12,708
Debt and capital lease obligations, less current portion	6,781			7,515			6,460			6,732
Deferred income taxes	4,942			4,530			5,210			5,017
Other long-term liabilities	1,607			1,767			1,896			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			7			7
Additional paid-in capital	7,559			7,704			7,479			7,486
Treasury stock, at cost; 114,855,199 and 105,113,545 common shares	(6,491		)	(6,462		)
Treasury stock, at cost; 120,526,015 and 116,689,450 common shares							(6,542		)	(6,475		)
Retained earnings	15,347			13,388			14,794			15,309
Accumulated other comprehensive income	232			388			221			96
Total Valero Energy Corporation stockholders’ equity	16,654			15,025			15,959			16,423
Noncontrolling interests	16			—
Noncontrolling interest							33			22
Total equity	16,670			15,025			15,992			16,445
Total liabilities and equity	$	41,683		$	37,621		$	42,634		$	42,783

See Condensed Notes to Consolidated Financial Statements.

Table of Contents

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Millions of Dollars, Except Per Share Amounts)

(Unaudited)



	Three Months Ended March 31,
	2012			2011
Operating revenues (a)	$	35,167		$	26,308
Costs and expenses:
Cost of sales	33,035			24,568
Operating expenses:
Refining	964			744
Retail	166			162
Ethanol	87			95
General and administrative expenses	164			130
Depreciation and amortization expense	384			365
Asset impairment loss	611			—
Total costs and expenses	35,411			26,064
Operating income (loss)	(244		)	244
Other income, net	6			17
Interest and debt expense, net of capitalized interest	(99		)	(117		)
Income (loss) from continuing operations before income tax expense	(337		)	144
Income tax expense	95			40
Income (loss) from continuing operations	(432		)	104
Loss from discontinued operations, net of income taxes	—			(6		)
Net income (loss)	(432		)	98
Less: Net loss attributable to noncontrolling interests	—			—
Net income (loss) attributable to Valero Energy Corporation stockholders	$	(432	)	$	98
Net income (loss) attributable to Valero Energy Corporation stockholders:
Continuing operations	$	(432	)	$	104
Discontinued operations	—			(6		)
Total	$	(432	)	$	98
Earnings per common share:
Continuing operations	$	(0.78	)	$	0.18
Discontinued operations	—			(0.01		)
Total	$	(0.78	)	$	0.17
Weighted-average common shares outstanding (in millions)	551			566
Earnings per common share – assuming dilution:
Continuing operations	$	(0.78	)	$	0.18
Discontinued operations	—			(0.01		)
Total	$	(0.78	)	$	0.17
Weighted-average common shares outstanding – assuming dilution (in millions)	551			573
Dividends per common share	$	0.15		$	0.05

Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010
Operating revenues (a) $ 33,713
$ 21,015
$ 91,314
$ 60,069
Costs and expenses:
Cost of sales 30,033
18,915
82,981
54,198
Operating expenses:
Refining 870
753
2,427
2,210
Retail 177
169
508
484
Ethanol 103
96
302
267
General and administrative expenses 161
139
442
367
Depreciation and amortization expense 390
353
1,141
1,043
Asset impairment loss —
—
—
2
Total costs and expenses 31,734
20,425
87,801
58,571
Operating income 1,979
590
3,513
1,498
Other income, net 1
17
28
29
Interest and debt expense, net of capitalized interest (88 ) (119 ) (312 ) (363 )
Income from continuing operations before income tax expense 1,892
488
3,229
1,164
Income tax expense 689
185
1,178
421
Income from continuing operations 1,203
303
2,051
743
Income (loss) from discontinued operations, net of income taxes —
(11 ) (7 ) 19
Net income 1,203
292
2,044
762
Less: Net loss attributable to noncontrolling interests —
—
(1 ) —
Net income attributable to Valero Energy Corporation stockholders $ 1,203
$ 292
$ 2,045
$ 762
Net income attributable to Valero Energy Corporation stockholders:
Continuing operations $ 1,203
$ 303
$ 2,052
$ 743
Discontinued operations —
(11 ) (7 ) 19
Total $ 1,203
$ 292
$ 2,045
$ 762
Earnings per common share:
Continuing operations $ 2.12
$ 0.54
$ 3.61
$ 1.31
Discontinued operations —
(0.02 ) (0.01 ) 0.03
Total $ 2.12
$ 0.52
$ 3.60
$ 1.34
Weighted-average common shares outstanding (in millions) 564
564
566
563
Earnings per common share – assuming dilution:
Continuing operations $ 2.11
$ 0.53
$ 3.59
$ 1.31
Discontinued operations —
(0.02 ) (0.01 ) 0.03
Total $ 2.11
$ 0.51
$ 3.58
$ 1.34
Weighted-average common shares outstanding –
assuming dilution (in millions)
569
568
572
567
Dividends per common share $ 0.05
$ 0.05
$ 0.15
$ 0.15



Supplemental information:
(a) Includes excise taxes on sales by our U.S. retail system	$	234	$	214

Supplemental information:
(a) Includes excise taxes on sales by our U.S. retail system $ 229
$ 234
$ 670
$ 667

See Condensed Notes to Consolidated Financial Statements.

Table of Contents

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF ~~CASH FLOWS~~COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)

Nine Months Ended
September 30,
2011 2010
Cash flows from operating activities:
Net income $ 2,044
$ 762
Adjustments to reconcile net income to net cash provided by
operating activities:

Depreciation and amortization expense 1,141
1,096
Noncash interest expense and other income, net 20
8
Asset impairment loss —
2
Gain on sale of Delaware City Refinery assets —
(92 )
Stock-based compensation expense 34
32
Deferred income tax expense 393
285
Changes in current assets and current liabilities 840
592
Changes in deferred charges and credits and other operating activities, net (144 ) (63 )
Net cash provided by operating activities 4,328
2,622
Cash flows from investing activities:
Capital expenditures (1,584 ) (1,226 )
Deferred turnaround and catalyst costs (501 ) (410 )
Acquisition of Pembroke Refinery, net of cash acquired (1,675 ) —
Acquisition of pipeline and terminal facilities (37 ) —
Acquisitions of ethanol plants —
(260 )
Proceeds from sale of the Delaware City Refinery assets and
associated terminal and pipeline assets
—
220
Other investing activities, net (24 ) 15
Net cash used in investing activities (3,821 ) (1,661 )
Cash flows from financing activities:
Non-bank debt:
Borrowings —
1,244
Repayments (718 ) (517 )
Accounts receivable sales program:
Proceeds from the sale of receivables —
1,225
Repayments —
(1,325 )
Purchase of common stock for treasury (270 ) (2 )
Issuance of common stock in connection with stock-based compensation plans 42
12
Common stock dividends (85 ) (85 )
Debt issuance costs —
(10 )
Contributions from noncontrolling interests 12
—
Other financing activities, net 17
5
Net cash provided by (used in) financing activities (1,002 ) 547
Effect of foreign exchange rate changes on cash (10 ) 19
Net increase (decrease) in cash and temporary cash investments (505 ) 1,527
Cash and temporary cash investments at beginning of period 3,334
825
Cash and temporary cash investments at end of period $ 2,829
$ 2,352



	Three Months Ended March 31,
	2012			2011
Comprehensive income (loss)	$	(307	)	$	189

See Condensed Notes to Consolidated Financial Statements.

Table of Contents

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF ~~COMPREHENSIVE INCOME~~CASH FLOWS

(Millions of Dollars)

(Unaudited)

Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010
Net income $ 1,203
$ 292
$ 2,044
$ 762
Other comprehensive income (loss):
Foreign currency translation adjustment (278 ) 100
(166 ) 63
Pension and other postretirement benefits:
Net loss arising during the period,
  net of income tax benefit of $-, $-, $-, and $-
—
—
—
(21 )
Net gain reclassified into income,
  net of income tax expense of $1, $2, $2, and $2
(1 ) (2 ) (3 ) (4 )
Net loss on pension and other
  postretirement benefits
(1 ) (2 ) (3 ) (25 )

Derivative instruments designated and
  qualifying as cash flow hedges:

Net gain (loss) arising during the period,
  net of income tax (expense) benefit of
  $(7), $-, $(7), and $1
13
—
13
(1 )
Net gain reclassified into income,
  net of income tax expense of $-, $13, $-, and $47
—
(24 ) —
(88 )
Net gain (loss) on cash flow hedges 13
(24 ) 13
(89 )
Other comprehensive income (loss) (266 ) 74
(156 ) (51 )
Comprehensive income 937
366
1,888
711
Less: Comprehensive loss attributable to
  noncontrolling interests
—
—
(1 ) —
Comprehensive income attributable to
  Valero Energy Corporation stockholders
$ 937
$ 366
$ 1,889
$ 711



	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities:
Net income (loss)	$	(432	)	$	98
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	384			365
Asset impairment loss	611			—
Noncash interest expense and other income, net	7			7
Stock-based compensation expense	10			12
Deferred income tax expense (benefit)	61			(44		)
Changes in current assets and current liabilities	1,063			1,603
Changes in deferred charges and credits and other operating activities, net	—			17
Net cash provided by operating activities	1,704			2,058
Cash flows from investing activities:
Capital expenditures	(726		)	(438		)
Deferred turnaround and catalyst costs	(158		)	(299		)
Advance payment related to acquisition of Pembroke Refinery	—			(37		)
Other investing activities, net	10			(9		)
Net cash used in investing activities	(874		)	(783		)
Cash flows from financing activities:
Non-bank debt:
Repayments	—			(510		)
Accounts receivable sales program:
Repayments	(150		)	—
Purchase of common stock for treasury	(106		)	—
Proceeds from the exercise of stock options	9			21
Common stock dividends	(83		)	(28		)
Contributions from noncontrolling interest	11			—
Other financing activities, net	—			5
Net cash used in financing activities	(319		)	(512		)
Effect of foreign exchange rate changes on cash	24			36
Net increase in cash and temporary cash investments	535			799
Cash and temporary cash investments at beginning of period	1,024			3,334
Cash and temporary cash investments at end of period	$	1,559		$	4,133

See Condensed Notes to Consolidated Financial Statements.

Table of Contents

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

General

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

These unaudited ~~consolidated~~ financial statements 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 ~~consolidated~~ financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the ~~three and~~ ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012 and ~~2010~~2011 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited ~~consolidated~~ financial statements. Operating results for the ~~three and~~ ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2011.~~2012.

The ~~consolidated~~ balance sheet as of December 31, ~~2010~~2011 has been derived from our audited financial statements as of that date. For further information, refer to our ~~consolidated~~ financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, ~~2010~~2011.

~~We have evaluated subsequent events that occurred after~~ ~~September 30, 2011~~ ~~through the filing of this Form 10-Q. Any material subsequent events that occurred during this time have been properly recognized or disclosed in these financial statements.~~

~~Noncontrolling Interests~~

~~In connection with the acquisition of the Pembroke Refinery (see further discussion in Note 2), we acquired an~~ ~~85 percent~~ ~~interest in Mainline Pipelines Limited (MLP). MLP owns a pipeline that distributes refined products from the Pembroke Refinery to terminals in the United Kingdom.~~

On ~~January 21, 2011~~, we entered into a joint venture agreement with Darling Green Energy LLC, a subsidiary of Darling International, Inc., to form Diamond Green Diesel Holdings LLC (DGD Holdings). DGD Holdings, through its wholly owned subsidiary, Diamond Green Diesel LLC (DGD), will construct and operate a biomass-based diesel plant having a design feed capacity of ~~10,000~~ barrels per day that will process animal fats, used cooking oils, and other vegetable oils into renewable green diesel. The plant will be located next to our St. Charles Refinery. The aggregate cost of this facility is estimated to be approximately ~~$368 million~~ and the construction is expected to be completed in late 2012. The joint venture agreement requires that contributions be made to DGD Holdings based on the percentage of units held by each member, which is currently on a ~~50/50~~ ~~basis. In addition, on~~ ~~May 31, 2011, we agreed to lend DGD up to~~ ~~$221 million~~ ~~in order to finance~~ ~~60 percent~~ ~~of the construction costs of the plant.~~

Because of our controlling financial interests in MLP and DGD Holdings, we have included the financial statements of MLP and DGD Holdings in these consolidated financial statements and have separately disclosed the related noncontrolling interests.

~~Table of Contents~~

~~VALERO ENERGY CORPORATION AND SUBSIDIARIES~~

~~CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued~~)

Significant Accounting Policies

~~Reclassifications~~

As discussed in Note 2, we sold our Paulsboro Refinery in December 2010. As a result, the results of operations of the Paulsboro Refinery have been reclassified to discontinued operations for the three and ~~nine~~ ~~months ended~~ ~~September 30, 2010~~.

In addition, credit card fees previously recognized in 2010 in retail operating expenses have been reclassified to cost of sales as such fees are directly and jointly related to the sale transaction. This reclassification resulted in an increase in cost of sales and a decrease in retail operating expenses of ~~$23 million~~ ~~and~~ ~~$68 million~~ ~~for the three and~~ ~~nine months ended September 30,2010, respectively.~~

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 ~~consolidated~~ financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, we review our estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

~~New Accounting Pronouncements~~Comprehensive Income

~~In June 2011,~~Effective January 1, 2012, we adopted the provisions of Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” ~~were amended to allow an entity the option~~and have elected to present the total offor comprehensive income in a statement that is separate from the ~~components~~statement of income but placed directly after the statement of income.

Comprehensive income (loss) for the three months ended March 31,2012 and 2011 of $(307) million and $189 million, respectively, differs from net income (loss) of $(432) million and $98 million, respectively, primarily due to the foreign currency translation adjustments recorded in the respective quarter related to our investments in subsidiaries in Canada and the ~~components~~United Kingdom (U.K.).

Fair Value Measurements

Effective January 1, 2012, we adopted the provisions of ~~other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In both choices,~~ASC Topic 820, “Fair Value Measurement,” which clarified the ~~entity is required to present reclassification adjustments on the face~~application of the financial statements for items that are reclassified from other comprehensive income to net income in the statement where those components are presented. These provisions are effective for the first interim or annual period beginning after December 15, 2011,existing fair value measurement requirements and ~~are to be applied retrospectively, with early adoption permitted.~~changed certain fair value measurement and disclosure requirements. The adoption of ~~this guidance effective January 1, 2012 will~~these provisions did not affect our financial position or results of operations ~~because~~as these requirements only ~~affect disclosures.~~affected disclosures as reflected in Note 12.

In May 2011, the provisions of ASC Topic 820, “Fair Value Measurement,” were amended to clarify the application of existing fair value measurement requirements and to change certain fair value measurement and disclosure requirements. Amendments that change measurement and disclosure requirements relate to (i) fair value measurement of financial instruments that are managed within a portfolio, (ii) application of premiums and discounts in a fair value measurement, and (iii) additional disclosures about fair value measurements categorized within Level 3 of the fair value hierarchy. These provisions are effective for the first interim or annual period beginning after December 15, 2011. The adoption of this guidance effective January 1, 2012 will not affect our financial position or results of operations, but may result in additional disclosures.

In January 2011, the provisions of ASC Topic 310, “Receivables,” were amended to delay temporarily the effective date of disclosures relating to troubled debt restructurings, which were previously amended in July 2010, in order to allow the Financial Accounting Standards Board time to complete its deliberations on what constitutes a troubled debt restructuring. In April 2011, the provisions of ASC Topic 310 were amended to clarify the guidance on a creditor’s evaluations of whether it has granted a concession to the debtor and whether the debtor is experiencing financial difficulties. These provisions are effective for the first interim

Table of Contents

VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

orNew 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 ~~period~~reporting periods beginning on ~~or after June 15, 2011. The new guidance should be applied retrospectively to restructurings occurring on or after the beginning of the annual period of adoption, with early adoption permitted.~~January 1, 2013. The adoption of this guidance effective ~~July~~January 1, ~~2011 did~~2013 will not affect our financial position or results of ~~operations.~~operations, but may result in additional disclosures.


2.	ACQUISITIONS ~~AND DISPOSITIONS~~

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, ~~including inventories of~~ ~~$261 million, from Murphy Oil Corporation, with the total purchase price~~which was funded from available cash. ~~We expect to receive a favorable adjustment related to inventories in~~In the fourth quarter of 2011, we recorded an adjustment related to inventories acquired that ~~will reduce~~reduced the purchase price ~~by approximately~~to $40547 million. The ~~Meraux Refinery has a total throughput capacity of~~ ~~135,000~~ ~~barrels per day and is located in Meraux, Louisiana. This acquisition is referred to as the Meraux Acquisition.~~

~~The Meraux Acquisition is consistent with our general business strategy and complements our existing refining and marketing network.~~

~~A determination of the acquisition-date fair values of the~~ assets acquired and ~~the~~ 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 ~~Meraux Acquisition is pending~~year ended December 31, 2011, and no adjustments to those estimated amounts have been made during the three months ended March 31,2012. We are, however, awaiting the completion of an independent appraisal and other ~~evaluations. Disclosure~~evaluations of ~~pro forma information for~~ the ~~Meraux Acquisition for~~fair values of the ~~three~~assets acquired and ~~nine months ended September 30,~~ ~~2011 and 2010 is impracticable as historical financial information is not readily available at this time.~~liabilities assumed.

Pembroke Acquisition

On August 1, 2011, we acquired 100 percent of the outstanding shares of Chevron Limited from a subsidiary of Chevron Corporation (Chevron), and we subsequently changed the name of Chevron Limited to Valero Energy Ltd. ~~Valero Energy Ltd owns and operates the Pembroke Refinery, which has a total throughput capacity of approximately~~ ~~270,000~~ barrels per day and is located in Wales, United Kingdom. Valero Energy Ltd also owns, directly and through various subsidiaries, an extensive network of marketing and logistics assets throughout the United Kingdom and Ireland. On the acquisition date, we initially paid $1.8 billion from available cash, of which $1.1 billion was for working capital. ~~Subsequent~~In the fourth quarter of 2011, we recorded adjustments to ~~the acquisition date, the amounts paid have been favorably adjusted for~~ working capital ~~true-up adjustments~~ (primarily inventory), ~~with~~resulting in an adjusted purchase price of $~~1.675~~1.7 billion,. The assets acquired and liabilities assumed in this acquisition were recognized at their acquisition-date estimated fair values, as ~~outlined below.~~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 three months ended March 31,2012. We ~~expect final settlement by year end.~~are, however, awaiting the completion of an independent appraisal and other evaluations of the fair values of the assets acquired and liabilities assumed. This acquisition is referred to as the Pembroke Acquisition.

