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 ~~March 31,~~June 30, 2013



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

Commission File Number 1-13175

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)



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

One Valero Way

San Antonio, Texas

(Address of principal executive offices)

78249

(Zip Code)

(210) 345-2000

(Registrant’s telephone number, including area code)

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

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

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



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

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

Yes o No R

The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of ~~April 30,~~July 31, 2013 was ~~545,365,570~~542,142,749.

VALERO ENERGY CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS




	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of ~~March 31,~~June 30, 2013 and December 31, 2012	1
Consolidated Statements of Income for the Three and Six Months Ended ~~March 31,~~ June 30, 2013 and 2012	2
Consolidated Statements of Comprehensive Income for the Three and Six Months Ended ~~March 31,~~ June 30, 2013 and 2012	3
Consolidated Statements of Cash Flows for the ~~Three~~Six Months Ended ~~March 31,~~ June 30, 2013 and 2012	4
Condensed Notes to Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	3435
Item 3. Quantitative and Qualitative Disclosures About Market Risk	5158
Item 4. Controls and Procedures	5360
PART II – OTHER INFORMATION
Item 1. Legal Proceedings	5360
Item 1A. Risk Factors	5361
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	5461
Item 6. Exhibits	5461
SIGNATURE	5562

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)


	March 31, 2013			December 31, 2012			June 30, 2013			December 31, 2012
	(Unaudited)						(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	1,857		$	1,723		$	2,398		$	1,723
Receivables, net	7,658			8,167			7,486			8,167
Inventories	6,937			5,973			6,446			5,973
Income taxes receivable	90			169			56			169
Deferred income taxes	280			274			246			274
Prepaid expenses and other	384			154			136			154
Total current assets	17,206			16,460			16,768			16,460
Property, plant and equipment, at cost	34,470			34,132			33,087			34,132
Accumulated depreciation	(8,072		)	(7,832		)	(7,701		)	(7,832		)
Property, plant and equipment, net	26,398			26,300			25,386			26,300
Intangible assets, net	203			213			159			213
Deferred charges and other assets, net	1,694			1,504			1,864			1,504
Total assets	$	45,501		$	44,477		$	44,177		$	44,477
LIABILITIES AND EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	406		$	586		$	303		$	586
Accounts payable	9,821			9,348			9,507			9,348
Accrued expenses	761			590			504			590
Taxes other than income taxes	1,314			1,026			1,239			1,026
Income taxes payable	15			1			85			1
Deferred income taxes	388			378			397			378
Total current liabilities	12,705			11,929			12,035			11,929
Debt and capital lease obligations, less current portion	6,463			6,463			6,261			6,463
Deferred income taxes	6,131			5,860			6,159			5,860
Other long-term liabilities	1,784			2,130			1,697			2,130
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	7,245			7,322			7,237			7,322
Treasury stock, at cost; 125,469,048 and 121,406,520 common shares	(6,605		)	(6,437		)
Treasury stock, at cost; 131,412,237 and 121,406,520 common shares							(6,818		)	(6,437		)
Retained earnings	17,575			17,032			17,593			17,032
Accumulated other comprehensive income	121			108
Accumulated other comprehensive income (loss)							(99		)	108
Total Valero Energy Corporation stockholders’ equity	18,343			18,032			17,920			18,032
Noncontrolling interests	75			63			105			63
Total equity	18,418			18,095			18,025			18,095
Total liabilities and equity	$	45,501		$	44,477		$	44,177		$	44,477

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Millions of Dollars, Except Per Share Amounts)