~~The Pembroke Acquisition is consistent with our general business strategy and broadens the geographic diversity of our refining and marketing network.~~

~~Table of Contents~~

~~VALERO ENERGY CORPORATION AND SUBSIDIARIES~~

~~CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued~~)

The purchase price for the Pembroke Acquisition has been preliminarily allocated based on estimated fair values of the assets acquired and liabilities assumed at the acquisition date, pending the completion of an independent appraisal and other evaluations. The preliminary purchase price allocation as of September 30, 2011 was as follows (in millions):

Current assets, net of cash acquired $ 2,217
Property, plant and equipment 777
Deferred charges and other assets 17
Intangible assets 50
Current liabilities, less current portion of debt
and capital lease obligations
(1,294 )
Debt and capital leases assumed, including current portion (12 )
Other long-term liabilities (77 )
Noncontrolling interest (3 )
Purchase price, net of cash acquired $ 1,675

~~The acquired intangible assets are subject to amortization and have preliminary estimated useful lives of~~ 15 ~~years. These acquired intangible assets have been preliminarily assigned to the major intangible asset classes of royalties and licenses and wholesale dealer agreements.~~

~~During the three and~~ ~~nine months ended September 30,~~ ~~2011, we recognized~~ ~~$18 million~~ ~~and~~ ~~$23 million, respectively, of costs related to the Pembroke Acquisition. These costs were expensed and are included in general and administrative expenses.~~

Our consolidated statements of income include the results of operations of the Pembroke Acquisition commencing on August 1, 2011. The operating revenues and income from continuing operations associated with the Pembroke Acquisition included in our consolidated statements of income for the three and ~~nine months ended September 30,~~ ~~2011, were as follows (in millions):~~

Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010
Operating revenues $ 3,028
N/A $ 3,028
N/A
Income from continuing operations 19
N/A 19
N/A

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~~CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued~~)

The following pro forma financial information (in millions, except per share amounts) presents our consolidated results assuming the Pembroke Acquisition occurred on January 1, 2010. The pro forma financial information is not necessarily indicative of the results of future operations.

Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010
Operating revenues $ 35,491
$ 24,594
$ 103,030
$ 70,638
Income from continuing operations
  attributable to Valero stockholders
1,196
306
1,941
767
Earnings per common share from
  continuing operations – basic
2.11
0.54
3.41
1.36
Earnings per common share from
  continuing operations – assuming dilution
2.10
0.54
3.39
1.35

~~Acquisition of Pipeline and Terminal Facilities~~

~~In June 2011, we acquired~~ ~~two~~ product terminal facilities in Louisville and Lexington, Kentucky and a minority interest in the LouLex Pipeline system, which connects the terminal facilities, from a subsidiary of Chevron for cash consideration of ~~$37 million. These assets provide storage and distribution facilities for our wholesale marketing business in eastern Kentucky, which is supplied primarily by our Memphis Refinery.~~

~~Because this acquisition was not material to our results of operations, we have not presented actual results of operations for this acquisition from the acquisition date through~~ ~~September 30, 2011~~ ~~or pro forma results of operations for the three and~~ ~~nine months ended September 30,2011~~ ~~and~~ ~~2010. The consolidated statements of income for the three and~~ ~~nine~~ ~~months ended~~ ~~September 30, 2011~~ ~~include the results of this acquisition from its acquisition date.~~

~~Acquisitions of Ethanol Plants~~

~~In December 2009, we signed an agreement with ASA Ethanol Holdings, LLC to buy~~ ~~two~~ ~~ethanol plants located in Linden, Indiana and Bloomingburg, Ohio and made a~~ ~~$20 million~~ ~~advance payment towards the acquisition of these plants. In January 2010, we completed the acquisition of these plants, including certain inventories, for total consideration of~~ ~~$202 million~~.

~~Also in December 2009, we received approval from a bankruptcy court to acquire~~ an ~~ethanol plant located near Jefferson, Wisconsin from Renew Energy LLC and made a~~ ~~$1 million~~ ~~advance payment towards the acquisition of this plant. We completed the acquisition of this plant, including certain receivables and inventories, in February 2010 for total consideration of~~ ~~$79 million~~.

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~~Disposition of Paulsboro Refinery~~

In ~~December 2010, we sold our Paulsboro Refinery to PBF Holding Company LLC (PBF Holding) for total proceeds of~~ ~~$707 million, including~~ ~~$361 million~~ ~~from the sale of working capital, resulting in a pre-tax loss of~~ ~~$980 million~~ (~~$610 million~~ ~~after taxes). The sale proceeds consisted of~~ ~~$547 million~~ ~~of cash and a~~ ~~$160 million~~ ~~note secured by the Paulsboro Refinery. The note matures in~~ ~~December 2011~~ ~~and bears interest at~~ ~~LIBOR plus 700 basis points. PBF Holding has the option to extend the note for six months; however, the interest rate for the additional six months will be~~ ~~LIBOR plus 900 basis points~~.

~~The results of operations of the Paulsboro Refinery are reflected in discontinued operations, and selected results prior to its sale are shown below (in millions).~~

Three Months Ended
September 30, 2010 Nine Months Ended
September 30, 2010
Operating revenues $ 1,195
$ 3,559
Loss before income taxes (18 ) (36 )

~~Disposition of Delaware City Refinery Assets and Associated Terminal and Pipeline Assets~~

In ~~June 2010, we sold our shutdown Delaware City Refinery assets and associated terminal and pipeline assets to wholly owned subsidiaries of PBF Energy Partners LP (PBF) for~~ ~~$220 million~~ ~~of cash proceeds. The sale resulted in a gain of~~ ~~$92 million~~ (~~$58 million~~ ~~after taxes) related to the shutdown refinery assets and a gain of~~ ~~$3 million~~ related to the terminal and pipeline assets. The gain on the sale of the shutdown refinery assets resulted from the proceeds we received for the scrap value of the assets and the reversal of certain liabilities recorded in the fourth quarter of 2009 associated with the shutdown of the refinery, which we did not incur because of the sale, and this gain is presented in discontinued operations for the ~~nine~~ ~~months ended~~ ~~September 30, 2010~~.

~~Results of operations of the Delaware City Refinery are reflected in discontinued operations, and selected results prior to its sale, excluding the gain on the sale, are shown below (in millions):~~



	~~Three Months Ended~~ ~~September 30, 2010~~		~~Nine Months Ended~~ ~~September 30, 2010~~
~~Operating revenues~~	$	—	$	—
~~Loss before income taxes~~	—		~~(33~~		)

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3.	IMPAIRMENT ~~ANALYSIS~~

In late 2008, the U.S. and worldwide economies experienced severe disruptions in their capital and commodities markets resulting in a significant slowdown that persisted throughout 2009. This slowdown negatively impacted refining industry fundamentals and the demand and price for our refined products. Because of this negative impact,March 2012, we decided to ~~shut down our~~suspend the operations of the Aruba Refinery ~~temporarily in July 2009, and it remained shut until~~ ~~January 2011. We restarted our Aruba Refinery due~~by the end of March. Our decision was based on the refinery’s inability to ~~improvements in the U.S. and worldwide economies and the resulting improvement in refining industry fundamentals; however, we analyzed our Aruba Refinery for potential impairment as of~~ ~~September 30, 2011~~ ~~because of its recent temporary shutdown, its negative operating~~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 narrowed significantly in the fourth quarter of 2011. We considered the use of alternative feedstocks or configuration changes that might improve the refinery’s cash flows and ~~our decision in July 2011 to renew our exploration~~we also considered a temporary or permanent shutdown of ~~strategic alternatives for~~ the refinery ~~which may include~~facilities. We ultimately decided to shut down the ~~sale~~refinery and to maintain it in a state that would allow for operations to be resumed.

On March 28, 2012, we received a non-binding indication of interest from an unrelated interested party to purchase the Aruba Refinery for $350 million, plus working capital as of the closing date, subject to completion of due diligence and further negotiations. The due diligence process is currently ongoing and no final agreement has been reached to sell the refinery. We ~~considered these matters in~~have accepted this offer, subject to the finalization of the purchase and sale agreement. The Aruba Refinery is classified as “held and used” because all of the accounting criteria required for “held for sale” classification have not been met.

Because of our decision to suspend the operations of the Aruba Refinery and the possibility that we may sell the refinery, we evaluated the refinery for potential impairment ~~analysis~~ and concluded that ~~our~~the Aruba Refinery was ~~not~~ impaired as of ~~September 30, 2011~~March 31, 2012. ~~Our future cash flow estimates for~~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 described above, which was based on the interested party’s specific knowledge of the refinery, ~~are based on our expectation that refining industry fundamentals will continue to improve in connection with an increase~~experience in the ~~demand~~refining and marketing industry, and extensive knowledge of the current economic factors of our business. 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.

There is no certainty that we will sell the refinery to the interested party, or to any other party, and if we ultimately sell the refinery, there is no certainty that we will sell it for ~~refined products. Should refining industry fundamentals fail to continue to improve or~~$350 million. In addition, should we ~~decide~~be unable to sell the refinery, ~~our future cash flow estimates~~we may ~~be negatively impacted and we could ultimately determine that the refinery is impaired. The Aruba Refinery had a net book value of~~ ~~$950 million~~ ~~as of~~ ~~September 30, 2011; therefore,~~have to recognize an additional asset impairment ~~loss could be material to our results of operations.~~


4.	~~INVENTORIES~~

~~Inventories consisted of the following (in millions):~~

September 30,
2011 December 31,
2010
Refinery feedstocks $ 2,502
$ 2,225
Refined products and blendstocks 2,217
2,233
Ethanol feedstocks and products 130
201
Convenience store merchandise 102
101
Materials and supplies 213
187
Inventories $ 5,164
$ 4,947

~~As of~~ ~~September 30, 2011~~ ~~and~~ ~~December 31, 2010, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately~~ ~~$7.1 billion~~ ~~and~~ ~~$6.1 billion, respectively.~~loss.

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4.	INVENTORIES

Inventories consisted of the following (in millions):



	March 31, 2012		December 31, 2011
Refinery feedstocks	$	2,730	$	2,474
Refined products and blendstocks	2,862		2,633
Ethanol feedstocks and products	236		195
Convenience store merchandise	98		103
Materials and supplies	219		218
Inventories	$	6,145	$	5,623

As of March 31, 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~~In March 2012, we exercised the call provisions on our Series 1997 ~~nine months ended September 30,2011~~5.6%, ~~the following activity occurred related to our non-bank debt:~~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 May 2011, we made a scheduled debt repayment of~~ ~~$200 million~~ ~~related to our~~ ~~6.125%~~ ~~senior notes;~~

inIn April ~~2011,~~2012, we made scheduled debt repayments of $84 million related to our Series A1997A 5.45%~~, Series B~~ ~~5.40%, and Series C~~ ~~5.40%~~ industrial revenue ~~bonds;~~bonds and $750 million related to our 6.875% notes.

During the three months ended March 31,2011, the following activity occurred:

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

in February 2011, we paid $300 million to acquire the Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds), which were subject to mandatory tender. We expect to hold the GO Zone Bonds for our own account until conditions permit the remarketing of these bonds at an interest rate acceptable to us.

~~During the~~ ~~nine months ended September 30,2010, the following activity occurred related to our non-bank debt:~~

~~in June 2010, we made a scheduled debt repayment of~~ ~~$25 million~~ ~~related to our~~ ~~7.25%~~ ~~debentures;~~

~~in May 2010, we redeemed our~~ ~~6.75%~~ ~~senior notes with a maturity date of~~ ~~May 1, 2014~~ ~~for~~ ~~$190 million, or~~ ~~102.25%~~ ~~of stated value;~~

~~in April 2010, we made scheduled debt repayments of~~ ~~$8 million~~ ~~related to our Series A~~ ~~5.45%, Series B~~ ~~5.40%, and Series C~~ ~~5.40%~~ ~~industrial revenue bonds;~~

~~in March 2010, we redeemed our~~ ~~7.50%~~ ~~senior notes with a maturity date of~~ ~~June 15, 2015~~ ~~for~~ ~~$294 million, or~~ ~~102.5%~~ ~~of stated value; and~~

~~in February 2010, we issued~~ ~~$400 million~~ of ~~4.50%~~ ~~notes due in~~ ~~February 2015~~ ~~and~~ ~~$850 million~~ of ~~6.125%~~ ~~notes due in~~ ~~February 2020~~ ~~for total net proceeds of~~ ~~$1.2 billion~~.

Bank Debt and Credit Facilities

We have a $~~2.4~~3 billion revolving credit facility (the Revolver) that has a maturity date of ~~November 2012~~December 2016. The Revolver has certain restrictive covenants, including a maximum debt-to-capitalization ratio of 60 percent. As of ~~September 30, 2011~~March 31, 2012 and December 31, ~~2010~~2011, our debt-to-capitalization ~~ratio,~~ratios, calculated in accordance with the terms of the Revolver, ~~was~~were 2227 percent and 2529 percent, respectively. We believe that we will remain in compliance with this covenant.

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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~~three months ended ~~September 30, 2011~~March 31, 2012 and ~~2010~~2011, we had no borrowings or repayments under our Revolver or the Canadian revolving credit facility. As of ~~September 30, 2011~~March 31, 2012 and December 31, ~~2010~~2011, we had no borrowings outstanding under the Revolver or the Canadian revolving credit facility.

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~~CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued~~)

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


			Amounts Outstanding					Amounts Outstanding
	Borrowing Capacity	Expiration	September 30, 2011	December 31, 2010	Borrowing Capacity		Expiration	March 31, 2012		December 31, 2011
Letter of credit facility	$200	June 2012	$—	$—
Letter of credit facility	$300	June 2012	$300	$100
Letter of credit facilities					$	500	June 2012	$	500	$	300
Revolver	$2,400	November 2012	$74	$399	$	3,000	December 2016	$	153	$	119
Canadian revolving credit facility	C$115	December 2012	C$20	C$20	C$	115	December 2012	C$	20	C$	20

As of ~~September 30, 2011~~March 31, 2012 and December 31, ~~2010~~2011, we had $~~346~~456 million and $~~176~~391 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities.

~~In connection with the Pembroke Acquisition, we assumed a~~ ~~€2.8 million~~ ~~short-term demand loan, which bears interest at EURIBOR plus a margin. We expect to repay the loan on or before~~ ~~February 2012~~.

Accounts Receivable Sales Facility

We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables. ~~We amended our agreement~~The facility matures in ~~June 2011 to extend the maturity date to~~ June 2012. ~~As of~~ ~~September 30, 2011~~ ~~and~~ ~~December 31, 2010, the amount of eligible receivables sold was~~ ~~$100 million. There were no sales or repayments of eligible receivables during the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2011. During the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2010, we sold~~ ~~$1.2 billion~~ ~~of eligible receivables and repaid~~ ~~$1.3 billion~~ ~~to the third-party entities and financial institutions.~~ Proceeds from the sale of receivables under this facility are reflected as debt. Changes in the amounts outstanding under our accounts receivable sales facility were as follows (in millions):



	Three Months Ended March 31,
	2012			2011
Balance as of beginning of period	$	250		$	100
Proceeds from the sale of receivables	—			—
Repayments	(150		)	—
Balance as of end of period	$	100		$	100

In late April 2012, we sold $850 million of eligible receivables to the third-party entities and financial institutions under this facility, and we repaid $500 million on May 4, 2012.

Capitalized Interest

~~Capitalized~~For the three months ended March 31,2012 and 2011, capitalized interest was $4152 million and $2527 million ~~for the~~ ~~three months ended September 30,2011~~ ~~and~~ ~~2010, respectively, and~~ ~~$101 million~~ ~~and~~ ~~$67 million~~ ~~for the~~ ~~nine months ended September 30,2011~~ ~~and~~ ~~2010~~, respectively.

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6.	COMMITMENTS AND CONTINGENCIES

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). ~~According to statements by the EPA, any~~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 ~~will~~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.

~~In addition, certain~~Certain states and foreign governments have pursued ~~independent~~ regulation of greenhouse ~~gases.~~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 iswas scheduled to become effective in 2011, ~~with small reductions in~~but rulings by the ~~carbon intensity~~U.S. District Court stayed enforcement of ~~transportation fuels sold in California. The mandated reductions in carbon intensity are scheduled~~the LCFS until certain legal challenges to ~~increase through 2020, after which another step-change in reductions is anticipated. The~~the LCFS ~~is designed to encourage substitution of traditional petroleum fuels, and, over time, it is anticipated~~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).

The Ninth Circuit Court lifted the stay on April 23, 2012. We anticipate that the Ninth Circuit Court will ~~lead to~~hear arguments on the merits of the appeal this year, with a ~~greater use of electric cars and alternative fuels, such as E85, as companies seek to generate more credits to offset petroleum fuels. The~~final ruling sometime thereafter.

A California statewide cap-and-trade program will begin in ~~2013.~~late 2012. Initially, the program will apply only to stationary sources of greenhouse gases (~~e.g~~.(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.

On June 30, 2010, the EPA formally disapproved the flexible permits program submitted by the Texas Commission on Environmental Quality (TCEQ) in 1994 for inclusion in its clean-air implementation plan. The EPA determined that Texas’ flexible permit program did not meet several requirements under the federal Clean Air Act. Our Port Arthur, Texas City, Three Rivers, McKee, and Corpus Christi East and West Refineries formerly operated under flexible permits administered by the TCEQ. In the fourth quarter of 2010, we completed the conversion of our flexible permits into federally enforceable conventional state NSR permits (“de-flexed permits”). We are now in the process of incorporating these de-flexed permits into our Title V permits. Continued discussions with the TCEQ and the EPA regarding this matter are likely.

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~~Meanwhile,~~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. The regulation would require major refiners and importers of gasoline, including Valero, to install clean fuel outlets at five percent of California’s retail stations for hydrogen fueling and electric vehicle charging. 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 ~~formally~~ disapproved ~~other TCEQ~~certain permitting programs of the Texas Commission on Environmental Quality (TCEQ) that historically have streamlined the environmental permitting process in Texas. For example, the EPA ~~has~~ disapproved the TCEQ pollution control standard permit, thus requiring conventional permitting for future pollution control equipment. The Fifth Circuit Court of Appeals recently overturned the EPA’s disapproval and sent it back to the EPA to re-evaluate the decision. Litigation is pending from industry groups and others against the EPA for each of these actions. The EPA has also objected to numerous Title V permits in Texas and other states, including permits at our Port Arthur, Corpus Christi East, and McKee Refineries. Environmental activist groups have filed a notice of intent to sue the EPA, seeking to require the EPA to assume control of these permits from the TCEQ. 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. But 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 ~~federal, state, and foreign~~ income taxes, ~~and~~ transactional taxes ~~such as excise,~~(excise/duty, sales/use, 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 March 31, 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 the 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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liabilities will not be material to our financial position or results of operations.


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 ~~interests,~~interest, and total equity for the ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012 and ~~2010~~2011:


	2011									2010								2012								2011
	Valero Stockholders’ Equity			Non- controlling Interests			Total Equity			Valero Stockholders’ Equity			Non- controlling Interests		Total Equity			Valero Stockholders’ Equity			Non- controlling Interest		Total Equity			Valero Stockholders’ Equity			Non- controlling Interest		Total Equity
Balance at beginning of period	$	15,025		$	—		$	15,025		$	14,725		$	—	$	14,725		$	16,423		$	22	$	16,445		$	15,025		$	—	$	15,025
Net income (loss)	2,045			(1		)	2,044			762			—		762			(432		)	—		(432		)	98			—		98
Dividends	(85		)	—			(85		)	(85		)	—		(85		)	(83		)	—		(83		)	(28		)	—		(28		)
Stock-based compensation expense	34			—			34			32			—		32			10			—		10			12			—		12
Tax deduction in excess of stock-based compensation expense	19			—			19			7			—		7			2			—		2			5			—		5
Transactions in connection with stock-based compensation plans:
Stock issuances	42			—			42			12			—		12			9			—		9			21			—		21
Stock repurchases	(270		)	—			(270		)	(2		)	—		(2		)	(95		)	—		(95		)	—			—		—
Contributions from noncontrolling interest	—			14			14			—			—		—			—			11		11			—			—		—
Recognition of noncontrolling interest in connection with Pembroke Acquisition	—			3			3			—			—		—
Other comprehensive income (loss)	(156		)	—			(156		)	(51		)	—		(51		)
Other comprehensive income																		125			—		125			91			—		91
Balance at end of period	$	16,654		$	16		$	16,670		$	15,400		$	—	$	15,400		$	15,959		$	33	$	15,992		$	15,224		$	—	$	15,224

The noncontrolling ~~interests relate~~interest relates to the ownership ~~interests~~interest in ~~MLP and DGD~~Diamond Green Diesel Holdings LLC that ~~are~~is owned by ~~parties~~a party unrelated to ~~us, as discussed in~~ ~~Note 1~~.us.

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~~Treasury Stock~~Share Activity

~~During~~Activity in the ~~nine~~number of shares of common stock and treasury stock was as follows (in millions) for the three months ended ~~September 30,~~March 31, 2012 and 2011 ~~and 2010, we purchased~~ :~~13.6 million~~ ~~shares and~~ ~~1.6 million~~ ~~shares, respectively, of our common stock in connection with the administration of our stock-based compensation plans. During the~~ ~~nine months ended September 30,~~ ~~2011 and 2010, we issued~~ ~~3.9 million~~ ~~and~~ ~~1.6 million~~ ~~shares from treasury, respectively, for our stock-based compensation plans.~~



	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	—	1		—	2
Stock purchases	—	(5	)	—	—
Balance as of end of period	673	(121	)	673	(103	)

Common Stock Dividends

On ~~October 27, 2011~~May 3, 2012, our board of directors declared a ~~regular~~ quarterly cash dividend of $0.15 per common share payable on ~~December 14, 2011~~June 20, 2012 to holders of record at the close of business on ~~November 16, 2011~~May 23, 2012.


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~~three months ended ~~September 30,~~March 31, 2012 and 2011 ~~2011 and 2010 (in millions)~~:


	Pension Plans						Other Postretirement Benefit Plans						Pension Plans						Other Postretirement Benefit Plans
	2011			2010			2011			2010			2012			2011			2012			2011
Three months ended September 30:
Service cost	$	28		$	22		$	4		$	3		$	35		$	23		$	3		$	3
Interest cost	21			21			5			6			23			21			5			6
Expected return on plan assets	(28		)	(28		)	—			—			(31		)	(28		)	—			—
Amortization of:
Prior service cost (credit)	1			1			(6		)	(5		)	1			1			(5		)	(6		)
Net loss	3			—			—			1			8			3			—			—
Net periodic benefit cost	$	25		$	16		$	3		$	5		$	36		$	20		$	3		$	3

Nine months ended September 30:
Service cost	$	73		$	65		$	9		$	8
Interest cost	64			62			16			19
Expected return on plan assets	(84		)	(84		)	—			—
Amortization of:
Prior service cost (credit)	2			2			(17		)	(15		)
Net loss	9			1			1			3
Net periodic benefit cost	$	64		$	46		$	9		$	15

~~During~~Our anticipated contributions to our pension plans during 2012 have not changed from amounts previously disclosed in our financial statements for the year ended December 31, 2011. There were no significant contributions made to our pension plans during the ~~nine~~three months ended ~~September 30,~~March 31, ~~2011~~2012 and ~~2010~~2011~~, we contributed~~ ~~$207 million~~ ~~and~~ ~~$54 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) for the three months ended March 31, 2012 and 2011:



	2012					2011
	Restricted Stock		Common Stock			Restricted Stock		Common Stock
Earnings per common share from continuing operations:
Net income (loss) attributable to Valero stockholders from continuing operations			$	(432	)			$	104
Less dividends paid:
Common stock			83					28
Nonvested restricted stock			—					—
Undistributed earnings (loss)			$	(515	)			$	76
Weighted-average common shares outstanding	3		551			3		566
Earnings per common share from continuing operations:
Distributed earnings	$	0.15	$	0.15		$	0.05	$	0.05
Undistributed earnings	—		(0.93		)	0.13		0.13
Total earnings per common share from continuing operations	$	0.15	$	(0.78	)	$	0.18	$	0.18

Earnings per common share from continuing operations – assuming dilution:
Net income (loss) attributable to Valero stockholders from continuing operations			$	(432	)			$	104
Weighted-average common shares outstanding			551					566
Common equivalent shares:
Stock options			—					5
Performance awards and unvested restricted stock			—					2
Weighted-average common shares outstanding – assuming dilution			551					573
Earnings per common share from continuing operations – assuming dilution			$	(0.78	)			$	0.18

Three Months Ended September 30,
2011 2010

Restricted
Stock

Common
Stock

Restricted
Stock

Common
Stock
Earnings per common share from
  continuing operations:

Net income attributable to Valero stockholders
  from continuing operations
$ 1,203
$ 303
Less dividends paid:
Common stock 28
28
Nonvested restricted stock —
—
Undistributed earnings $ 1,175
$ 275

Weighted-average common shares outstanding 3
564
3
564

Earnings per common share from
  continuing operations:

Distributed earnings $ 0.05
$ 0.05
$ 0.05
$ 0.05
Undistributed earnings 2.07
2.07
0.49
0.49
Total earnings per common share from
  continuing operations
$ 2.12
$ 2.12
$ 0.54
$ 0.54

Earnings per common share from
  continuing operations – assuming dilution:

Net income attributable to Valero stockholders
  from continuing operations
$ 1,203
$ 303
Weighted-average common shares outstanding 564
564
Common equivalent shares:

Stock options 3
3
Performance awards and unvested restricted
  stock
2
1
Weighted-average common shares outstanding –
  assuming dilution
569
568
Earnings per common share from
  continuing operations – assuming dilution
$ 2.11
$ 0.53

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Nine Months Ended September 30,
2011 2010

Restricted
Stock

Common
Stock

Restricted
Stock

Common
Stock
Earnings per common share from
  continuing operations:

Net income attributable to Valero stockholders
  from continuing operations
$ 2,052
$ 743
Less dividends paid:
Common stock 85
85
Nonvested restricted stock —
—
Undistributed earnings $ 1,967
$ 658

Weighted-average common shares outstanding 3
566
3
563

Earnings per common share from
  continuing operations:

Distributed earnings $ 0.15
$ 0.15
$ 0.15
$ 0.15
Undistributed earnings 3.46
3.46
1.16
1.16
Total earnings per common share from
  continuing operations
$ 3.61
$ 3.61
$ 1.31
$ 1.31

Earnings per common share from
  continuing operations – assuming dilution:

Net income attributable to Valero stockholders
  from continuing operations
$ 2,052
$ 743
Weighted-average common shares outstanding 566
563
Common equivalent shares:
Stock options 4
3
Performance awards and unvested restricted
  stock
2
1
Weighted-average common shares outstanding –
  assuming dilution
572
567
Earnings per common share from
  continuing operations – assuming dilution
$ 3.59
$ 1.31

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~~CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued~~)

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 common equivalent shares (primarily stock options), which were excluded due to the loss from continuing operations for three months ended March 31,2012, and stock options for which the exercise prices were greater than the average market price of our common ~~stock~~shares during each respective reporting period.

Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010
Stock options 6
17
6
14



	2012	2011
Common equivalent shares	6	—
Stock options	6	6


10.	SEGMENT INFORMATION

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



	Refining			Retail		Ethanol		Corporate			Total
Three months ended March 31, 2012:
Operating revenues from external customers	$	31,150		$	2,935	$	1,082	$	—		$	35,167
Intersegment revenues	2,255			—		14		—			2,269
Operating income (loss)	(119		)	40		9		(174		)	(244		)

Three months ended March 31, 2011:
Operating revenues from external customers	22,562			2,684		1,062		—			26,308
Intersegment revenues	1,997			—		48		—			2,045
Operating income (loss)	276			66		44		(142		)	244

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

Refining Retail Ethanol Corporate Total
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

Three months ended September 30, 2010:
Operating revenues from external
  customers
17,811
2,360
844
—
21,015
Intersegment revenues 1,576
—
73
—
1,649
Operating income (loss) 590
105
47
(152 ) 590

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

Nine months ended September 30, 2010:
Operating revenues from external
  customers
51,104
6,893
2,072
—
60,069
Intersegment revenues 4,675
—
184
—
4,859
Operating income (loss) 1,479
285
139
(405 ) 1,498



	March 31, 2012		December 31, 2011
Refining	$	37,600	$	38,164
Retail	2,049		1,999
Ethanol	982		943
Corporate	2,003		1,677
Total assets	$	42,634	$	42,783

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

September 30,
2011 December 31, 2010
Refining $ 35,541
$ 30,363
Retail 1,933
1,925
Ethanol 879
953
Corporate 3,330
4,380
Total consolidated assets $ 41,683
$ 37,621


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) for the three months ended March 31, 2012 and 2011:


	Nine Months Ended September 30,
	2011			2010			2012			2011
Decrease (increase) in current assets:
Receivables, net	$	(1,963	)	$	(516	)	$	1,319		$	(1,258	)
Inventories	891			79			(471		)	622
Income taxes receivable	333			787			(14		)	(25		)
Prepaid expenses and other	12			111			6			10
Increase (decrease) in current liabilities:
Accounts payable	1,191			358			410			2,143
Accrued expenses	137			(51		)	(100		)	174
Taxes other than income taxes	99			(168		)	9			(160		)
Income taxes payable	140			(8		)	(96		)	97
Changes in current assets and current liabilities	$	840		$	592		$	1,063		$	1,603

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

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

~~the amounts shown above exclude the current assets and current liabilities acquired in connection with the the Pembroke Acquisition in August 2011 and the acquisitions of~~ ~~three~~ ~~ethanol plants in the first quarter of 2010;~~

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

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~~CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued~~)

certain differences between ~~consolidated~~ 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.

~~During the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2011, we received a noncash contribution of~~ ~~$2 million~~ ~~from the noncontrolling interest for property, plant and equipment related to DGD Holdings.~~ There were no significant noncash investing or financing activities for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2012 or 2011.

Cash flows related to interest and income taxes were as follows (in millions) for the three months ended March 31, 2012 and 2011:


	Nine Months Ended September 30,
	2011		2010			2012		2011
Interest paid in excess of amount capitalized	$	276	$	302		$	45	$	77
Income taxes paid (received), net	289		(645		)
Income taxes paid, net						142		3

Cash flows related to the discontinued operations of the Paulsboro and Delaware City Refineries have been combined with the cash flows from continuing operations within each category in the consolidated statement of cash flows for the ~~nine months ended September 30,~~ ~~2010 and are summarized as follows (in millions):~~

Cash provided by (used in) operating activities:
Paulsboro Refinery $ 42
Delaware City Refinery (76 )
Cash used in investing activities:
Paulsboro Refinery (32 )
Delaware City Refinery —

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12.	FAIR VALUE MEASUREMENTS

General

GAAP requires that certain financial instruments, such as derivative instruments, be recognized at their fair values in our ~~consolidated~~ 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 ~~consolidated~~ 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 ~~consolidated~~ 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

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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 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.

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Recurring Fair Value Measurements

The tables below present information (in millions) about our financial instruments recognized at their fair values in our ~~consolidated~~ balance sheets categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of ~~September 30, 2011~~March 31, 2012 and December 31, ~~2010~~2011.

Cash collateral deposits of $199 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 March 31, 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)							Total as of September 30, 2011			Fair Value Measurements Using
						Netting Adjustments				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 March 31, 2012
Assets:
Commodity derivative contracts	$	6,764	$	238				$	—		$	(6,734	)		$	268		$	2,310		$	162		$	—		$	(2,302	)		$	170
Physical purchase contracts	—		(81		)		—			—				(81		)	—			(36		)	—			—				(36		)
Investments of nonqualified benefit plans	81		—				11			—				92
Investments of certain benefit plans																	89			—			11			—				100
Foreign currency contracts																	1			—			—			—				1
Other investments	—		—				—			—				—			—			—			—			—				—
Liabilities:
Commodity derivative contracts	6,503		338				—			(6,734		)		107			2,145			165			—			(2,302		)		8
Nonqualified benefit plan obligations	34		—				—			—				34
RINs obligation	137		—				—			—				137
Biofuels blending obligation																	3			—			—			—				3
Obligations of certain benefit plans																	36			—			—			—				36
Foreign currency contracts																	3			—			—			—				3

Fair Value Measurements Using

Quoted
Prices in
Active
Markets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total as of
December 31,
2010

Netting
Adjustments

Assets:
Commodity derivative contracts $ 3,240
$ 489
$ —
$ (3,560 ) $ 169
Physical purchase contracts —
17
—
—
17
Investments of nonqualified benefit plans 104
—
10
—
114
Other investments —
—
—
—
—
Liabilities:
Commodity derivative contracts 3,097
502
—
(3,560 ) 39
Nonqualified benefit plan obligations 36
—
—
—
36
RINs obligation 51
—
—
—
51

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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
Obligations of certain benefit plans	34		—			—		—			34
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.

~~Nonqualified~~Investments of certain benefit ~~plan assets~~plans consist of investment securities held by trusts for the purpose of satisfying a portion of our obligations under certain U.S. nonqualified ~~defined~~ benefit ~~and nonqualified defined contribution~~ plans. The ~~nonqualified~~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. Obligations of certain benefit ~~plan obligations~~plans relate to ~~our~~certain U.S. nonqualified defined contribution plans under which our obligations to eligible employees are equal to the fair value of the assets held by those plans. ~~The nonqualified benefit plan assets~~

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

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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 are measured at fair value using a market approach based on quotations from national securities exchanges. The nonqualified benefit plan assets categorized in Level 3 of the fair value hierarchy represent insurance contracts, the fair value of which is provided by the insurer.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 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 ~~RINs~~biofuels blending obligation represents a liability for the purchase of ~~Renewable Identification Numbers (RINs)~~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. A RIN represents a serial number assigned to each gallon of biofuel produced or imported into the U.S. as required by the EPA’s Renewable Fuel Standard, which was implemented in accordance with the Energy Policy Act of 2005. The EPA sets annual quotas for the percentage of biofuels that must be blended into motor fuels consumed in the U.S., and 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 EPA’s quota. To the degree we are unable to blend at that rate, we must purchase RINs in the open market to satisfy our obligation. Our ~~RINs~~ obligation is based on our deficiency in RINs ~~deficiency~~and RTFCs and the price of ~~those RINs~~these instruments as of the balance sheet date. Our ~~RINs~~ 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.

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 months ended March 31, 2012 and 2011.



	2012				2011
	Investments of Certain Benefit Plans		Other Investments		Investments of Certain Benefit Plans		Other Investments
Balance as of beginning of period	$	11	$	—	$	10	$	—
Purchases	—		—		—		6
Total gains (losses) included in income	—		—		1		(6		)
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	$	(6	)

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Nonrecurring Fair Value Measurements

~~Cash collateral deposits~~The table below presents the fair value (in millions) of our nonfinancial assets measured on a nonrecurring basis during the three months ended March 31, 2012 and categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of March 31, 2012.



	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value as of March 31, 2012		Total Loss Recognized During the Three Months Ended March 31, 2012
Assets:
Long-lived assets of the Aruba Refinery	$	—	$	—	$	350	$	350	$	595
Cancelled capital project	—		—		2		2		16

As discussed in Note 3, we concluded that the Aruba Refinery was impaired as of ~~$228 million~~March 31, 2012 ~~and~~ ~~$403 million~~ ~~with brokers under master netting arrangements are included in~~. As a result, we were required to determine the fair value of the ~~commodity derivatives reflected in Level 1~~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 ~~September 30, 2011~~March 31, 2012 was the $350 million offer received and accepted, subject to the finalization of the purchase and sale agreement. We believe this offer represents what a market participant would pay us for the assets in their highest and best use, as more fully discussed in ~~December 31, 2010~~Note 3~~, respectively. Certain~~. The fair value of ~~our commodity derivative contracts under master netting arrangements include both asset~~the Aruba Refinery was measured using the market approach and ~~liability positions. We have elected to offset~~is categorized in Level 3 within the fair value ~~amounts~~hierarchy. The carrying value of the Aruba Refinery’s long-lived assets as of March 31, 2012 was $945 million; therefore, we recognized ~~for multiple similar derivative instruments executed~~an asset impairment loss of $595 million during the three months ended March 31, 2012.

We recognized an asset impairment loss of $16 million during the three months ended March 31,2012 related to equipment associated with a capital project that was cancelled permanently in 2009. We had written down the ~~same counterparty, including any related cash collateral asset or obligation; however,~~carrying value of this equipment to fair value ~~amounts by hierarchy level are presented~~in 2009, but we have been unable to sell the equipment. As a result, we wrote down the carrying amount of the equipment to scrap value.

There were no liabilities that were measured at fair value on a ~~gross~~nonrecurring basis induring the ~~tables above.~~

~~The following is a reconciliation of the beginning and ending balances (in millions) for fair value measurements developed using significant unobservable inputs (Level 3).~~

2011 2010

Investments of Nonqualified
Benefit
Plans

Other
Investments

Investments of
Nonqualified
Benefit
Plans

Other
Investments
Three months ended September 30:
Balance at beginning of period $ 11
$ —
$ 10
$ —
Purchases —
5
—
—
Total losses included in earnings —
(5 ) —
—
Transfers in and/or out of Level 3 —
—
—
—
Balance at end of period $ 11
$ —
$ 10
$ —
The amount of total losses included
  in earnings attributable to the change in
  unrealized losses relating to assets still
  held at end of period
$ —
$ (5 ) $ —
$ —

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

~~Nonrecurring Fair Value Measurements~~

~~As of~~ ~~September 30, 2011~~three months ended March 31, 2012 ~~and~~ ~~December 31, 2010, there~~. There were no assets or liabilities that were measured at fair value on a nonrecurring ~~basis.~~basis during the three months ended March 31, 2011.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Other Financial Instruments

Financial instruments that we recognize in our ~~consolidated~~ balance sheets at their carrying amounts include cash and temporary cash investments, receivables, payables, debt and capital lease obligations. The fair values of these financial instruments approximate their carrying amounts, except for debt as shown in the table below (in millions):


	September 30, 2011		December 31, 2010		March 31, 2012		December 31, 2011
Carrying amount (excluding capital leases)	$	7,595	$	8,300	$	7,554	$	7,690
Fair value	9,169		9,492		8,653		9,298

The fair value of our debt is determined primarily using the market approach based on quoted prices in active markets (Level 1).