(Unaudited)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012			2013			2012
Operating revenues ~~(a)~~	$	33,474		$	35,167		$	34,034		$	34,662		$	67,508		$	69,829
Costs and expenses:
Cost of sales	30,685			33,035			31,523			31,621			62,208			64,656
Operating expenses:
Refining	876			964			906			868			1,782			1,832
Retail	169			166			57			170			226			336
Ethanol	77			87			102			85			179			172
General and administrative expenses	176			164			233			171			409			335
Depreciation and amortization expense	430			384			405			386			835			770
Asset impairment losses	—			611			—			—			—			611
Total costs and expenses	32,413			35,411			33,226			33,301			65,639			68,712
Operating income (loss)	1,061			(244		)
Other income, net	14			6
Operating income							808			1,361			1,869			1,117
Other income (expense), net							11			(5		)	25			1
Interest and debt expense, net of capitalized interest	(83		)	(99		)	(78		)	(74		)	(161		)	(173		)
Income (loss) before income tax expense	992			(337		)
Income before income tax expense							741			1,282			1,733			945
Income tax expense	340			95			276			452			616			547
Net income (loss)	652			(432		)
Net income							465			830			1,117			398
Less: Net loss attributable to noncontrolling interests	(2		)	—			(1		)	(1		)	(3		)	(1		)
Net income (loss) attributable to Valero Energy Corporation stockholders	$	654		$	(432	)
Net income attributable to Valero Energy Corporation stockholders							$	466		$	831		$	1,120		$	399

Earnings per common share	$	1.18		$	(0.78	)	$	0.86		$	1.50		$	2.04		$	0.72
Weighted-average common shares outstanding (in millions)	550			551			543			550			546			550

Earnings per common share – assuming dilution	$	1.18		$	(0.78	)	$	0.85		$	1.50		$	2.03		$	0.72
Weighted-average common shares outstanding – assuming dilution (in millions)	556			551			548			555			552			556

Dividends per common share	$	0.20		$	0.15		$	0.20		$	0.15		$	0.40		$	0.30
____________________________________
Supplemental information:
(a) Includes excise taxes on sales by our U.S. retail system	$	236		$	234

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012			2013			2012
Net income (loss)	$	652		$	(432	)
Net income							$	465		$	830		$	1,117		$	398

Other comprehensive income (loss):
Foreign currency translation adjustment	(204		)	123			(64		)	(91		)	(268		)	32

Pension and other postretirement benefits:
Gain arising during the period related to remeasurement due to plan amendments	328			—			—			—			328			—
(Gain) loss reclassified into income related to:
Net actuarial loss	14			8			15			9			29			17
Prior service credit	(6		)	(4		)	(9		)	(6		)	(15		)	(10		)
Net gain on pension and other postretirement benefits	336			4			6			3			342			7

Derivative instruments designated and qualifying as cash flow hedges:
Net gain arising during the period	1			47
Net gain reclassified into income	(3		)	(48		)
Net gain (loss) arising during the period							(10		)	(31		)	(9		)	16
Net (gain) loss reclassified into income							8			12			5			(36		)
Net loss on cash flow hedges	(2		)	(1		)	(2		)	(19		)	(4		)	(20		)

Other comprehensive income, before income tax expense	130			126
Income tax expense related to items of other comprehensive income	117			1
Other comprehensive income	13			125
Other comprehensive income (loss), before income tax expense (benefit)							(60		)	(107		)	70			19
Income tax expense (benefit) related to items of other comprehensive income (loss)							1			(5		)	118			(4		)
Other comprehensive income (loss)							(61		)	(102		)	(48		)	23

Comprehensive income (loss)	665			(307		)
Comprehensive income							404			728			1,069			421
Less: Comprehensive loss attributable to noncontrolling interests	(2		)	—			(1		)	(1		)	(3		)	(1		)
Comprehensive income (loss) attributable to Valero Energy Corporation stockholders	$	667		$	(307	)
Comprehensive income attributable to Valero Energy Corporation stockholders							$	405		$	729		$	1,072		$	422

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

(Unaudited)