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 ~~those~~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~~(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, ~~are~~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 ~~the consolidated~~our statements of cash flows for all periods presented.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, ~~futures,~~ and options. We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations. We use swaps primarily to 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.

As of ~~September 30, 2011~~March 31, 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		~~2011~~2012
Crude oil and refined products:
Futures – long		~~3,025~~10,670
Futures – short		~~16,453~~33,088
Physical ~~purchase~~ contracts –- long		~~13,428~~22,418

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, product or natural gas purchases or refined product sales at existing market prices that we deem favorable.

As of ~~September 30, 2011~~March 31, 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		~~5,241~~5,961
Swaps – short		~~5,241~~5,961
Futures – long		34,601
Futures – short		32,112
Physical contracts – short		2,489

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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 infor 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, 2011~~March 31, 2012, we had the following outstanding commodity derivative instruments that were entered into 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			Notional Contract Volumes by Year of Maturity
Derivative Instrument	2011	2012	2013	2012	2013
Crude oil and refined products:
Swaps – long	34,708	65,040	—	51,124	—
Swaps – short	33,890	65,040	—	48,424	—
Futures – long	200,076	40,388	—	55,939	—
Futures – short	192,292	41,219	—	56,511	—
Options – long	606	10	—	2	—
Options – short	600	—	—
Corn:
Futures – long	22,325	8,405	—	14,670	50
Futures – short	41,300	23,980	260	40,330	2,180
Physical purchase contracts – long	12,166	10,991	265
Physical contracts – long				16,759	2,121

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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, 2011~~March 31, 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		Notional Contract Volumes by Year of Maturity
Derivative Instrument	2011	2012	2012	2013
Crude oil and refined products:
Swaps – long	6,196	3,240	14,799	13,070
Swaps – short	6,196	3,240	14,659	13,190
Futures – long	66,365	15,868	72,215	8,050
Futures – short	66,389	15,831	74,651	5,550
Options – long			2,615	—
Options – short	75	—	2,500	—
Natural gas:
Futures – short			650	—
Corn:
Swaps - long			8,795	—
Swaps - short			9,085	—
Futures – long	5,050	—	7,720	—
Futures – short	5,050	—	7,720	—
Corn:
Swaps – long	—	1,050
Swaps – short	—	1,050
Futures – long	3,850	60
Futures – short	2,350	1,060

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. These programs are described below.

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 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. We have not entered into derivative instruments to manage this risk, but we purchase RINs and RTFCs when the price of

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

these instruments is deemed favorable. For the three months ended March 31,2012 and 2011, the cost of meeting our obligations under these compliance programs was $67 millionand $56 million, respectively, and 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. For the three months ended March 31,2012, the cost of purchasing CSO tickets to help meet our obligations under this compliance program was $2 million, and this amount was 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 March 31,2012, the cost of meeting our obligation under this compliance program was $1 million, and this amount 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 March 31, 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 March 31, 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 months ended March 31,2012, the loss recognized in income on these derivative instruments designated as economic hedges was 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 instruments outstanding as of March 31, 2012 or December 31, 2011, or during the three months ended March 31,2012 and 2011.

Foreign Currency Risk

We are exposed to exchange rate fluctuations on transactions entered into by our ~~Canadian and European~~international operations

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 2011~~March 31, 2012, we had commitments to purchase $~~475~~565 million of U.S. dollars and C$65 million of Canadian dollars. ~~These~~The majority of these commitments matured on or before ~~October 28, 2011~~April 30, 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, 2011~~March 31, 2012 and December 31, ~~2010~~2011 (in millions) and the line items in the ~~consolidated~~ balance ~~sheet~~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.


	Consolidated Balance Sheet Location	September 30, 2011				Balance Sheet Location	March 31, 2012
	Consolidated Balance Sheet Location	Asset Derivatives		Liability Derivatives		Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	360	$	237	Receivables, net	$	161	$	188
Swaps	Receivables, net	46		40		Receivables, net	89		83
Swaps	Accrued expenses	4		3		Accrued expenses	4		3
Total		$	410	$	280		$	254	$	274

Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	6,170	$	6,266	Receivables, net	$	1,949	$	1,957
Swaps	Receivables, net	6		5		Receivables, net	46		48
Swaps	Prepaid expenses and other	2		1		Prepaid expenses and other	1		—
Swaps	Accrued expenses	181		268		Accrued expenses	22		31
Options	Receivables, net	5		—		Receivables, net	1		—
Options	Accrued expenses	—		21
Physical purchase contracts	Inventories	—		81		Inventories	—		36
Foreign currency contracts						Receivables, net	1		—
Foreign currency contracts						Accrued expenses	—		3
Total		$	6,364	$	6,642		$	2,020	$	2,075
Total derivatives		$	6,774	$	6,922		$	2,274	$	2,349

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Consolidated Balance Sheet Location	December 31, 2010				Balance Sheet Location	December 31, 2011
	Consolidated Balance Sheet Location	Asset Derivatives		Liability Derivatives		Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	120	$	183	Receivables, net	$	264	$	240
Swaps	Prepaid expenses and other	55		39
Swaps	Accrued expenses	31		32		Accrued expenses	36		46
Total		$	206	$	254		$	300	$	286

Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	2,717	$	2,914	Receivables, net	$	1,636	$	1,624
Swaps	Prepaid expenses and other	287		277		Prepaid expenses and other	4		2
Swaps	Accrued expenses	116		148		Accrued expenses	38		51
Options	Accrued expenses	—		6		Receivables, net	2		—
Options						Accrued expenses	—		2
Physical purchase contracts	Inventories	17		—		Inventories	—		2
Foreign currency contracts						Accrued expenses	—		3
Total		$	3,137	$	3,345		$	1,680	$	1,684
Total derivatives		$	3,343	$	3,599		$	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, 2011~~March 31, 2012, we had net receivables related to derivative instruments of $1 million from counterparties in the refining industry and no ~~amount of net receivables~~amounts from counterparties in the financial services industry. As of December 31, ~~2010~~2011, we had net receivables related to derivative instruments of $42 million from counterparties in the refining industry and ~~$21 million~~no amounts from counterparties in the financial services industry. These amounts represent the aggregate amount payable to us by companies in those industries, reduced by payables from us to those companies under master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party. We do not require any 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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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments on ~~Consolidated Statements of~~ 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 ~~consolidated~~ financial statements in which such gains and losses are reflected (in millions).

Derivatives in
Fair Value
Hedging
Relationships
Location
Gain or (Loss)
Recognized in
Income on
Derivatives

Gain or (Loss)
Recognized in
Income on
Hedged Item

Gain or (Loss)
Recognized in
Income for
Ineffective Portion
of Derivative
2011 2010 2011 2010 2011 2010
Three months ended September 30:
Commodity
contracts
Cost of sales $ 170
$ 54
$ (161 ) $ (56 ) $ 9
$ (2 )
Nine months ended September 30:
Commodity
contracts
Cost of sales 219
253
(222 ) (247 ) (3 ) 6



Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,
Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2012			2011
Commodity contracts:
Loss recognized in income on derivatives	Cost of sales	$	(267	)	$	(91	)
Gain recognized in income on hedged item	Cost of sales	228			86
Loss recognized in income on derivatives (ineffective portion)	Cost of sales	(39		)	(5		)

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~~three months ended ~~September 30, 2011~~March 31, 2012 and ~~2010~~2011. No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges for the ~~three and~~ ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012 and ~~2010~~2011.

Derivatives in
Cash Flow
Hedging
Relationships

Gain or (Loss)
Recognized in
OCI on
Derivatives
(Effective Portion)

Gain or (Loss)
Reclassified from
Accumulated OCI into
Income (Effective Portion)

Gain or (Loss)
Recognized in
Income on Derivatives
(Ineffective Portion)
2011 2010 Location 2011 2010 Location 2011 2010
Three months ended September 30:
Commodity
contracts
$ 20
$ —
Cost of sales $ —
$ 37
Cost of sales $ 4
$ —
Nine months ended September 30:
Commodity
contracts
20
(2 ) Cost of sales —
135
Cost of sales 4
—



Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,
Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2012			2011
Commodity contracts:
Gain recognized in OCI on derivatives (effective portion)		$	47		$	—
Gain reclassified from accumulated OCI into income (effective portion)	Cost of sales	48			—
Loss recognized in income on derivatives (ineffective portion)	Cost of sales	(5		)	—

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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~~three months ended ~~September 30, 2011~~March 31, 2012 and ~~2010~~2011. For the ~~three and~~ ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012, cash flow hedges primarily related to forward sales of gasoline and distillates, and associated forward purchases of crude oil, with $1319 million of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive ~~income as of~~ ~~September 30, 2011~~.income. We estimate that $1019 million of the deferred gains as of ~~September 30, 2011~~March 31, 2012 will be reclassified into cost of sales over the next 12nine months as a result of hedged transactions that are forecasted to occur. For the ~~three and~~ ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012 and ~~2010~~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 or (Loss) Recognized in Income on Derivatives	Gain or (Loss) Recognized in Income on Derivatives						Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,
		2011			2010			Location of Gain (Loss) Recognized in Income on Derivatives	2012			2011
Three months ended September 30:
Commodity contracts	Cost of sales	$	9		$	22		Cost of sales	$	(151	)	$	(299	)
Foreign currency contracts	Cost of sales	41			(5		)	Cost of sales	(23		)	(14		)
Other contract	Cost of sales	29			—
Total		$	79		$	17			$	(174	)	$	(313	)
Nine months ended September 30:
Commodity contracts	Cost of sales	$	(362	)	$	(93	)
Foreign currency contracts	Cost of sales	32			(2		)
Other contract	Cost of sales	29			—
Total		$	(301	)	$	(95	)

~~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. The loss of $~~362~~299 million on commodity contracts for the ~~nine~~three months ended ~~September 30,2011~~March 31, 2011 includes a $542 million loss related to forward sales of refined ~~products.~~product.


Trading Derivatives	Location of Gain or (Loss) Recognized in Income on Derivatives	Gain or (Loss) Recognized in Income on Derivatives				Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,
		2011		2010			2012			2011
Three months ended September 30:
Commodity contracts	Cost of sales	$	3	$	2	Cost of sales	$	(4	)	$	6
Nine months ended September 30:
Commodity contracts	Cost of sales	17		7

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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 ~~U.S., Canada, the United Kingdom, Ireland, and elsewhere;~~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, including the U.S., Canada, Europe, the Middle East, Africa, and South America;~~products;

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

~~domestic and foreign~~ demand for, and supplies of, crude oil and other feedstocks;

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

the level of consumer demand, including seasonal fluctuations;

refinery overcapacity or undercapacity;

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

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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 ~~foreign~~competitors’ imports ~~of refined products to the U.S., Canada, or the United Kingdom;~~into markets that we supply;

accidents, unscheduled shutdowns, or other ~~unscheduled shutdowns~~catastrophes affecting our refineries, machinery, pipelines, or 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;

~~lower than expected ethanol margins;~~

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

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

legislative or regulatory action, including the introduction or enactment of ~~federal, state, municipal, or foreign~~ legislation or rulemakings by governmental authorities, including tax and environmental regulations, such as those to be implemented under the California Global Warming Solutions Act (also known as AB 32) and the ~~EPA’s~~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~~euro relative to the ~~U.S.~~United States (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~~first quarter of ~~2011,~~2012, we reported a net loss attributable to Valero stockholders from continuing operations of $432 million, or $0.78 per share, compared to net income attributable to Valero stockholders from continuing operations of $~~1.2 billion, or~~ ~~$2.11~~ ~~per share, compared to~~ ~~$303~~104 million, or $~~0.53~~0.18 per share, for the ~~third~~first quarter of ~~2010. For the first~~ ~~nine~~2011 ~~months of 2011, we reported net income attributable to Valero stockholders from continuing operations of~~ .

~~$2.1 billion, or~~ ~~$3.59~~ ~~per share, compared to~~ ~~$743 million, or~~ ~~$1.31~~ ~~per share~~The results for the first quarter of 2012, however, were significantly impacted by a ~~nine~~$611 million ~~months of 2010. Included in~~asset impairment loss ($605 million after taxes, or $1.09 per share), primarily related to our Aruba Refinery, which is discussed below. In addition, the results for the first ~~nine~~ ~~months~~quarter of 2011 ~~was~~were significantly impacted by a $542 million loss ($352 million after taxes, or $0.62 per share) on commodity derivative contracts related to the forward sales of refined ~~products.~~product. These contracts were closed and realized in the first quarter of 2011. Excluding these significant items, net income attributable to Valero stockholders from continuing operations was $173 million ($0.31 per share) for the first quarter of 2012 compared to $456 million ($0.80 per share) for the first quarter of 2011.

The ~~improvement~~decline in net income attributable to Valero stockholders from continuing operations in the first quarter of ~~third~~2012 as compared to the first quarter ~~and~~of ~~first nine months~~2011 ~~of 2011 versus the comparable periods of 2010~~ was primarily due to ~~an increase~~a decrease in operating income attributable to the refining business ~~segments~~segment as outlined in the following ~~tables~~table (in millions):


	Three Months Ended September 30,									Three Months Ended March 31,
	2011			2010			Change			2012			2011			Change
Operating income (loss) by business segment:
Refining	$	1,947		$	590		$	1,357		$	(119	)	$	276		$	(395	)
Retail	97			105			(8		)	40			66			(26		)
Ethanol	107			47			60			9			44			(35		)
Corporate	(172		)	(152		)	(20		)	(174		)	(142		)	(32		)
Total	$	1,979		$	590		$	1,389		$	(244	)	$	244		$	(488	)

	Nine Months Ended September 30,
	2011			2010			Change
Operating income (loss) by business segment:
Refining	$	3,476		$	1,479		$	1,997
Retail	298			285			13
Ethanol	215			139			76
Corporate	(476		)	(405		)	(71		)
Total	$	3,513		$	1,498		$	2,015

Excluding the ~~impact~~impacts of the $611 million asset impairment loss in the first quarter of 2012 and the $542 million loss on commodity derivative contracts in the first quarter of 2011 described above, total company operating income for the first quarter of 2012 and the first quarter of 2011 would have been $367 million and $786 million, respectively, and our refining segment operating income would have been ~~$4.1 billion~~$492 million and ~~$4.0 billion,~~$818 million, respectively, for the ~~first nine months~~ ~~of 2011, which reflects an improvement in operating income of $2.6 billion and $2.5 billion, respectively, over the comparable 2010 period.~~same periods.

Refining segment operating income ~~improved~~declined primarily due to ~~increased margins for most of the products we produce. Our margin improvement included the benefits from wider~~lower sour crude oil differentials (which is the difference between the price of sweet crude oil and the price of sour crude oil) and lower margins for other products such as petrochemical feedstocks and petroleum coke, partially offset by improved gasoline and distillate margins for most of our refining regions. In addition, we continued to benefit from the favorable difference between the price of ~~waterborne~~sweet crude oils sourced from the inland U.S., such as West Texas Intermediate (WTI), versus the price of benchmark sweet crude oils, such as Louisiana Light Sweet (LLS) and Brent ~~and inland sweet~~ crude ~~oils, such as West Texas Intermediate (WTI). Many~~oils. Historically, the price of ~~our refineries process sour crude oils or~~ WTI-type crude ~~oils~~oil has closely approximated LLS and ~~these~~Brent crude ~~oils were~~oils. 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 resulted in WTI-type crude oil being priced ~~significantly below waterborne sweet~~at a significant discount to LLS and Brent crude oils during the ~~third~~first quarter of 2012 and 2011. This discount was wider in the first quarter of 2012 compared to the first quarter of 2011, which contributed to the improved gasoline and distillate margins described above.

In March 2012, we decided to suspend the ~~first nine months~~operations of ~~2011, versus~~ the ~~comparable 2010 periods.~~

Aruba Refinery by the end of March. Our decision

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~~Our retail segment generated operating income~~was based on the refinery’s inability to generate positive cash flows on a sustained basis subsequent to its restart in January 2011 and the sensitivity of ~~$97 million~~ ~~for the~~ ~~third~~ ~~quarter of 2011 compared~~its profitability to ~~$105 million~~ ~~for the~~ ~~third~~ quarter of 2010. This decrease of $8 million was due primarily to an increase of $8 million in the fuel margin generated by our Canadian retail operations, offset by a decrease of $10 million in the fuel margin generated by our U.S. retail operations and an increase of $8 million in operating expenses. For the ~~first nine months~~ ~~of 2011, our retail segment generated~~ ~~$298 million~~ ~~of operating income compared to~~ ~~$285 million~~ ~~for the~~ ~~first nine months~~ of 2010. The increase was primarily due to higher fuel margins and volumes in our Canadian operations, including a favorable impact from the strengthening of the Canadian dollar relative to the U.S. dollar.

~~Our ethanol segment generated operating income of~~ ~~$107 million~~ ~~for the~~ ~~third~~ ~~quarter of 2011 compared to~~ ~~$47 million~~ ~~for the~~ ~~third~~ ~~quarter of 2010, and it generated~~ ~~$215 million~~ ~~of operating income for the~~ ~~first nine months~~ ~~of 2011 compared to~~ ~~$139 million~~ ~~for the~~ ~~first nine months~~ ~~of 2010. The increase in operating income in both the~~ ~~third~~ ~~quarter and~~ ~~first nine months~~ ~~of 2011 was primarily due to improved operating margins combined with a full~~ ~~nine~~ months of operations related to the three ethanol plants we acquired in the first quarter of 2010. The ethanol business is dependent on margins between ethanol and corn feedstocks and is impacted by U.S. government subsidies and biofuels (including ethanol) mandates.

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. Valero Energy Ltd owns and operates the Pembroke Refinery,sour crude oil differentials, which ~~has a total throughput capacity of approximately~~ ~~270,000~~ barrels per day and is located in Wales, United Kingdom. Valero Energy Ltd also owns, directly and through various subsidiaries, an extensive network of marketing and logistics assets throughout the United Kingdom and Ireland. 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, the amounts paid have been favorably adjusted for working capital true-up adjustments (primarily inventory), to an adjusted purchase price of ~~$1.675 billion. We expect final settlement by year end. This acquisition is referred to as the Pembroke Acquisition.~~

On ~~October 1, 2011, we acquired the Meraux Refinery and related logistics assets for an initial payment of~~ ~~$586 million, including inventories of~~ ~~$261 million, from Murphy Oil Corporation. The purchase price was funded from available cash. We expect to receive a favorable adjustment related to inventories~~narrowed significantly in the fourth quarter of ~~2011 that will reduce~~2011. On March 28, 2012, we received a non-binding indication of interest from an unrelated interested party to purchase the Aruba Refinery for $350 million, plus working capital as of the closing date, subject to completion of due diligence and further negotiations. We have accepted this offer, subject to the finalization of the purchase ~~price by approximately~~and sale agreement. Because of our decision to suspend the operations of the Aruba Refinery and the possibility that we may sell the refinery, we evaluated the refinery for potential impairment as of March 31, 2012 and recognized an asset impairment loss of $40595 million., which is discussed in Note 3 of Notes to Condensed Consolidated Financial Statements.

AsOutlook

The benefit we experienced in our refining business throughout 2011 and the first quarter of 2012 from processing discounted WTI-type crude oils may decline as various crude oil pipeline and logistics projects are completed in coming months. 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 ~~date~~price differential of WTI-priced crude oils relative to Brent-priced crude oil. As a result, the ~~filing~~margins for refined products for refiners that process WTI-priced crude oils may decline. In addition, 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 coming months. However, some of ~~this report, the financial markets~~these refineries may continue to ~~experience significant volatility. The overall~~be operated for political and other reasons, which could have a negative impact on ~~our business is uncertain at this time and~~refined product margins. As a result of these matters, we expect ~~the~~ energy markets and margins 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) ~~(c)~~

(millions of dollars, except per share amounts)


	Three Months Ended September 30,									Three Months Ended March 31,
	2011			2010			Change			2012			2011			Change
Operating revenues	$	33,713		$	21,015		$	12,698		$	35,167		$	26,308		$	8,859
Costs and expenses:
Cost of sales ~~(d)~~(c)	30,033			18,915			11,118			33,035			24,568			8,467
Operating expenses:
Refining	870			753			117			964			744			220
Retail ~~(d)~~	177			169			8			166			162			4
Ethanol	103			96			7			87			95			(8		)
General and administrative expenses	161			139			22			164			130			34
Depreciation and amortization expense:
Refining	340			303			37			337			316			21
Retail	29			27			2			27			28			(1		)
Ethanol	10			10			—			10			9			1
Corporate	11			13			(2		)	10			12			(2		)
Asset impairment loss (d)										611			—			611
Total costs and expenses	31,734			20,425			11,309			35,411			26,064			9,347
Operating income	1,979			590			1,389
Operating income (loss)										(244		)	244			(488		)
Other income, net	1			17			(16		)	6			17			(11		)
Interest and debt expense, net of capitalized interest	(88		)	(119		)	31			(99		)	(117		)	18
Income from continuing operations before income tax expense	1,892			488			1,404
Income (loss) from continuing operations before income tax expense										(337		)	144			(481		)
Income tax expense	689			185			504			95			40			55
Income from continuing operations	1,203			303			900
Income (loss) from continuing operations										(432		)	104			(536		)
Income (loss) from discontinued operations, net of income taxes	—			(11		)	11			—			(6		)	6
Net income	1,203			292			911
Net income (loss)										(432		)	98			(530		)
Less: Net loss attributable to noncontrolling interests	—			—			—			—			—			—
Net income attributable to Valero stockholders	$	1,203		$	292		$	911
Net income (loss) attributable to Valero stockholders										$	(432	)	$	98		$	(530	)

Net income attributable to Valero stockholders:
Net income (loss) attributable to Valero stockholders:
Continuing operations	$	1,203		$	303		$	900		$	(432	)	$	104		$	(536	)
Discontinued operations	—			(11		)	11			—			(6		)	6
Total	$	1,203		$	292		$	911		$	(432	)	$	98		$	(530	)

Earnings per common share – assuming dilution:
Continuing operations	$	2.11		$	0.53		$	1.58		$	(0.78	)	$	0.18		$	(0.96	)
Discontinued operations	—			(0.02		)	0.02			—			(0.01		)	0.01
Total	$	2.11		$	0.51		$	1.60		$	(0.78	)	$	0.17		$	(0.95	)

________________

See note references on page 4743.

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Operating Highlights

(millions of dollars, except per barrel amounts)


	Three Months Ended September 30,							Three Months Ended March 31,
	2011		2010		Change			2012			2011		Change
Refining (a) (b):
Operating income(c)	$	1,947	$	590	$	1,357		$	(119	)	$	276	$	(395	)
Throughput margin per barrel ~~(e)~~(c)	$	13.24	$	8.13	$	5.11		$	7.71		$	9.91	$	(2.20	)
Operating costs per barrel:
Operating expenses	3.65		3.71		(0.06		)	4.15			3.93		0.22
Depreciation and amortization expense	1.43		1.50		(0.07		)	1.45			1.66		(0.21		)
Total operating costs per barrel(d)	5.08		5.21		(0.13		)	5.60			5.59		0.01
Operating income per barrel(d)	$	8.16	$	2.92	$	5.24		$	2.11		$	4.32	$	(2.21	)

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude	540		443		97			451			372		79
Medium/light sour crude	455		402		53			555			372		183
Acidic sweet crude	150		51		99			73			72		1
Sweet crude	739		708		31			883			666		217
Residuals	310		239		71			169			249		(80		)
Other feedstocks	123		113		10			144			137		7
Total feedstocks	2,317		1,956		361			2,275			1,868		407
Blendstocks and other	275		247		28			280			238		42
Total throughput volumes	2,592		2,203		389			2,555			2,106		449

Yields (thousand barrels per day):
Gasolines and blendstocks	1,196		1,088		108			1,191			956		235
Distillates	894		766		128			911			695		216
Other products (f)	519		381		138			469			465		4
Total yields	2,609		2,235		374			2,571			2,116		455

_______________

See note references on page 4743.

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Refining Operating Highlights by Region (g)

(millions of dollars, except per barrel amounts)


	Three Months Ended September 30,							Three Months Ended March 31,
	2011		2010		Change			2012			2011			Change
Gulf Coast:
U.S. Gulf Coast (a):
Operating income (c)								$	235		$	483		$	(248	)
Throughput volumes (thousand barrels per day)								1,476			1,299			177
Throughput margin per barrel (c) (e)								$	6.92		$	9.63		$	(2.71	)
Operating costs per barrel:
Operating expenses								$	3.67		$	3.86		$	(0.19	)
Depreciation and amortization expense								1.50			1.64			(0.14		)
Total operating costs per barrel (d)								5.17			5.50			(0.33		)
Operating income per barrel (d)								$	1.75		$	4.13		$	(2.38	)

U.S. Mid-Continent:
Operating income (c)								$	254		$	289		$	(35	)
Throughput volumes (thousand barrels per day)								398			403			(5		)
Throughput margin per barrel (c) (e)								$	13.80		$	13.04		$	0.76
Operating costs per barrel:
Operating expenses								5.31			3.65			1.66
Depreciation and amortization expense								1.50			1.44			0.06
Total operating costs per barrel								6.81			5.09			1.72
Operating income per barrel								$	6.99		$	7.95		$	(0.96	)

North Atlantic (b):
Operating income	$	1,167	$	388	$	779		$	61		$	56		$	5
Throughput volumes (thousand barrels per day)	1,522		1,336		186			461			209			252
Throughput margin per barrel (e)	$	13.08	$	8.34	$	4.74		$	5.64		$	7.02		$	(1.38	)
Operating costs per barrel:
Operating expenses	3.31		3.65		(0.34		)	3.52			2.81			0.71
Depreciation and amortization expense	1.43		1.54		(0.11		)	0.66			1.20			(0.54		)
Total operating costs per barrel	4.74		5.19		(0.45		)	4.18			4.01			0.17
Operating income per barrel	$	8.34	$	3.15	$	5.19		$	1.46		$	3.01		$	(1.55	)

Mid-Continent:
Operating income	$	586	$	131	$	455
U.S. West Coast:
Operating loss (c)								$	(58	)	$	(10	)	$	(48	)
Throughput volumes (thousand barrels per day)	400		422		(22		)	220			195			25
Throughput margin per barrel (e)	$	22.27	$	8.06	$	14.21
Throughput margin per barrel (c) (e)								$	6.32		$	8.33		$	(2.01	)
Operating costs per barrel:
Operating expenses	4.76		3.34		1.42			6.56			6.15			0.41
Depreciation and amortization expense	1.59		1.33		0.26			2.67			2.81			(0.14		)
Total operating costs per barrel	6.35		4.67		1.68			9.23			8.96			0.27
Operating income per barrel	$	15.92	$	3.39	$	12.53
Operating loss per barrel								$	(2.91	)	$	(0.63	)	$	(2.28	)

North Atlantic (a) (b):
Operating income	$	65	$	36	$	29
Throughput volumes (thousand barrels per day)	386		193		193
Throughput margin per barrel (e)	$	5.46	$	6.04	$	(0.58	)
Operating costs per barrel:
Operating expenses	2.91		2.75		0.16
Depreciation and amortization expense	0.74		1.30		(0.56		)
Total operating costs per barrel	3.65		4.05		(0.40		)
Operating income per barrel	$	1.81	$	1.99	$	(0.18	)

West Coast:
Operating income	$	129	$	35	$	94
Throughput volumes (thousand barrels per day)	284		252		32
Throughput margin per barrel (e)	$	11.96	$	8.66	$	3.30
Operating costs per barrel:
Operating expenses	4.94		5.42		(0.48		)
Depreciation and amortization expense	2.08		1.74		0.34
Total operating costs per barrel	7.02		7.16		(0.14		)
Operating income per barrel	$	4.94	$	1.50	$	3.44

Total refining operating income	$	1,947	$	590	$	1,357
Operating income for regions above								$	492		$	818		$	(326	)
Asset impairment loss (d)								(611		)	—			(611		)
Loss on derivative contracts related to the forward sales of refined product (c)								—			(542		)	542
Total refining operating income (loss)								$	(119	)	$	276		$	(395	)

_______________

See note references on page 4743.

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Average Market Reference Prices and Differentials (h)

(dollars per barrel, except as noted)


	Three Months Ended September 30,								Three Months Ended March 31,
	2011			2010		Change			2012			2011		Change
Feedstocks:
Louisiana Light Sweet (LLS) crude oil	$	112.21		$	78.66	$	33.55
LLS less West Texas Intermediate (WTI) crude oil	22.47			2.58		19.89
LLS less Alaska North Slope (ANS) crude oil	0.60			3.03		(2.43		)
LLS less Brent crude oil	(1.43		)	1.73		(3.16		)
Brent crude oil									$	118.34		$	105.16	$	13.18
Brent less West Texas Intermediate (WTI) crude oil									15.46			11.22		4.24
Brent less Alaska North Slope (ANS) crude oil									0.65			3.92		(3.27		)
Brent less Louisiana Light Sweet (LLS) crude oil									(0.56		)	0.14		(0.70		)
Brent less Mars crude oil									3.66			3.73		(0.07		)
Brent less Maya crude oil									9.33			15.82		(6.49		)
LLS crude oil									118.90			105.02		13.88
LLS less Mars crude oil	2.53			3.96		(1.43		)	4.22			3.59		0.63
LLS less Maya crude oil	13.48			11.04		2.44			9.89			15.68		(5.79		)
WTI crude oil	89.74			76.08		13.66			102.88			93.94		8.94
WTI less Mars crude oil	(19.94		)	1.38		(21.32		)
WTI less Maya crude oil	(8.99		)	8.46		(17.45		)

Natural gas (dollars per million British thermal units)									2.39			4.15		(1.76		)

Products:
Gulf Coast:
U.S. Gulf Coast:
Conventional 87 gasoline less Brent									7.12			3.68		3.44
Ultra-low-sulfur diesel less Brent									14.24			13.45		0.79
Propylene less Brent									(12.48		)	19.36		(31.84		)
Conventional 87 gasoline less LLS	$	8.20		$	4.35	$	3.85		6.56			3.82		2.74
Ultra-low-sulfur diesel less LLS	14.19			9.12		5.07			13.68			13.59		0.09
Propylene less LLS	12.46			2.61		9.85			(13.04		)	19.50		(32.54		)
Conventional 87 gasoline less WTI	30.67			6.93		23.74
Ultra-low-sulfur diesel less WTI	36.66			11.70		24.96
Propylene less WTI	34.93			5.19		29.74
Mid-Continent:
U.S. Mid-Continent:
Conventional 87 gasoline less WTI	32.11			9.20		22.91			18.28			15.89		2.39
Ultra-low-sulfur diesel less WTI	38.34			13.20		25.14			27.75			25.10		2.65
North Atlantic:
Conventional 87 gasoline less Brent	7.48			5.85		1.63			7.73			4.20		3.53
Ultra-low-sulfur diesel less Brent	14.55			12.16		2.39			15.87			15.30		0.57
Conventional 87 gasoline less WTI	31.38			6.70		24.68
Ultra-low-sulfur diesel less WTI	38.45			13.01		25.44
West Coast:
U.S. West Coast:
CARBOB 87 gasoline less ANS	10.27			16.96		(6.69		)	14.24			15.36		(1.12		)
CARB diesel less ANS	15.77			15.10		0.67			18.28			20.70		(2.42		)
CARBOB 87 gasoline less WTI	32.14			16.51		15.63			29.05			22.66		6.39
CARB diesel less WTI	37.64			14.65		22.99			33.09			28.00		5.09
New York Harbor corn crush (dollars per gallon)	0.36			0.43		(0.07		)	(0.05		)	0.08		(0.13		)

_______________

See note references on page 4743.

4541

Table of Contents

Operating Highlights (continued)

(millions of dollars, except per gallon amounts)


	Three Months Ended September 30,									Three Months Ended March 31,
	2011			2010			Change			2012			2011			Change
Retail–U.S.: ~~(d)~~
Operating income	$	59		$	72		$	(13	)	$	11		$	19		$	(8	)
Company-operated fuel sites (average)	994			990			4			997			993			4
Fuel volumes (gallons per day per site)	5,168			5,204			(36		)	5,046			4,895			151
Fuel margin per gallon	$	0.155		$	0.176		$	(0.021	)	$	0.050		$	0.076		$	(0.026	)
Merchandise sales	$	324		$	322		$	2		$	288		$	283		$	5
Merchandise margin (percentage of sales)	29.2		%	28.8		%	0.4		%	29.5		%	28.3		%	1.2		%
Margin on miscellaneous sales	$	22		$	21		$	1		$	24		$	22		$	2
Operating expenses	$	111		$	108		$	3		$	104		$	98		$	6
Depreciation and amortization expense	$	19		$	18		$	1		$	18		$	19		$	(1	)

Retail–Canada: ~~(d)~~
Operating income	$	38		$	33		$	5		$	29		$	47		$	(18	)
Fuel volumes (thousand gallons per day)	3,214			3,214			—			3,097			3,234			(137		)
Fuel margin per gallon	$	0.273		$	0.247		$	0.026		$	0.258		$	0.317		$	(0.059	)
Merchandise sales	$	72		$	66		$	6		$	58		$	57		$	1
Merchandise margin (percentage of sales)	29.4		%	30.4		%	(1		)%	29.3		%	29.7		%	(0.4		)%
Margin on miscellaneous sales	$	11		$	10		$	1		$	11		$	11		$	—
Operating expenses	$	66		$	61		$	5		$	62		$	64		$	(2	)
Depreciation and amortization expense	$	10		$	9		$	1		$	9		$	9		$	—

Ethanol (c):
Ethanol:
Operating income	$	107		$	47		$	60		$	9		$	44		$	(35	)
Production (thousand gallons per day)	3,272			3,100			172			3,478			3,282			196
Gross margin per gallon of production (e)	$	0.73		$	0.54		$	0.19		$	0.34		$	0.50		$	(0.16	)
Operating costs per gallon of production:
Operating expenses	0.34			0.34			—			0.28			0.32			(0.04		)
Depreciation and amortization expense	0.04			0.03			0.01			0.03			0.03			—
Total operating costs per gallon of production	0.38			0.37			0.01			0.31			0.35			(0.04		)
Operating income per gallon of production	$	0.35		$	0.17		$	0.18		$	0.03		$	0.15		$	(0.12	)

_______________

See note references on page 4743.

4642

Table of Contents

The following notes relate to references on pages 4238 through 4642.

(a)

~~The information presented for~~For the three months ended March 31,2012~~September 30, 2011~~ ~~includes~~, the financial highlights and operating highlights for the refining segment and U.S. Gulf Coast region include the results of operations of our ~~refinery in Wales, United Kingdom (Pembroke Refinery)~~Meraux Refinery, including related logistics assets, from the date of its acquisition on October 1, 2011

(b)

For the three months ended March 31, 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~~, through~~ ~~September 30, 2011~~. ~~In addition, the refining segment and North Atlantic region operating highlights for the three months ended~~ ~~September 30, 2011~~ ~~include the Pembroke Refinery.~~

~~(b)~~

~~In December 2010, we sold our Paulsboro Refinery to PBF Holding Company LLC. The results of operations of the Paulsboro Refinery have been presented as discontinued operations for the~~ ~~three months ended September 30,~~ ~~2010. In addition, the refining segment and North Atlantic region operating highlights exclude the Paulsboro Refinery for the~~ ~~three months ended September 30,~~ ~~2010.~~

(c)

~~We acquired~~

Cost of sales for the three ~~ethanol plants in~~months ended March 31, 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 ~~2010.~~2011. The ~~information~~loss is reflected in refining segment operating income for the three months ended March 31, 2011, but throughput margin per barrel for the refining segment has been restated for the amount previously presented ~~includes~~to exclude this $542 million loss ($2.86 per barrel). In addition, operating income (loss) and throughput margin per barrel for the ~~results~~U.S. Gulf Coast, U.S. Mid-Continent, and U.S. West Coast regions for the three months ended March 31, 2011 have been restated from the amounts previously presented to exclude the portion of ~~operations~~this loss that had been allocated to them of ~~those plants commencing on their respective acquisition dates. Ethanol production volumes are based on total production during each period divided by actual calendar days~~$372 million ($3.18 per ~~period.~~barrel); $122 million ($3.36 per barrel), and $48 million ($2.71 per barrel), respectively.

(d)

~~Credit card transaction processing fees incurred~~In March 2012, we concluded our evaluation of strategic alternatives for our refinery in Aruba (Aruba Refinery) and announced that we would temporarily suspend the refinery’s operations by ~~our retail~~the end of March. Because of this decision, we analyzed the Aruba Refinery for potential impairment and concluded that the refinery’s net book value (carrying amount) of $945 million was not recoverable through the future operations and disposition of the refinery. We determined that the fair value of the Aruba Refinery was $350 million; therefore, we recognized an asset impairment loss of $595 million. In addition, we recognized an asset impairment loss of $16 million related to equipment associated with a permanently cancelled capital project at another refinery. The total asset impairment loss of $611 million is reflected in refining segment of ~~$23 million~~operating income for the three months ended ~~September 30,~~ ~~2010 have been reclassified~~March 31, 2012, but it is excluded from ~~retail~~ operating ~~expenses to cost of sales. The Retail–U.S.~~costs per barrel and ~~Retail–Canada~~ operating ~~highlights~~income per barrel for the ~~three months ended September 30,~~ ~~2010 have been restated to reflect this reclassification.~~refining segment and Gulf Coast region.


(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, and Port Arthur Refineries; the U.S. Mid-Continent region includes the McKee, Ardmore, and Memphis Refineries; the North Atlantic ~~(formerly known as Northeast)~~ region includes the Pembroke and Quebec City Refineries; and the ~~West~~U.S.West Coast region includes the Benicia and Wilmington Refineries.