	Three Months Ended March 31,						Six Months Ended June 30,
	2013			2012			2013			2012
Cash flows from operating activities:
Net income (loss)	$	652		$	(432	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net income							$	1,117		$	398
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	430			384			835			770
Asset impairment losses	—			611			—			611
Noncash interest expense and other income, net	1			7			1			11
Stock-based compensation expense	12			10			25			20
Deferred income tax expense	173			61			341			480
Changes in current assets and current liabilities	255			903			444			565
Changes in deferred charges and credits and other operating activities, net	26			—			51			(21		)
Net cash provided by operating activities	1,549			1,544			2,814			2,834
Cash flows from investing activities:
Capital expenditures	(577		)	(726		)	(1,211		)	(1,420		)
Deferred turnaround and catalyst costs	(287		)	(158		)	(449		)	(264		)
Proceeds from the sale of the Paulsboro Refinery	—			160			—			160
Minor acquisitions							—			(66		)
Other investing activities, net	4			10			(23		)	9
Net cash used in investing activities	(860		)	(714		)	(1,683		)	(1,581		)
Cash flows from financing activities:
Non-bank debt:
Borrowings							—			300
Repayments							(480		)	(862		)
Bank credit agreements:
Borrowings							—			1,100
Repayments	(180		)	—			—			(1,100		)
Accounts receivable sales program:
Proceeds from the sale of receivables							—			1,300
Repayments	—			(150		)	—			(1,450		)
Purchase of common stock for treasury	(304		)	(106		)	(560		)	(147		)
Proceeds from the exercise of stock options	38			9			43			11
Common stock dividends	(111		)	(83		)	(220		)	(166		)
Contributions from noncontrolling interest	13			11
Contributions from noncontrolling interests							45			25
Separation of retail business:
Proceeds from short-term debt							550			—
Cash distributed to Valero by CST Brands, Inc.							500			—
Cash held and retained by CST Brands, Inc. upon separation							(315		)	—
Other financing activities, net	22			—			24			(2		)
Net cash used in financing activities	(522		)	(319		)	(413		)	(991		)
Effect of foreign exchange rate changes on cash	(33		)	24			(43		)	9
Net increase in cash and temporary cash investments	134			535			675			271
Cash and temporary cash investments at beginning of period	1,723			1,024			1,723			1,024
Cash and temporary cash investments at end of period	$	1,857		$	1,559		$	2,398		$	1,295

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

These unaudited financial statements have been prepared in accordance with United States (U.S.) generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the three and ~~three~~six months ended ~~March 31,~~June 30, 2013 and 2012 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited financial statements. Operating results for the three and ~~three~~six months ended ~~March 31,~~June 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.

The balance sheet as of December 31, 2012 has been derived from our audited financial statements as of that date. For further information, refer to our financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2012.

Significant Accounting Policies

Use of Estimates

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

Comprehensive Income

In February 2013, the provisions of Accounting Standards Codification (ASC) ~~ASC~~ Topic 220, “Comprehensive Income,” were amended to require an entity to disclose information about the amounts reclassified out of accumulated other comprehensive income ~~by component. For amounts~~and into net income. An entity is required to bepresent information on the face of the statement of income or in the notes to the financial statements about the effects on net income from significant amounts reclassified out of accumulated other comprehensive income if those amounts were required to be reclassified into net income in their entirety in the same reporting period ~~the guidance requires entities~~they were initially charged to ~~present~~other comprehensive income. For other significant amounts ~~by the respective line items of~~that were not required to be reclassified into net income ~~either on~~in their entirety in the ~~face of the~~same reporting period they were initially charged to other comprehensive income, ~~statement or~~a cross-reference is required in the notes to the financial ~~statements. For other amounts that are not required~~statements to ~~be reclassified to net income in their entirety, a cross-reference is required to other~~the disclosures that provide additional details about those amounts. These provisions ~~are~~were effective for interim and annual reporting periods beginning after December 15, 2012. The adoption of this guidance effective January 1, 2013 did not affect our financial position or results of operations, but ~~did result~~resulted in additional disclosures, which are included in Note 7.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Balance Sheet Offsetting Arrangements

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. In January 2013, the provisions of ASC Topic 210 were further amended to clarify that the scope of the previous amendment only applies to

~~Table of Contents~~

~~VALERO ENERGY CORPORATION AND SUBSIDIARIES~~

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

derivative instruments, including bifurcated derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either eligible for offset in the balance sheet or are subject to an agreement similar to a master netting agreement. The guidance requires entities to disclose both gross information and net information about assets and liabilities within the scope of the amendment. These provisions ~~are~~were effective for interim and annual reporting periods beginning on or after January 1, 2013. The adoption of this guidance effective January 1, 2013 did not affect our financial position or results of operations, but ~~did result~~resulted in additional disclosures, which are included in Note 12.