(h)

Average market reference prices for ~~LLS~~Brent crude oil, along with price differentials between the price of ~~LLS~~Brent crude oil and other types of crude oil, have been included in the table of Average Market Reference Prices and Differentials. The table also includes price differentials by region between the prices of certain products and the benchmark crude oil that provides the best indicator of product margins for each region. ~~Prior to the first quarter of 2011,~~We previously provided feedstock and product differentials ~~presented herein were~~ based on the price of WTI crude oil. However, the price of WTI crude oil no longer provides a reasonable benchmark price of crude oil for all regions. Beginning in late 2010, WTI ~~light-sweet~~ crude oil began to price at a discount to ~~waterborne light-sweet~~benchmark sweet crude oils, such as ~~LLS~~Brent and ~~Brent,~~LLS, because of increased WTI supplies resulting from greater ~~domestic~~U.S. production and increased deliveries of crude oil from Canada into the U.S. Mid-Continent region. ~~Therefore, the use of the price of WTI~~We utilize Brent crude oil ~~as a benchmark~~for price ~~for regions that do not process WTI~~differentials because we believe it represents sweet crude oil ~~is no longer reasonable.~~prices for marginal refineries in the Atlantic Basin, and thus sets refined-product prices.

General

Operating revenues increased 6034 percent (or $~~12.7~~8.9 billion) for the ~~third~~first quarter of ~~2011~~2012 compared to the ~~third~~first quarter of ~~2010~~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 ~~178,000~~124,000 barrels per day^{from the Meraux Refinery, which was acquired on October 1,} ~~($3.0 billion~~ 2011, and incremental throughput of ~~revenue)~~246,000 barrels per day from the Pembroke Refinery, which was acquired on August 1, ~~2011, and throughput of 182,000 barrels per day ($1.8 billion of revenue) from the Aruba Refinery, which restarted operations in January~~ 2011. ~~Both operating~~Operating income decreased $488 million and income from continuing operations before taxes ~~increased~~decreased $~~1.4 billion~~481 million for the ~~third~~first quarter of ~~2011~~2012 compared to amounts reported for the ~~third~~first quarter of ~~2010~~2011 primarily due to a $~~1.4 billion~~395 million ~~increase~~decrease in refining segment operating income discussed below.

~~_______________~~

¹~~Calculated based on throughput volumes of the Pembroke Refinery from the date of acquisition (August 1, 2011), divided by the number of days during the third quarter of 2011.~~

4743

Table of Contents

Refining

Refining segment operating income ~~more than tripled (a~~decreased $~~1.4 billion~~395 million ~~increase)~~ from operating income of $~~590~~276 million for the ~~third~~ ~~quarter of~~ ~~2010~~ to ~~$1.9 billion~~ ~~for the~~ ~~third~~first quarter of 2011 to an operating loss of $119 million for the first quarter of 2012. This decrease was impacted by the $542 million loss on derivative contracts in the first quarter of 2011 and the $611 million asset impairment loss in the first quarter of 2012. (See Note 3 of Condensed Notes to Consolidated Financial Statements for further discussion of this asset impairment loss). Excluding these losses, refining segment operating income decreased $326 million from $818 million in the first quarter of 2011 to $492 million in the first quarter of 2012. The $~~1.4 billion~~326 million ~~improvement~~decrease in operating income was due primarily to an $85 million decrease in refining margin and a $~~1.5 billion~~ ~~increase in refining margin, offset by a~~ ~~$117~~220 million increase in operating expenses.

The $~~1.5 billion~~85 million ~~increase~~decrease in refining margin was primarily due to a 6322 percent ~~increase~~decrease in throughput margin per barrel (a $~~5.11~~2.20 per barrel ~~increase~~decrease between the comparable periods), and this ~~increase~~decrease was largely driven by narrower sour crude oil differentials, partially offset by an ~~improvement~~increase in gasoline and distillate margins in most of our refining regions, ~~primarily the Mid-Continent and Gulf Coast refining regions,~~ as further explained below.

For the first quarter of 2012, our refining segment was unfavorably impacted by the decrease in sour crude oil differentials as compared to the first quarter of 2011. For example, Maya crude oil, which is a type of sour crude oil, sold at a discount of $9.33 per barrel to Brent crude oil, which is a type of sweet crude oil, during the first quarter of 2012. This compares to a discount of $15.82 per barrel during the first quarter of 2011, representing an unfavorable decrease of $6.49 per barrel. We estimate that the decrease in the discounts for all types of sour crude oil that we process had a negative impact to our refining margin of approximately $490 million, quarter versus quarter.

The WTI-based benchmark reference margin for U.S. Mid-Continent conventional 87 gasoline was $~~32.11~~18.28 per barrel for the ~~third~~first quarter of ~~2011~~2012, compared to $~~9.20~~15.89 per barrel for the ~~third~~first quarter of ~~2010~~2011, representing a favorable increase of $~~22.91~~2.39 per barrel. In addition, the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low sulfur diesel (a type of distillate) was $~~38.34~~27.75 per barrel for the ~~third~~first quarter of ~~2011~~2012, compared to $~~13.20~~25.10 per barrel for the ~~third~~first quarter of ~~2010~~2011, representing a favorable increase of $~~25.14~~2.65 per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately ~~$500~~$50 million and ~~$300~~$30 million, respectively,quarter versus quarter. The increases in the gasoline and distillate benchmark reference margins in the U.S. Mid-Continent region are primarily due to the substantial discount in the price of ~~WTI~~WTI-type crude oil, the primary type of crude oil processed by our U.S. Mid-Continent refineries, versus ~~LLS-type~~the price of LLS and Brent crude oils. Historically, the price of ~~WTI~~WTI-type crude oil has ~~tracked~~closely approximated LLS and Brent crude ~~oil,~~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~~WTI-type crude oil has resulted in ~~WTI~~WTI-type crude oil currently being priced at a significant discount to LLS and Brent crude ~~oil.~~oils.

The ~~LLS-based~~Brent-based benchmark reference margin for U.S. Gulf Coast conventional 87 gasoline was $~~8.20~~7.12 per barrel for the ~~third~~first quarter of ~~2011~~2012, compared to $~~4.35~~3.68 per barrel for the ~~third~~first quarter of ~~2010~~2011, representing a favorable increase of $~~3.85~~3.44 per barrel. In addition, the ~~LLS-based~~Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low sulfur diesel was $~~14.19~~14.24 per barrel for the ~~third~~first quarter of ~~2011~~2012, compared to $~~9.12~~13.45 per barrel for the ~~third~~first quarter of ~~2010~~2011, representing a favorable increase of $~~5.07~~0.79 per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $200 million and ~~$250~~$40 million, respectively, quarter versus quarter. The increases in the gasoline and distillate benchmark reference margins are supported by increased exports of gasoline and distillate as well as an increase in demand for distillates.

~~In addition, our system benefited from the increase in the discount~~

Table of ~~the price of heavy sour crude oils as compared to the price of sweet crude oils. For example, Maya crude oil, which is a type of heavy sour crude oil, sold at a discount of~~ ~~$13.48~~ ~~per barrel to LLS crude oil, which is a type of sweet crude oil, during the~~ ~~third~~ ~~quarter of~~ ~~2011. This compares to a discount of~~ ~~$11.04~~ ~~per barrel during the~~ ~~third~~ ~~quarter of~~ ~~2010, representing a favorable increase of~~ ~~$2.44~~ per barrel. We estimate that the increase in the discounts for all types of sour crude oil that we process had a positive impact to our refining margin of approximately $120 million, quarter versus quarter.Contents

The increase of $~~117~~220 million in refining operating expenses discussed above was primarily due to ~~$50~~$93 million in operating expenses incurred by the Pembroke Refinery, which was acquired on August 1, 2011, and $37 million in operating expenses incurred by the Meraux Refinery, which was acquired on October 1, 2011. The remaining increase in refining operating expenses of ~~$67~~$90 million was primarily due to a ~~$34~~$48 million increase in maintenance expenses and a ~~$38~~$36 million increase in ~~chemicals~~regulatory and ~~catalyst~~insurance costs.

~~Table of Contents~~

Retail

Retail segment operating income was $9740 million for the ~~third~~first quarter of 2012 compared to $66 million for the first quarter of 2011 ~~compared to~~ ~~$105 million~~ ~~for the~~ ~~third~~ ~~quarter of~~ ~~2010~~. This 839 percent (or $8$26 million) decrease was due primarily to ~~an increase of $8 million~~decreases in the fuel ~~margin~~margins generated by both our Canadian ~~retail operations offset by a decrease of $10 million in the fuel margin generated by our~~and U.S. retail operations of $18 million and ~~an increase of~~ $8$10 million, ~~in operating expenses between the quarters.~~ respectively.

Ethanol

Ethanol segment operating income was $~~107~~9 million for the ~~third~~first quarter of 2012 compared to $44 million for the first quarter of 2011 ~~compared to~~ ~~$47 million~~ ~~for the~~ ~~third~~ ~~quarter of~~ ~~2010~~. The $6035 million ~~increase~~decrease in operating income was primarily due to a ~~$68~~$42 million ~~increase~~decrease in gross margin, partially offset by ~~a $7~~an $8 million ~~increase~~decrease in operating expenses.

The ~~increase~~decrease in gross margin was due to a 32 percent decrease in the gross margin per gallon of ethanol production (a $0.16 per gallon decrease between the comparable periods) primarily due to lower ethanol prices between the first quarter of 2011 and the first quarter of 2012. The ethanol prices in 2012 were pressured by a surplus of ethanol supply in 2012 stemming from higher production in 2011, combined with reduced demand for ethanol in 2012 due to the decline in gasoline demand. The impact of lower ethanol prices on gross margin was partially offset by an increase in ethanol production (a ~~172,000~~196,000 gallon per day increase between the comparable periods), which resulted from higher utilization rates and increased yield from the corn feedstock that we processed during the ~~third~~first quarter of ~~2011~~2012~~, and a 35 percent increase in the gross margin per gallon of ethanol production (a~~ ~~$0.19~~ ~~per gallon increase between the comparable periods)~~.

The ~~increase~~reduction in operating expenses was due primarily to a $5$14 million ~~increase~~decrease in energy costs ~~and~~due to lower natural gas prices partially offset by an increase in chemical ~~expenses.~~expenses of $3 million compared to the first quarter of 2011.

Corporate Expenses and Other

General and administrative expenses increased ~~$22~~$34 million from the ~~third~~ ~~quarter of~~ ~~2010~~ ~~to the~~ ~~third~~first quarter of 2011 ~~primarily due~~ to ~~$18 million in costs incurred in connection with the Pembroke Acquisition.~~

~~“Other income, net” for~~ the ~~third~~first quarter of ~~2011~~ ~~decreased~~ ~~$16 million~~ ~~from the~~ ~~third~~ ~~quarter of~~ ~~2010~~2012 primarily due to $19 million in administrative costs related to our European operations and a $12 million ~~decrease~~increase in investment income earned on the plan assets of certain of our non-qualified benefit plans and earnings of $4 million in the third quarter of 2010 related to our joint venture investment in Cameron Highway Oil Pipeline Company, which did not recur due to the sale of our ownership interest in that joint venture in the fourth quarter of 2010.employee-related expenses.

“Interest and debt expense, net of capitalized interest” for the ~~third~~first quarter of 2012 decreased $18 million from the first quarter of 2011 ~~decreased~~ ~~$31 million~~ ~~from the~~ ~~third~~ ~~quarter of~~ ~~2010~~. This decrease is primarily due to a ~~$16~~$25 million increase in capitalized interest due to a corresponding increase in capital expenditures between the quarters and the resumption of construction activity on previously suspended projects combined with a $7 million favorable impact from a decrease in average borrowings and an $8 million favorable impact resulting from the successful resolution of a tax contingency.quarters.

Income tax expense increased $~~504~~55 million from the ~~third~~ ~~quarter of~~ ~~2010~~ ~~to the~~ ~~third~~first quarter of 2011 ~~mainly as a result of higher operating income in 2011.~~

~~Table of Contents~~

~~Financial Highlights (a) (b) (c)~~

~~(millions of dollars, except per share amounts)~~

Nine Months Ended September 30,
2011 2010 Change
Operating revenues $ 91,314
$ 60,069
$ 31,245
Costs and expenses:
Cost of sales (d) (e) 82,981
54,198
28,783
Operating expenses:
Refining 2,427
2,210
217
Retail (d) 508
484
24
Ethanol 302
267
35
General and administrative expenses 442
367
75
Depreciation and amortization expense:
Refining 995
898
97
Retail 84
80
4
Ethanol 28
27
1
Corporate 34
38
(4 )
Asset impairment loss —
2
(2 )
Total costs and expenses 87,801
58,571
29,230
Operating income 3,513
1,498
2,015
Other income, net 28
29
(1 )
Interest and debt expense, net of capitalized interest (312 ) (363 ) 51
Income from continuing operations
before income tax expense
3,229
1,164
2,065
Income tax expense 1,178
421
757
Income from continuing operations 2,051
743
1,308
Income (loss) from discontinued operations,
net of income taxes
(7 ) 19
(26 )
Net income 2,044
762
1,282
Less: Net loss attributable to noncontrolling interests (1 ) —
(1 )
Net income attributable to Valero stockholders $ 2,045
$ 762
$ 1,283

Net income attributable to Valero stockholders:
Continuing operations $ 2,052
$ 743
$ 1,309
Discontinued operations (7 ) 19
(26 )
Total $ 2,045
$ 762
$ 1,283

Earnings per common share – assuming dilution:
Continuing operations $ 3.59
$ 1.31
$ 2.28
Discontinued operations (0.01 ) 0.03
(0.04 )
Total $ 3.58
$ 1.34
$ 2.24

~~_______________~~

~~See note references on page~~ 55.

~~Table of Contents~~

~~Operating Highlights~~

~~(millions of dollars, except per barrel amounts)~~

Nine Months Ended September 30,
2011 2010 Change
Refining (a) (b):
Operating income (e) $ 3,476
$ 1,479
$ 1,997
Throughput margin per barrel (e) (f) $ 10.80
$ 7.97
$ 2.83
Operating costs per barrel:
Operating expenses 3.80
3.84
(0.04 )
Depreciation and amortization expense 1.56
1.56
—
Total operating costs per barrel 5.36
5.40
(0.04 )
Operating income per barrel $ 5.44
$ 2.57
$ 2.87

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude 455
452
3
Medium/light sour crude 415
399
16
Acidic sweet crude 117
51
66
Sweet crude 695
655
40
Residuals 284
195
89
Other feedstocks 122
115
7
Total feedstocks 2,088
1,867
221
Blendstocks and other 252
241
11
Total throughput volumes 2,340
2,108
232

Yields (thousand barrels per day):
Gasolines and blendstocks 1,069
1,046
23
Distillates 793
695
98
Other products (g) 491
392
99
Total yields 2,353
2,133
220

~~_______________~~

~~See note references on page~~ 55.

~~Table of Contents~~

~~Refining Operating Highlights by Region (h)~~

~~(millions of dollars, except per barrel amounts)~~

Nine Months Ended September 30,
2011 2010 Change
Gulf Coast:
Operating income (e) $ 2,064
$ 1,027
$ 1,037
Throughput volumes (thousand barrels per day) 1,418
1,268
150
Throughput margin per barrel (e) (f) $ 10.48
$ 8.35
$ 2.13
Operating costs per barrel:

Operating expenses 3.62
3.78
(0.16 )
Depreciation and amortization expense 1.53
1.60
(0.07 )
Total operating costs per barrel 5.15
5.38
(0.23 )
Operating income per barrel $ 5.33
$ 2.97
$ 2.36

Mid-Continent:
Operating income (e) $ 1,146
$ 271
$ 875
Throughput volumes (thousand barrels per day) 401
392
9
Throughput margin per barrel (e) (f) $ 16.18
$ 7.59
$ 8.59
Operating costs per barrel:
Operating expenses 4.14
3.63
0.51
Depreciation and amortization expense 1.56
1.42
0.14
Total operating costs per barrel 5.70
5.05
0.65
Operating income per barrel $ 10.48
$ 2.54
$ 7.94

North Atlantic (a) (b):
Operating income $ 104
$ 81
$ 23
Throughput volumes (thousand barrels per day) 268
189
79
Throughput margin per barrel (f) $ 5.32
$ 6.01
$ (0.69 )
Operating costs per barrel:
Operating expenses 2.92
2.98
(0.06 )
Depreciation and amortization expense 0.98
1.47
(0.49 )
Total operating costs per barrel 3.90
4.45
(0.55 )
Operating income per barrel $ 1.42
$ 1.56
$ (0.14 )

West Coast:
Operating income (e) $ 162
$ 102
$ 60
Throughput volumes (thousand barrels per day) 253
259
(6 )
Throughput margin per barrel (e) (f) $ 9.87
$ 8.14
$ 1.73
Operating costs per barrel:
Operating expenses 5.21
5.08
0.13
Depreciation and amortization expense 2.31
1.62
0.69
Total operating costs per barrel 7.52
6.70
0.82
Operating income per barrel $ 2.35
$ 1.44
$ 0.91

Operating income for regions above $ 3,476
$ 1,481
$ 1,995
Asset impairment loss applicable to refining —
(2 ) 2
Total refining operating income $ 3,476
$ 1,479
$ 1,997

~~_______________~~

~~See note references on page~~ 55.

~~Table of Contents~~

~~Average Market Reference Prices and Differentials (i)~~

~~(dollars per barrel, except as noted)~~

Nine Months Ended September 30,
2011 2010 Change
Feedstocks:
LLS crude oil $ 111.73
$ 79.35
$ 32.38
LLS less WTI 16.34
1.83
14.51
LLS less ANS crude oil 2.44
2.27
0.17
LLS less Brent crude oil (0.82 ) 2.14
(2.96 )
LLS less Mars crude oil 4.05
3.39
0.66
LLS less Maya crude oil 14.58
10.88
3.70
WTI crude oil 95.39
77.52
17.87
WTI less Mars crude oil (12.29 ) 1.56
(13.85 )
WTI less Maya crude oil (1.76 ) 9.05
(10.81 )

Products:
Gulf Coast:
Conventional 87 gasoline less LLS $ 7.43
$ 6.26
$ 1.17
Ultra-low-sulfur diesel less LLS 13.09
8.61
4.48
Propylene less LLS 19.33
7.80
11.53
Conventional 87 gasoline less WTI 23.77
8.09
15.68
Ultra-low-sulfur diesel less WTI 29.43
10.44
18.99
Propylene less WTI 35.67
9.63
26.04
Mid-Continent:
Conventional 87 gasoline less WTI 24.79
8.77
16.02
Ultra-low-sulfur diesel less WTI 30.75
11.06
19.69
North Atlantic:
Conventional 87 gasoline less Brent 6.29
8.33
(2.04 )
Ultra-low-sulfur diesel less Brent 14.04
12.15
1.89
Conventional 87 gasoline less WTI 23.45
8.02
15.43
Ultra-low-sulfur diesel less WTI 31.20
11.84
19.36
West Coast:
CARBOB 87 gasoline less ANS 13.39
14.97
(1.58 )
CARB diesel less ANS 18.56
12.95
5.61
CARBOB 87 gasoline less WTI 27.29
14.53
12.76
CARB diesel less WTI 32.46
12.51
19.95
New York Harbor corn crush (dollars per gallon) 0.17
0.41
(0.24 )

~~_______________~~

~~See note references on page~~ 55.