Other

The statement of cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2012, which was included in our Form ~~10-Q~~10‑Q for the quarterly period ended ~~March 31,~~June 30, 2012, reflected an incorrect classification of $160 million in proceeds on a note receivable related to the sale of our Paulsboro Refinery in December 2010. We previously reflected such proceeds as a component of cash flows from operating activities rather than as a component of cash flows from investing activities. The statement of cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2012 included in this Form 10-Q for the quarterly period ended ~~March 31,~~June 30, 2013 has been corrected to properly reflect the classification of those proceeds.

New Accounting Pronouncements

In July 2013, the provisions of ASC Topic 740, “Income Taxes,” were amended to provide specific guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists at the reporting date. The amendment requires entities to present an unrecognized tax benefit as a reduction to the deferred tax asset generated by the net operating loss carryforward, similar tax loss, or tax credit carryforward, if such items are available to be used to offset the unrecognized tax benefit. These provisions are effective for interim and annual reporting periods beginning after December 15, 2013 and should be applied prospectively to all unrecognized tax benefits that exist at the effective date, with retrospective application permitted. The adoption of this guidance effective January 1, 2014 will not affect our financial position or results of operations, nor will it require any additional disclosures, but may result in a change in presentation to our consolidated balance sheets.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


2.	SEPARATION OF RETAIL BUSINESS

On May 1, 2013, we completed the separation of our retail business by creating an independent public company named CST Brands, Inc. (CST)~~. In accordance with a separation~~ and ~~distribution agreement, the separation occurred by way of a pro rata distribution of~~distributing 80 percent of the outstanding shares of CST common stock to our stockholders on May 1, 2013. Each Valero stockholder received one share of CST common stock for every nine shares of Valero common stock held at the close of business on the record date of April 19, 2013. Fractional shares of CST common stock were not distributed, but instead were aggregated and sold in the open market at prevailing rates with net cash proceeds then distributed pro rata to each Valero stockholder who was entitled to receive fractional shares.

In connection with the separation, we received an aggregate of $1.05 billion in cash, consisting of $550 million from the issuance of short-term debt to a third-party financial institution on April 16, 2013 and $500 million distributed to us by CST on May 1, 2013. The cash distributed to us by CST was borrowed by CST on May 1, 2013 under its senior secured credit facility. See Note 5 for further discussion of that credit facility. Also on May 1, 2013, CST issued $550 million of its senior unsecured bonds to us, and we exchanged those bonds with the third-party financial institution in satisfaction of our short-term debt. Immediately prior to May 1, 2013, subsidiaries of CST held $315 million of cash, and CST retained that cash following the distribution on May 1, 2013. ~~Approximately~~ ~~$265 million~~ of the cash retained by CST resulted from a change in the payment terms from “due upon receipt” to “net 10” days on motor fuel purchased from us, and this change in payment terms was effective prior to May 1, 2013. The new payment terms are consistent with those offered by us to our other creditworthy retail distributors. Also in connection with the separation, we incurred a tax liability of approximately $~~220~~189 million primarily related to the manner in which the transaction is treated for tax purposes in Canada, and most of these taxes will not be paid until the first half of 2014. Therefore, the ~~net~~ cash we ~~will receive~~received as a result of the separation, ~~will be approximately~~net of our tax liability, was $~~500~~546 million. We also incurred $30 million in costs during the three months ended June 30, 2013 to effect the separation, which are included in general and administrative expenses. We expect to liquidate the remaining 20 percent of the outstanding shares of CST common stock that we own within 18 months. of the date of separation.

We also entered into long-term motor fuel supply agreements with CST in the U.S. and Canada. The nature and significance of our agreements to supply motor fuel to CST through 2028 represents a continuation of activities with CST for accounting purposes. As such, the historical results of operations of our retail business have not been reported as discontinued operations in our statements of income.

Selected historical results of operations of our retail business prior to the separation are disclosed in Note 10. Subsequent to May 1, 2013, our share of CST’s results of operations associated with our retained 20 percent equity interest in CST is reflected in “other income (expense), net” and our equity investment in CST, which is accounted for under the equity method, is included in “deferred charges and other assets, net.” Our share of income taxes incurred directly by CST is reported in the equity in earnings from CST, and as such is not included in income taxes in our statements of income.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

~~In order to effect~~The following table presents the ~~separation~~carrying values of the major categories of assets and provide a framework for our relationship with CST after the separation, we entered into various agreements with CST, including fuel supply agreements in the U.S. and Canada. The nature and significanceliabilities of our ~~post-separation participation in the supply~~retail business, immediately preceding its separation on May 1, 2013, which are excluded from our consolidated balance sheet as of ~~motor fuel~~June 30, 2013 (in millions):



Assets
Cash and temporary cash investments	$	315
Credit card receivables from Valero	44
Other receivables, net	109
Inventories	170
Deferred income taxes	14
Prepaid expenses and other	13
Total current assets	665
Property, plant and equipment, at cost	1,891
Accumulated depreciation	(611		)
Property, plant and equipment, net	1,280
Intangible assets, net	38
Deferred charges and other assets, net	205
Total assets	$	2,188

Liabilities
Current portion of capital lease obligations	$	2
Trade payable to Valero	242
Other accounts payable	96
Accrued expenses	31
Taxes other than income taxes	20
Total current liabilities	391
Debt and capital lease obligations, less current portion	1,053
Deferred income taxes	83
Other long-term liabilities	112
Total liabilities	$	1,639

We retained certain environmental and other liabilities related to ~~CST represents a continuation of activities with~~our former retail business and we have indemnified CST for ~~accounting purposes. As such, the historical results of operations~~certain self-insurance liabilities related to ~~CST will not be reported by us as discontinued operations in our consolidated statements of income.~~its employees and property.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


3.	IMPAIRMENTS

Aruba Refinery

In March 2012, we suspended the operations of the Aruba Refinery because of its inability to generate positive cash flows on a sustained basis subsequent to its restart in January 2011 and the sensitivity of its profitability to sour crude oil differentials, which had narrowed significantly in the fourth quarter of 2011. Shortly thereafter, we received a non-binding offer to purchase the refinery for $350 million, plus working capital as of the closing date. Because of our decision to suspend the operations and the possibility of selling the refinery, we evaluated the refinery for potential impairment as of March 31, 2012 and concluded that it was impaired. We recognized an asset impairment loss of $595 million in March 2012. We did not, however, classify the Aruba Refinery as “held for sale” in our balance sheet because all of the accounting criteria required for that classification had not been met.

In September 2012, we decided to reorganize the Aruba Refinery into a crude oil and refined products terminal in response to the withdrawal of the non-binding offer to purchase the refinery. We bifurcated the idled crude oil processing units and related infrastructure (refining assets) from the terminal assets and evaluated the refining assets for potential impairment as of September 30, 2012. We concluded that the refining assets were impaired and recognized an asset impairment loss of $308 million in September 2012. We also recognized an asset impairment loss of $25 million related to materials and supplies inventories that supported the refining operations, resulting in a total asset impairment loss of $333 million that was recognized in September 2012 related to the Aruba Refinery. The terminal assets were not impaired.

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

The variation in the customary relationship between income tax expense and income before income tax expense for the ~~three~~six months ended ~~March 31,~~June 30, 2012 was primarily due to not recognizing a tax benefit associated with the asset impairment loss of $595 million related to the Aruba Refinery as we do not expect to realize this tax benefit.