~~Table of Contents~~

~~Operating Highlights (continued)~~

~~(millions of dollars, except per gallon amounts)~~

Nine Months Ended September 30,
2011 2010 Change
Retail–U.S.: (d)
Operating income $ 165
$ 181
$ (16 )
Company-operated fuel sites (average) 994
990
4
Fuel volumes (gallons per day per site) 5,053
5,115
(62 )
Fuel margin per gallon $ 0.146
$ 0.158
$ (0.012 )
Merchandise sales $ 930
$ 910
$ 20
Merchandise margin (percentage of sales) 28.6 % 28.4 % 0.2 %
Margin on miscellaneous sales $ 66
$ 65
$ 1
Operating expenses $ 312
$ 306
$ 6
Depreciation and amortization expense $ 56
$ 54
$ 2

Retail–Canada: (d)
Operating income $ 133
$ 104
$ 29
Fuel volumes (thousand gallons per day) 3,210
3,131
79
Fuel margin per gallon $ 0.303
$ 0.263
$ 0.040
Merchandise sales $ 197
$ 179
$ 18
Merchandise margin (percentage of sales) 29.6 % 30.3 % (0.7 )%
Margin on miscellaneous sales $ 33
$ 29
$ 4
Operating expenses $ 196
$ 178
$ 18
Depreciation and amortization expense $ 28
$ 26
$ 2

Ethanol (c):
Operating income $ 215
$ 139
$ 76
Production (thousand gallons per day) 3,317
2,943
374
Gross margin per gallon of production (f) $ 0.60
$ 0.54
$ 0.06
Operating costs per gallon of production:

Operating expenses 0.33
0.33
—
Depreciation and amortization expense 0.03
0.04
(0.01 )
Total operating costs per gallon of production 0.36
0.37
(0.01 )
Operating income per gallon of production $ 0.24
$ 0.17
$ 0.07

~~_______________~~

~~See note references on page~~ 55.

~~Table of Contents~~

~~The following notes relate to references on pages~~ 50 ~~through~~ 54.

~~(a)~~

~~The information presented for the nine months ended~~ ~~September 30, 2011~~ ~~includes the results of operations of our Pembroke Refinery, including the related marketing and logistics business, from the date of its acquisition,~~ ~~August 1, 2011, through~~ ~~September 30, 2011. In addition, the refining segment and North Atlantic region operating highlights for the nine months ended~~ ~~September 30, 2011~~ ~~include the Pembroke Refinery.~~

~~(b)~~

In December 2010, we sold our Paulsboro Refinery to PBF Holding Company LLC and in June 2010, we sold our shutdown Delaware City Refinery assets and associated terminal and pipeline assets to PBF Energy Partners LP. The results of operations of these refineries have been presented as discontinued operations for the ~~nine months ended September 30,~~ ~~2010. In addition, the refining segment and North Atlantic region operating highlights exclude these refineries for~~ ~~nine months ended September 30,~~ ~~2010.~~


~~(c)~~	We acquired three ethanol plants in the first quarter of 2010. The information presented includes the results of operations of those plants commencing on their respective acquisition dates. Ethanol production volumes are based on total production during each period divided by actual calendar days per period.


~~(d)~~	~~Credit card transaction processing fees incurred by our retail segment of~~ ~~$68 million~~ ~~for the~~ ~~nine months ended September 30,~~ ~~2010 have been reclassified from retail operating expenses to cost of sales. The Retail–U.S. and Retail–Canada operating highlights for the~~ ~~nine months ended September 30,~~ ~~2010 have been restated to reflect this reclassification.~~

~~(e)~~

~~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 forward sales of refined products. These contracts were closed and realized during the first quarter of 2011. The~~ ~~$542 million~~ ~~loss is reflected in refining segment operating income, resulting in an $0.85 reduction in refining throughput margin per barrel for the~~ ~~nine months ended September 30,~~ 2011, and is allocated to refining operating income by region, excluding the North Atlantic, based on relative throughput volumes for each region as follows: Gulf Coast- $372 million, or $0.96 per barrel; Mid-Continent- $122 million, or $1.11 per barrel; and West Coast- $48 million, or $0.69 per barrel.


~~(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 Gulf Coast region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, St. Charles, Aruba, and Port Arthur Refineries; the Mid-Continent region includes the McKee, Ardmore, and Memphis Refineries; the North Atlantic region includes the Pembroke and Quebec City Refineries; and the West Coast region includes the Benicia and Wilmington Refineries.

~~(i)~~

Average market reference prices for LLS crude oil, along with price differentials between the price of LLS crude oil and other types of crude oil, have been included in the table of Average Market Reference Prices and Differentials. The table also includes price differentials by region between the prices of certain products and the benchmark crude oil that provides the best indicator of product margins for each region. Prior to the first quarter of 2011, feedstock and product differentials presented herein were based on the price of WTI crude oil. However, the price of WTI crude oil no longer provides a reasonable benchmark price of crude oil for all regions. Beginning in late 2010, WTI light-sweet crude oil began to price at a discount to waterborne light-sweet crude oils, such as LLS and Brent, because of increased WTI supplies resulting from greater domestic production and increased deliveries of crude oil from Canada into the Mid-Continent region. Therefore, the use of the price of WTI crude oil as a benchmark price for regions that do not process WTI crude oil is no longer reasonable.

~~General~~

~~Operating revenues increased 52 percent (or~~ ~~$31.2 billion) for the~~ ~~first nine months~~ of ~~2011~~ ~~compared~~ to the first ~~nine months~~ quarter of ~~2010~~2012 ~~primarily as~~even though we reported 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 60,000 barrels per day¹ ($3.0 billion of revenue) from the Pembroke Refinery, which was acquired on August 1, 2011, and throughput of 161,000 barrels per day ($4.2 billion of revenue) from the Aruba Refinery, which restarted operations in January 2011. Operating income increased ~~$2.0 billion~~ ~~and income~~loss from continuing operations before ~~taxes increased~~ ~~$2.1 billion~~ ~~for the~~ ~~first nine months~~ of ~~2011~~ ~~compared to amounts reported for the~~ ~~first nine months~~ of ~~2010~~ ~~primarily due to a~~ ~~$2.0 billion~~ ~~increase in refining segment operating~~ income ~~discussed below.~~

~~_______________~~

¹~~Calculated based on throughput volumes of the Pembroke Refinery from the date of acquisition (August 1, 2011), divided by the number of days during the~~ ~~nine months ended September 30,~~ ~~2011.~~

~~Table of Contents~~

~~Refining~~

~~Refining segment operating income more than doubled (a~~ ~~$2.0 billion~~ ~~increase) from~~ ~~$1.5 billion~~ ~~for the~~ ~~first nine months~~ of ~~2010~~ to ~~$3.5 billion~~ ~~for the~~ ~~first nine months~~ of ~~2011. The~~ ~~$2.0 billion~~ ~~improvement in operating income~~tax expense, which was due to ~~a $2.8 billion increase in refining margin, offset by a $542 million first quarter~~the asset impairment loss ~~on forward sales of refined products and a~~ ~~$217 million~~ ~~increase in operating expenses.~~

The $2.8 billion increase in refining margin was primarily due to a 46 percent increase in throughput margin per barrel (a $3.68 per barrel increase between the comparable periods, consisting of the increase of $~~2.83~~ ~~per barrel adjusted for the $0.85 per barrel impact of the~~ ~~$542~~595 million loss discussed above). This increase in refining margin was largely driven by an improvement in gasoline and distillate margins in most of our refining regions, especially the Mid-Continent and Gulf Coast refining regions, as further explained below.

~~The WTI-based benchmark reference margin for Mid-Continent conventional 87 gasoline was~~ ~~$24.79~~ ~~per barrel for the~~ ~~first nine months~~ of ~~2011, compared to~~ ~~$8.77~~ ~~per barrel for the~~ ~~first nine months~~ of ~~2010, representing a favorable increase of~~ ~~$16.02~~ ~~per barrel. In addition, the WTI-based benchmark reference margin for Mid-Continent ultra-low sulfur diesel (a type of distillate) was~~ ~~$30.75~~ ~~per barrel for the~~ ~~first nine months~~ of ~~2011, compared to~~ ~~$11.06~~ ~~per barrel for the~~ ~~first nine months~~ of ~~2010, representing a favorable increase of~~ ~~$19.69~~ per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $900 million and $800 million, respectively, nine months versus nine months. The increases in the gasoline and distillate benchmark reference margins in the Mid-Continent region are primarily duerelated to the substantial discount in the price of WTI crude oil, the primary type of crude oil processed by our Mid-Continent refineries, versus LLS-type crude oils. Historically, the price of WTI crude oil has tracked LLS crude oil, but dueAruba Refinery. We did not record a tax benefit related to the significant development of crude oil reserves within the Mid-Continent region and increased deliveries of crude oil from Canada into the Mid-Continent region, the increased supply of WTI crude oil has resulted in WTI crude oil currently being priced at a significant discount to LLS crude oil.

~~The LLS-based benchmark reference margin for Gulf Coast conventional 87 gasoline was~~ ~~$7.43~~ ~~per barrel for the~~ ~~first nine months~~ of ~~2011, compared to~~ ~~$6.26~~ ~~per barrel for the~~ ~~first nine months~~ of ~~2010, representing a favorable increase of~~ ~~$1.17~~ ~~per barrel. In addition, the LLS-based benchmark reference margin for Gulf Coast ultra-low sulfur diesel was~~ ~~$13.09~~ ~~per barrel for the~~ ~~first nine months~~ of ~~2011, compared to~~ ~~$8.61~~ ~~per barrel for the~~ ~~first nine months~~ of ~~2010, representing a favorable increase of~~ ~~$4.48~~ per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $200 million and $600 million, respectively, nine months versus nine months. The increases in the gasoline and distillate benchmark reference margins are supported by increased exports of gasoline and distillate as well as an increase in demand for distillates.

In addition, our system benefited from the increase in the discount of the price of heavy sour crude oils as compared to the price of sweet crude oils. For example, Maya crude oil, which is a type of heavy sour crude oil, sold at a discount of ~~$14.58~~ ~~per barrel to LLS crude oil, which is a type of sweet crude oil, during the~~ ~~first nine months~~ of ~~2011. This compares to a discount of~~ ~~$10.88~~ ~~per barrel during the~~ ~~first nine months~~ of ~~2010, representing a favorable increase of~~ ~~$3.70~~ ~~per barrel. We estimate that the increase in the discounts for all types of sour crude oil~~this loss because we do not believe that we ~~process had~~will realize a ~~positive impact to our refining margin of approximately $450 million, nine months versus nine months.~~tax benefit.

~~Table of Contents~~

~~The increase of~~ ~~$217 million~~ ~~in operating expenses discussed above was partially due to $50 million in operating expenses incurred by the Pembroke Refinery, which was acquired on~~ ~~August 1, 2011~~. The remaining increase of operating expenses of $167 million was primarily due to a $58 million increase in maintenance expenses, a $64 million increase in employee-related expenses, and a $76 million increase in chemicals and catalyst costs.

~~Retail~~

~~Retail segment operating income was~~ ~~$298 million~~ ~~for the~~ ~~first nine months~~ of ~~2011~~ ~~compared to~~ ~~$285 million~~ ~~for the~~ ~~first nine months~~ of ~~2010~~. This 5 percent (or $13 million) increase was due to an increase in fuel margins of $23 million primarily from our Canadian operations, including a favorable impact from the strengthening of the Canadian dollar relative to the U.S. dollar, and an increase in merchandise margins of $12 million, offset by increased operating expenses of $24 million.

~~Ethanol~~

~~Ethanol segment operating income was~~ ~~$215 million~~ ~~for the~~ ~~first nine months~~ of ~~2011~~ ~~compared to~~ ~~$139 million~~ ~~for the~~ ~~first nine months~~ of ~~2010. The~~ ~~$76 million~~ ~~increase in operating income was primarily due to a $113 million increase in gross margin, partially offset by a~~ ~~$35 million~~ ~~increase in operating expenses.~~

~~Gross margin increased from the~~ ~~first nine months~~ of ~~2010~~ ~~to the~~ ~~first nine months~~ of ~~2011~~ ~~due to an increase in ethanol production (a~~ ~~374,000~~ gallon per day increase between the comparable periods) primarily resulting from the full operation of three additional plants acquired in the first quarter of 2010 and higher utilization rates and increased yields during ~~2011~~ ~~combined with a $0.06 per gallon increase in the ethanol gross margin .~~

~~The increase in operating expenses was primarily due to $25 million of additional expenses related to the operation of the three ethanol plants we acquired in the first quarter of~~ ~~2010~~ ~~for a full~~ ~~nine~~ ~~months in~~ ~~2011~~.

~~Corporate Expenses and Other~~

~~General and administrative expenses increased~~ ~~$75 million~~ ~~from the~~ ~~first nine months~~ of ~~2010~~ ~~to the~~ ~~first nine months~~ of ~~2011~~ due to a $16 million increase in variable compensation expense, $23 million in costs incurred in connection in with the Pembroke Acquisition, and a favorable settlement with an insurance company for $40 million recorded in the first quarter of 2010, which reduced general and administration expenses in that period.

~~“Interest and debt expense, net of capitalized interest” for the~~ ~~first nine months~~ of ~~2011~~ ~~decreased $51 million from the~~ ~~first nine months~~ of ~~2010~~. This decrease is primarily due to an increase of $34 million in capitalized interest due to a corresponding increase in capital expenditures between the nine-month periods and the resumption of construction activity on previously suspended projects combined with favorable impacts from the decrease in average borrowings of $12 million and the decrease in average interest rates of $3 million.

~~Income tax expense increased~~ ~~$757 million~~ ~~from the~~ ~~first nine months~~ of ~~2010~~ ~~to the~~ ~~first nine months~~ of ~~2011~~ ~~mainly as a result of higher operating income in 2011 and the nonrecurrence of a $20 million income tax benefit recognized in 2010 related to a tax settlement with the Government of Aruba.~~

~~The loss from discontinued operations of~~ ~~$7 million~~ ~~for the~~ ~~first nine months~~ of ~~2011~~ ~~primarily represents adjustments to the working capital settlement related to the sale of our Paulsboro Refinery in December 2010. The income from discontinued operations of~~ ~~$19 million~~ ~~for the~~ ~~first nine months~~ of ~~2010~~ represents a $58 million after-tax gain on the sale of the shutdown refinery assets at Delaware City, offset by a $39 million loss from the discontinued operations of the Delaware City and Paulsboro Refineries.

5745

Table of Contents

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, ~~2011~~2012 and ~~2010~~2011

Net cash provided by operating activities for the first ~~nine~~three months of 2012 was $1.7 billion compared to $2.1 billion for the first three months of 2011 ~~was~~ ~~$4.3 billion~~ ~~compared to~~ ~~$2.6 billion~~ ~~for the first~~ ~~nine~~ ~~months of~~ ~~2010~~. The ~~increase~~decrease in cash generated from operating activities was primarily due to a $~~248~~540 million ~~favorable~~unfavorable effect from changes in working capital between the ~~periods, combined with the~~ ~~$2.0 billion~~ ~~increase in operating income discussed above under “RESULTS OF OPERATIONS.”~~periods. Changes in cash provided by or used for working capital during the first ~~nine~~three months of ~~2011~~2012 and ~~2010~~2011 are shown in Note 11 of Condensed Notes to Consolidated Financial Statements.

The net cash provided by operating activities during the first ~~nine~~three months of ~~2011~~2012 ~~combined with~~ ~~$505 million~~ ~~from available cash on hand were~~was used mainly to:

fund $~~2.1 billion~~884 million 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~~a repayment under our accounts receivable sales facility of $~~418~~150 million ~~and acquire the Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds) for~~ ~~$300 million~~;

~~purchase our common stock for~~ ~~$270 million; and~~

pay common stock dividends of $8583 million; and

increase available cash on hand by $535 million.

The net cash provided by operating activities during the first ~~nine~~three months of ~~2010, combined with~~ ~~$1.2 billion~~2011 ~~of net proceeds from the issuance of~~ ~~$400 million~~ ~~of 4.50% notes due in February 2015 and~~ ~~$850 million~~ ~~of 6.125% notes due in February 2020 as discussed in~~ ~~Note 5~~ ~~of Condensed Notes to Consolidated Financial Statements, and~~ ~~$220 million~~ ~~of proceeds from the sale of the Delaware City Refinery assets and associated terminal and pipeline assets as discussed in~~ ~~Note 2~~ ~~of Condensed Notes to Consolidated Financial Statements, were~~was used mainly to:

fund $~~1.6 billion~~737 million of capital expenditures and deferred turnaround and catalyst costs;

~~redeem our 7.50% senior notes~~make a scheduled long-term note repayment of $210 million and acquire the Gulf Opportunity Zone Revenue Bonds Series 2010 for $~~294 million~~ ~~and our 6.75% senior notes for~~ ~~$190 million~~;

~~make scheduled long-term note repayments of $33 million;~~

~~make repayments under our accounts receivable sales facility of~~ ~~$100 million~~;

~~purchase additional ethanol plants for~~ ~~$260~~300 million;

pay common stock dividends of $8528 million; and

increase available cash on hand by $~~1.5 billion~~799 million.

Cash flows related to the discontinued operations of the Paulsboro and Delaware City Refineries have been combined with the cash flows from continuing operations within each category in the consolidated statements of cash flows for the ~~nine months ended September 30,~~ ~~2010 and are summarized as follows (in millions):~~

Cash provided by (used in) operating activities:
Paulsboro Refinery $ 42
Delaware City Refinery (76 )
Cash used in investing activities:
Paulsboro Refinery (32 )
Delaware City Refinery —

~~Table of Contents~~

Capital Investments

Our operations, especially those of our refining segment, are highly capital intensive. Each of our refineries ~~is comprised of~~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 continuously improved. Improvements consist of the addition of new Units and betterments of existing Units, and the cost of these improvements is 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 ~~further~~ refine crude oil into products with higher market values. Therefore, many of our improvements do not increase throughput capacity significantly.

During the ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012, we expended $~~1.6 billion~~726 million for capital expenditures ~~primarily related to improvements to our refineries. We also expended~~and $~~501~~158 million for deferred turnaround and catalyst costs. Capital expenditures for the ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012 included ~~$168~~$22 million of costs related to environmental projects.

For ~~2011~~2012, we expect to incur ~~$3.2~~approximately $3.0 billion for capital investments ~~including $2.5 billion~~(approximately $135 million of which is for ~~capital expenditures primarily related to improvements to our refineries~~environmental projects) and ~~$650~~$510 million for deferred turnaround and catalyst costs. The ~~$2.5 billion for~~ capital ~~expenditures includes $250 million for environmental projects, but~~expenditure estimate excludes expenditures related to strategic business acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.