Cancelled Capital Project

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

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4.	INVENTORIES

Inventories consisted of the following (in millions):


	March 31, 2013		December 31, 2012		June 30, 2013		December 31, 2012
Refinery feedstocks	$	2,580	$	2,458	$	2,641	$	2,458
Refined products and blendstocks	3,832		2,995		3,446		2,995
Ethanol feedstocks and products	190		191		139		191
Convenience store merchandise	111		112		—		112
Materials and supplies	224		217		220		217
Inventories	$	6,937	$	5,973	$	6,446	$	5,973

As of ~~March 31,~~June 30, 2013 and December 31, 2012, the replacement cost (market value) of last in, first out (LIFO) inventories exceeded their LIFO carrying amounts by approximately $~~7.5~~6.3 billion and $6.7 billion, respectively.


5.	DEBT

Bank Debt and Credit Facilities

We have a $3 billion revolving credit facility (the Revolver) that has a maturity date of December 2016. The Revolver has certain restrictive covenants, including a maximum debt-to-capitalization ratio of 60 percent. As of ~~March 31,~~June 30, 2013 and December 31, 2012, our debt-to-capitalization ratios, calculated in accordance with the terms of the Revolver, were 2119 percent and 23 percent, respectively. We believe that we will remain in compliance with this covenant. In addition to the Revolver, one of our Canadian subsidiaries has a committed revolving credit facility under which it may borrow and obtain letters of credit up to C$50 million.

During the ~~three~~six months ended ~~March 31,~~June 30, 2013 ~~and~~ ~~2012~~, we had no borrowings or repayments under our ~~Revolver~~Revolver. During the six months ended June 30, 2012, we borrowed and repaid $1.1 billion under our Revolver. We had no borrowings or repayments under the Canadian revolving credit ~~facility.~~facility during the six months ended June 30, 2013 and 2012. As of ~~March 31,~~June 30, 2013 and December 31, 2012, we had no borrowings outstanding under the Revolver or the Canadian revolving credit facility.

On March 20, 2013, in anticipation of the separation of our retail business as described in Note 2, CST entered into a credit agreement providing for $800 million of senior secured credit facilities (consisting of a $500 million term loan facility and a revolving credit facility with ~~a borrowing capacity~~an aggregate principal amount of up to $300 million). Borrowings under the term loan and revolving credit ~~facility will~~facilities bear interest at ~~a base rate or~~ the London Interbank Offered Rate (LIBOR) plus a margin or an alternate base rate, as ~~prescribed~~defined in the ~~agreement.~~agreement, plus a margin. The credit agreement matures on May 1, 2018 and has certain restrictive covenants. ~~As of~~ ~~March 31, 2013~~, no ~~amounts were outstanding under these credit facilities.~~ This credit ~~facility was~~agreement and related credit facilities were retained by CST after the separation from us. Therefore, we have no rights to obtain credit under nor any liabilities in connection with this credit agreement and related credit facilities.

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On April 16, 2013, also in anticipation of the separation of our retail business, we borrowed $550 million under a short-term debt agreement with a third-party financial institution. On May 1, 2013, CST issued $550 million of its senior unsecured bonds to us, and we exchanged those bonds with the third-party financial institution in satisfaction of our short-term debt.

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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	March 31, 2013		December 31, 2012		Borrowing Capacity		Expiration	June 30, 2013		December 31, 2012
Letter of credit facilities	$	550	June 2013	$	550	$	418	$	550	June 2014	$	250	$	418
Revolver	$	3,000	December 2016	$	59	$	59	$	3,000	December 2016	$	59	$	59
Canadian revolving credit facility	C$	50	November 2013	C$	10	C$	10	C$	50	November 2013	C$	9	C$	10

As of ~~March 31,~~June 30, 2013 and December 31, 2012, we had $~~441~~87 million and $275 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities.

Non-Bank Debt

InDuring the six months ended June 30, 2013, the following activity occurred:

in June 2013, we made a scheduled debt repayment of $300 million related to our 4.75% notes; and

in January 2013, we made a scheduled debt repayment of $180 million related to our 6.7% senior notes. In

During the six months ended June 30, 2012, the following activity occurred:

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

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

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

Accounts Receivable Sales Facility

We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell up to $1.5 billion of eligible trade receivables on a revolving basis. ~~This~~In July 2013, we amended this facility ~~matures in~~to extend the maturity date to July ~~2013~~2014. Proceeds from the sale of receivables under this facility are reflected as debt. Under this program, one of our marketing subsidiaries (Valero Marketing) sells eligible receivables, without recourse, to another of our subsidiaries (Valero Capital), whereupon the receivables are no longer owned by Valero Marketing. Valero Capital, in turn, sells an undivided percentage ownership interest in the eligible receivables, without recourse, to the third-party entities and financial institutions. To the extent that Valero Capital retains an ownership interest in the receivables it has purchased from Valero Marketing, such interest is included in our financial statements solely as a result of the consolidation of the financial statements of Valero Capital with those of Valero Energy Corporation; the receivables are not available to satisfy the claims of the creditors of Valero Marketing or Valero Energy Corporation.

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

Three Months Ended
March 31,
2013 2012
Balance as of beginning of period $ 100
$ 250
Repayments —
(150 )
Balance as of end of period $ 100
$ 100

~~Capitalized Interest~~

~~Capitalized interest was~~ ~~$40 million~~ ~~and~~ ~~$52 million~~ ~~for the three months ended~~ ~~March 31, 2013~~ ~~and~~ ~~2012, respectively.~~

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



	Six Months Ended June 30,
	2013		2012
Balance as of beginning of period	$	100	$	250
Proceeds from the sale of receivables	—		1,300
Repayments	—		(1,450		)
Balance as of end of period	$	100	$	100

Capitalized Interest

Capitalized interest was $45 million and $53 million for the three months ended June 30, 2013 and 2012, respectively, and $85 million and $105 million for the six months ended June 30, 2013 and 2012, respectively.


6.	COMMITMENTS AND CONTINGENCIES

Environmental Matter

We are involved, together with several other companies, in an environmental cleanup in the Village of Hartford, Illinois (the Village) and the adjacent shutdown refinery site, which we acquired as part of a prior acquisition. In cooperation with some of the other companies, we have been conducting initial mitigation and cleanup response pursuant to an administrative order issued by the U.S. Environmental Protection Agency (EPA). The EPA is seeking further cleanup obligations from us and other potentially responsible parties for the Village. In parallel with the Village cleanup, we are also in litigation with the State of Illinois Environmental Protection Agency and other potentially responsible parties relating to the remediation of the shutdown refinery site. In each of these matters, we have various defenses and rights for contribution from the other potentially responsible parties. We have accrued for our own expected contribution obligations. However, because of the unpredictable nature of these cleanups and the methodology for allocation of liabilities, it is reasonably possible that we could incur a loss in a range of $0 to $~~250~~200 million in excess of the amount of our accrual to ultimately resolve these matters. Factors underlying this estimated range are expected to change from time to time, and actual results may vary significantly from this estimate.

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.

One-Time Severance Benefits

As described in Note 3, we decided to reorganize the Aruba Refinery into a crude oil and refined products terminal in September 2012 resulting in a decrease in required personnel for our operations in Aruba. We notified 495 employees in September 2012 of the termination of their employment effective November 15,

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2012. Benefits to each terminated employee consisted primarily of a cash payment based on a formula that considers the employee’s current compensation and years of service, among other factors. We recognized a severance liability of $41 million in September 2012, which approximated fair value. We paid $31 million of these benefits in the fourth quarter of 2012 and we paid the remaining termination benefits of $10 million during the ~~three~~ ~~months ended~~ ~~March 31, 2013~~.first quarter of 2013.

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7.	EQUITY

Reconciliation of Balances

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, and total equity for the ~~three~~six months ended ~~March 31,~~June 30, 2013 and 2012 (in millions):