Table of Contents

Contractual Obligations

As of ~~September 30, 2011~~March 31, 2012, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities.

During the ~~nine~~three months ended ~~September 30, 2011~~March 31, 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; however, we made the following debt repayments:~~liabilities.

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% of their outstanding stated values.

~~in May 2011,~~In April 2012, we made a scheduled debt ~~repayment~~repayments of $4 million related to our Series 1997A 5.45% industrial revenue bonds and $~~200~~750 million related to our ~~6.125%~~6.875% ~~senior notes;~~notes.

We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables. This facility matures in ~~April 2011,~~June 2012. During the three months ended March 31, 2012, we ~~made scheduled debt repayments~~repaid $150 million under this facility. As of March 31, 2012, the amount of eligible receivables sold was $8100 million ~~related to our Series A~~. In late April 2012, we sold ~~5.45%, Series B~~ ~~5.40%, and Series C~~ ~~5.40%~~ ~~industrial revenue bonds;~~

~~in February 2011, we made a scheduled debt repayment of~~ $~~210~~850 million ~~related~~of eligible receivables to ~~our~~the third-party entities and financial institutions under this facility, and we repaid ~~6.75%~~ ~~senior notes; and~~

~~in February 2011, we paid~~ $~~300~~500 million ~~to acquire the GO Zone Bonds, which were subject to mandatory tender.~~on

May 4, 2012.

~~Table of Contents~~

Our agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt to below investment grade ratings by Moody’s Investors Service, ~~and~~ Standard & Poor’s Ratings Services, and Fitch Ratings, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. As of ~~November 9, 2011~~March 31, 2012, all of our ratings on our senior unsecured debt are at or above investment grade level as follows:



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

Table of Contents

Other Commercial Commitments

As of ~~September 30, 2011~~March 31, 2012, our committed lines of credit were as follows (in millions):

Borrowing

Capacity

Expiration

Outstanding Letters of Credit

Borrowing

Capacity

Expiration

Outstanding

Letters of

Credit

Letter of credit facility

$200

June 2012

$—

Letter of credit facility

$300

June 2012

$300

Letter of credit facilities

$500

June 2012

$500

Revolving credit facility

$2,400

November 2012

$74

$3,000

December 2016

$153

Canadian revolving credit facility

C$115

December 2012

C$20

C$115

December 2012

C$20

As of ~~September 30, 2011~~March 31, 2012, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of ~~September 30, 2011~~March 31, 2012 expire during ~~2011~~2012 and ~~2012.~~2013.

Other Matters Impacting Liquidity and Capital Resources

~~Meraux Acquisition~~

On ~~October 1, 2011, we acquired the Meraux Refinery and related logistics assets for an initial payment of~~ ~~$586 million, including inventories of~~ ~~$261 million~~, from Murphy Oil Corporation. The purchase price was funded from available cash. We expect to receive a favorable adjustment related to inventories in the fourth quarter of 2011 that will reduce the purchase price by approximately ~~$40 million~~.

~~Contributions to~~ Pension ~~Plans~~Plan Funded Status

We have no minimum required contributions of $2 million during 2012 to our pension plans that have minimum funding requirements; however, we plan to contribute approximately $100 million to our pension plans during ~~2011 under the Employee Retirement Income Security Act. However, we contributed~~ ~~$207 million~~2012. We made no significant contributions to our pension plans in the first ~~nine~~three months of ~~2011.~~2012.

~~Table of Contents~~

Stock Purchase Programs

As of ~~September 30, 2011~~March 31, 2012, we have approvals under common stock purchase programs to purchase approximately $3.5 billion of our common stock.

Environmental Matters

WeOur operations are subject to extensive ~~federal, state, and local~~ environmental ~~laws and~~ regulations ~~including those~~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 ~~refineries~~operating facilities could require material additional expenditures to comply with environmental laws and regulations.

~~The U.S. Environmental Protection Agency (EPA) began regulating greenhouse gases on January 2, 2011, under the Clean Air Act Amendments~~ See Note 6 of ~~1990 (Clean Air Act). According~~Condensed Notes to ~~statements by the EPA, any new construction or material expansions will require that, among other things,~~Consolidated Financial Statements for 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 will be on a case by case basis, and the EPA has provided only general guidance on which controls will be required. Any such controls, however, could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

In addition, certain states and foreign governments have pursued independent regulation of greenhouse gases. 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. 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 is effective in 2011, with small reductions in the carbon intensity of transportation fuels sold in California. The mandated reductions in carbon intensity are scheduled to increase through 2020, after which another step-change in reductions is anticipated. The LCFS is designed to encourage substitution of traditional petroleum fuels, and, over time, it is anticipated that the LCFS will lead to a greater use of electric cars and alternative fuels, such as E85, as companies seek to generate more credits to offset petroleum fuels. The statewide cap-and-trade program will begin in 2013. 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, but we expect that compliance costs will increase significantly beginning in 2015, when 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.

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On June 30, 2010, the EPA formally disapproved the flexible permits program submitted by the Texas Commission on Environmental Quality (TCEQ) in 1994 for inclusion in its clean-air implementation plan. The EPA determined that Texas’ flexible permit program did not meet several requirements under the federal Clean Air Act. Our Port Arthur, Texas City, Three Rivers, McKee, and Corpus Christi East and West Refineries formerly operated under flexible permits administered by the TCEQ. In the fourth quarter of 2010, we completed the conversionfurther discussion of our flexible permits into federally enforceable conventional state NSR permits (“de-flexed permits”). We are now in the process of incorporating these de-flexed permits into our Title V permits. Continued discussions with the TCEQ and the EPA regarding this matter are likely.

~~Meanwhile, the EPA has formally disapproved other TCEQ permitting programs that historically have streamlined the~~ environmental permitting process in Texas. For example, the EPA has disapproved the TCEQ pollution control standard permit, thus requiring conventional permitting for future pollution control equipment. Litigation is pending from industry groups and others against the EPA for each of these actions. The EPA has also objected to numerous Title V permits in Texas and other states, including permits at our Port Arthur, Corpus Christi East, and McKee Refineries. Environmental activist groups have filed a notice of intent to sue the EPA, seeking to require the EPA to assume control of these permits from the TCEQ. 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. But 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.matters.

Tax Matters

As of March 31, 2012, the Internal Revenue Service (IRS) has ongoing tax audits related to our U.S. federal tax returns from 2002 through 2009, as discussed in Note 6 of Condensed Notes to Consolidated Financial Statements. We have received Revenue Agent Reports on our tax years for 2002 through 2007 and we are vigorously contesting the 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

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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 March 31, 2012, $773 million 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). ~~The~~Key provisions of the Wall Street Reform Act ~~among many things, creates~~create new ~~regulations for companies~~statutory requirements that ~~extend credit to consumers and requires~~require most derivative instruments to be traded on exchanges and routed through ~~clearinghouses. Rules to implement~~clearinghouses, as well as impose new recordkeeping and reporting responsibilities on market participants. Final rules implementing the Wall Street Reform Act are ~~being finalized and~~expected to become effective mid-2012; therefore, the impact to our operations is ~~not~~ yet ~~known.~~unknown. However, the implementation could result in higher margin ~~requirements,~~environments, 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.

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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.

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CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with ~~United States~~U. S. generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported in ~~the consolidated~~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, ~~2010~~2011, except for the addition of the policy reflected below regarding the accounting for our property, plant and equipment, including the manner in which we estimate the useful lives of such assets, which we have identified as a critical accounting policy..

~~Property, Plant and Equipment~~

The cost of property, plant and equipment (property assets) purchased or constructed, including betterments of property assets, are capitalized. The cost of repairs to and normal maintenance of property assets, however, is expensed as incurred. Betterments of property assets are those which either extend the useful life, increase the capacity or improve the operating efficiency of the asset, or improve the safety of our operations. The cost of property assets constructed includes interest and certain overhead costs allocable to the construction activities.

Our operations, especially those of our refining segment, are highly capital intensive. Each of our refineries is comprised of 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 continuously improved. Improvements consist of the addition of new Units and betterments of existing Units. We plan for these improvements by developing a multi-year capital program that is updated and revised based on changing internal and external factors.

Depreciation of our property assets is recorded on a straight-line basis over the estimated useful lives of these assets primarily using the composite method of depreciation. We maintain a separate composite group of property assets for each of our 15 refineries. We estimate the useful life of each group based on an evaluation of the property assets comprising the group, and such evaluations consist of, but are not limited to, the physical inspection of the assets to determine their condition, consideration of the manner in which the assets are maintained, assessment of the need to replace assets, and evaluation of the manner in which improvements impact the useful life of the group. The estimated useful lives of our composite groups range primarily from 25 to 30 years.

Under the composite method of depreciation, the cost of an improvement is added to the composite group to which it relates and is depreciated over that group’s estimated useful life. We design improvements to our refineries in accordance with engineering specifications, design standards and practices accepted in our industry, and these improvements have design lives consistent with our estimated useful lives. Therefore, we believe the use of the group life to depreciate the cost of improvements made to the group is reasonable because the estimated useful life of each improvement is consistent with that of the group. It should be noted, however, that factors such as competition, regulation, or environmental matters could cause us to change our estimates, thus impacting depreciation expense in the future.

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Also under the composite method of depreciation, the historical cost of a minor property asset (net of salvage value) that is retired or replaced is charged to accumulated depreciation and no gain or loss is recognized in income. However, a gain or loss is recognized in income for a major property asset that is retired, replaced or sold and for an abnormal disposition of a property asset (primarily involuntary conversions). Gains and losses are reflected in depreciation and amortization expense, unless such amounts are reported separately due to materiality.


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks related to the volatility in the price of commodities, interest rates and foreign currency exchange rates, and we enter into derivative instruments to manage those risks. We also enter into derivative instruments to manage the price risk on other contractual derivatives into which we have entered. The only types of derivative instruments we enter into are those related to the various commodities we purchase or produce, interest rate swaps, and foreign currency exchange and purchase contracts, as described below. All derivative instruments are recorded on our consolidated balance sheets as either assets or liabilities measured at their fair values.

COMMODITY PRICE RISK

inventories and firm commitments to purchase inventories generally for amounts by which our current year ~~LIFO~~ 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, ~~and~~ 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.

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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						Derivative Instruments Held For
	Non-Trading Purposes			Trading Purposes			Non-Trading Purposes			Trading Purposes
September 30, 2011:
Gain (loss) in fair value due to:
March 31, 2012:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	$	(56	)	$	—		$	(255	)	$	(3	)
10% decrease in underlying commodity prices	56			—			255			7

December 31, 2010:
Gain (loss) in fair value due to:
December 31, 2011:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	(199		)	—			(156		)	1
10% decrease in underlying commodity prices	189			(1		)	156			2

See Note 13 of Condensed Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of ~~September 30, 2011~~March 31, 2012.

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 March 31, 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 March 31, 2012.

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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, 2011~~March 31, 2012 or December 31, ~~2010~~2011.


	September 30, 2011																							March 31, 2012
	Expected Maturity Dates																							Expected Maturity Dates
	2011			2012			2013			2014			2015			There- after			Total			Fair Value		2012			2013			2014			2015			2016			There- after			Total			Fair Value
Debt (excluding capital lease obligations):
Debt:
Fixed rate	$	—		$	759		$	489		$	209		$	484		$	5,605		$	7,546		$	9,065	$	862		$	480		$	200		$	475		$	—		$	5,474		$	7,491		$	8,553
Average interest rate	—		%	6.9		%	5.5		%	4.8		%	5.2		%	7.2		%	6.9		%			6.7		%	5.5		%	4.8		%	5.2		%	—		%	7.3		%	6.9		%
Floating rate	$	—		$	104		$	—		$	—		$	—		$	—		$	104		$	104	$	100		$	—		$	—		$	—		$	—		$	—		$	100		$	100
Average interest rate	—		%	0.7		%	—		%	—		%	—		%	—		%	0.7		%			0.6		%	—		%	—		%	—		%	—		%	—		%	0.6		%

	December 31, 2010																							December 31, 2011
	Expected Maturity Dates																							Expected Maturity Dates
	2011			2012			2013			2014			2015			There- after			Total			Fair Value		2012			2013			2014			2015			2016			There- after			Total			Fair Value
Debt (excluding capital lease obligations):
Debt:
Fixed rate	$	418		$	759		$	489		$	209		$	484		$	5,605		$	7,964		$	9,092	$	754		$	484		$	200		$	475		$	—		$	5,578		$	7,491		$	9,048
Average interest rate	6.4		%	6.9		%	5.5		%	4.8		%	5.2		%	7.2		%	6.9		%			6.9		%	5.5		%	4.8		%	5.2		%	—		%	7.3		%	6.9		%
Floating rate	$	400		$	—		$	—		$	—		$	—		$	—		$	400		$	400	$	250		$	—		$	—		$	—		$	—		$	—		$	250		$	250
Average interest rate	0.5		%	—		%	—		%	—		%	—		%	—		%	0.5		%			0.6		%	—		%	—		%	—		%	—		%	—		%	0.6		%

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FOREIGN CURRENCY RISK

We are exposed to exchange rate fluctuations on transactions entered into by our Canadian and European 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. As of ~~September 30, 2011~~March 31, 2012, we had commitments to purchase $~~475~~565 million of U.S. dollars and C$65 million of Canadian dollars. Our market risk was minimal on these contracts, as ~~they~~the majority of which matured on or before ~~October 28, 2011~~April 30, 2012, resulting in a loss of approximately $173 million ~~loss~~ in the ~~fourth~~second quarter of ~~2011.~~2012.

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, 2011~~March 31, 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.

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PART II – OTHER INFORMATION


Item 1.	Legal Proceedings

The information below describes new proceedings or material developments in proceedings that we previously reported in our annual report on Form 10-K for the year ended December 31, ~~2010~~2011~~, or our quarterly reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.~~.

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 (Port Arthur Refinery). In our annual report on Form 10-K for the year ended December 31, 2011, we disclosed that our Port Arthur Refinery expected the EPA to assess penalties for a flaring event that occurred at the refinery in 2011. Potential stipulated penalties payable to the EPA under the consent decree for this event are $4.7 million. In March 2012, the Texas Commission on Environmental Quality (TCEQ) also issued a notice of enforcement (NOE) for this and another flaring event that occurred at the refinery in 2011. The TCEQ has not stated a penalty amount in the NOE, although we reasonably believe the amount will be in excess of $100,000.

EPA ~~(McKee~~(Three Rivers Refinery). In our ~~quarterly~~annual report on Form ~~10-Q~~10-K for the ~~quarter~~year ended ~~June 30,~~December 31, 2011, we disclosed that our ~~McKee~~Three Rivers Refinery ~~had~~expected the EPA to assess penalties for a flaring event that occurred at the refinery in 2011. Potential stipulated penalties payable to the EPA under the consent decree for this event are $522,500. In April 2012, the TCEQ also issued an NOE for this event. The TCEQ has not stated a penalty amount in the NOE, although we reasonably believe the amount will be in excess of $100,000.

TCEQ (Port Arthur Refinery). In March 2012, our Port Arthur Refinery received a proposed agreed order from the TCEQ ~~relating to alleged violations noted during an annual air compliance inspection. In the third quarter of 2011, we settled this matter with the TCEQ.~~

~~TCEQ~~ ~~(Three Rivers Refinery). In September 2011, our Three Rivers Refinery received a proposed agreed order~~ that assesses a penalty of ~~$192,663~~$180,911 for various alleged air emission and reporting violations. We ~~believe that we have several defenses to the allegations and~~ are working with the TCEQ to settle this matter.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, ~~2010~~2011.

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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 2011 9,560
$ 26.35
9,560
—
$3.46 billion
August 2011 10,597,275
$ 19.90
10,597,275
—
$3.46 billion
September 2011 2,936,270
$ 19.27
2,936,270
—
$3.46 billion
Total 13,543,105
$ 19.77
13,543,105
—
$3.46 billion



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)
January 2012	1,805,513	$	20.91	1,805,513	—	$3.46 billion
February 2012	2,232,661	$	25.11	2,232,661	—	$3.46 billion
March 2012	489,527	$	24.42	489,527	—	$3.46 billion
Total	4,527,701	$	23.36	4,527,701	—	$3.46 billion

(a)

The shares reported in this column represent purchases settled in the ~~third~~first quarter of 2011 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 and Ratios of Earnings to Fixed Charges and Preferred Stock Dividends.~~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 9, 2011~~May 8, 2012

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Current assets, net of cash acquired	$	2,217
Property, plant and equipment	777
Deferred charges and other assets	17
Intangible assets	50
Current liabilities, less current portion of debt and capital lease obligations	(1,294		)
Debt and capital leases assumed, including current portion	(12		)
Other long-term liabilities	(77		)
Noncontrolling interest	(3		)
Purchase price, net of cash acquired	$	1,675



	Three Months Ended September 30, 2010			Nine Months Ended September 30, 2010
Operating revenues	$	1,195		$	3,559
Loss before income taxes	(18		)	(36		)



Cash provided by (used in) operating activities:
Paulsboro Refinery	$	42
Delaware City Refinery	(76		)
Cash used in investing activities:
Paulsboro Refinery	(32		)
Delaware City Refinery	—



	2011					2010
	Investments of Nonqualified Benefit Plans		Other Investments			Investments of Nonqualified Benefit Plans		Other Investments
Three months ended September 30:
Balance at beginning of period	$	11	$	—		$	10	$	—
Purchases	—		5			—		—
Total losses included in earnings	—		(5		)	—		—
Transfers in and/or out of Level 3	—		—			—		—
Balance at end of period	$	11	$	—		$	10	$	—
The amount of total losses included in earnings attributable to the change in unrealized losses relating to assets still held at end of period	$	—	$	(5	)	$	—	$	—

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



Derivatives in Fair Value Hedging Relationships	Location	Gain or (Loss) Recognized in Income on Derivatives				Gain or (Loss) Recognized in Income on Hedged Item						Gain or (Loss) Recognized in Income for Ineffective Portion of Derivative
Derivatives in Fair Value Hedging Relationships	Location	2011		2010		2011			2010			2011			2010
Three months ended September 30:
Commodity contracts	Cost of sales	$	170	$	54	$	(161	)	$	(56	)	$	9		$	(2	)
Nine months ended September 30:
Commodity contracts	Cost of sales	219		253		(222		)	(247		)	(3		)	6



Derivatives in Cash Flow Hedging Relationships	Gain or (Loss) Recognized in OCI on Derivatives (Effective Portion)					Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)					Gain or (Loss) Recognized in Income on Derivatives (Ineffective Portion)
Derivatives in Cash Flow Hedging Relationships	2011		2010			Location	2011		2010		Location	2011		2010
Three months ended September 30:
Commodity contracts	$	20	$	—		Cost of sales	$	—	$	37	Cost of sales	$	4	$	—
Nine months ended September 30:
Commodity contracts	20		(2		)	Cost of sales	—		135		Cost of sales	4		—