	2013									2012								2013									2012
	Valero Stockholders’ Equity			Non- controlling Interests			Total Equity			Valero Stockholders’ Equity			Non- controlling Interest		Total Equity			Valero Stockholders’ Equity			Non- controlling Interests			Total Equity			Valero Stockholders’ Equity			Non- controlling Interest			Total Equity
Balance as of beginning of period	$	18,032		$	63		$	18,095		$	16,423		$	22	$	16,445		$	18,032		$	63		$	18,095		$	16,423		$	22		$	16,445
Net income (loss)	654			(2		)	652			(432		)	—		(432		)	1,120			(3		)	1,117			399			(1		)	398
Dividends	(111		)	—			(111		)	(83		)	—		(83		)	(220		)	—			(220		)	(166		)	—			(166		)
Stock-based compensation expense	11			—			11			10			—		10			25			—			25			20			—			20
Tax deduction in excess of stock-based compensation expense	24			—			24			2			—		2			27			—			27			3			—			3
Transactions in connection with stock-based compensation plans
Transactions in connection with stock-based compensation plans:
Stock issuances	38			—			38			9			—		9			43			—			43			11			—			11
Stock repurchases	(24		)	—			(24		)	(95		)	—		(95		)	(196		)	—			(196		)	(136		)	—			(136		)
Stock repurchases under buyback program	(294		)	—			(294		)	—			—		—			(364		)	—			(364		)	—			—			—
Separation of retail business																		(499		)	—			(499		)	—			—			—
Contributions from noncontrolling interests	—			14			14			—			11		11			—			45			45			—			25			25
Other comprehensive income	13			—			13			125			—		125
Other comprehensive income (loss)																		(48		)	—			(48		)	23			—			23
Balance as of end of period	$	18,343		$	75		$	18,418		$	15,959		$	33	$	15,992		$	17,920		$	105		$	18,025		$	16,577		$	46		$	16,623

The noncontrolling interests relate to third-party ownership interests in two joint venture companies, whose financial statements we consolidate due to our controlling interests.

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Share Activity

Activity in the number of shares of common stock and treasury stock was as follows ~~(in millions)~~ for the ~~three~~six months ended ~~March 31,~~June 30, 2013 and 2012 (in millions):


	2013			2012			2013			2012
	Common Stock	Treasury Stock		Common Stock	Treasury Stock		Common Stock	Treasury Stock		Common Stock	Treasury Stock
Balance as of beginning of period	673	(121	)	673	(117	)	673	(121	)	673	(117	)
Transactions in connection with stock-based compensation plans:
Stock issuances	—	3		—	1		—	3		—	1
Stock purchases	—	—		—	(5	)	—	(5	)	—	(6	)
Stock repurchases under buyback program	—	(7	)	—	—		—	(8	)	—	—
Balance as of end of period	673	(125	)	673	(121	)	673	(131	)	673	(122	)

Common Stock Dividends

On ~~May 1,~~July 25, 2013, our board of directors declared a quarterly cash dividend of $~~0.20~~0.225 per common share payable on ~~June 19,~~September 11, 2013 to holders of record at the close of business on ~~May 22,~~August 14, 2013.

Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss) by component, net of tax, were as follows for the ~~three~~six months ended ~~March 31,~~June 30, 2013 (in millions):


	Foreign Currency Translation Adjustment			Defined Benefit Pension Items			Gains and (Losses) on Cash Flow Hedges			Total		Foreign Currency Translation Adjustment			Defined Benefit Pension Items			Gains and (Losses) on Cash Flow Hedges			Total
Balance as of December 31, 2012	$	665		$	(558	)	$	1		$	108	$	665		$	(558	)	$	1		$	108
Other comprehensive income (loss) before reclassifications	(204		)	213			1			10		(268		)	214			(6		)	(60		)
Amounts reclassified from accumulated other comprehensive income	—			5			(2		)	3
Amounts reclassified from accumulated other comprehensive income (loss)												—			9			3			12
Net other comprehensive income (loss)	(204		)	218			(1		)	13		(268		)	223			(3		)	(48		)
Balance as of March 31, 2013	$	461		$	(340	)	$	—		$	121
Separation of retail business												(159		)	—			—			(159		)
Balance as of June 30, 2013												$	238		$	(335	)	$	(2	)	$	(99	)

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~~Reclassifications into income~~Gains (losses) reclassified out of accumulated other comprehensive income (loss) and into net income were as follows ~~for the~~ ~~three~~ ~~months ended~~ ~~March 31, 2013~~(in millions):


Details about Accumulated Other Comprehensive Income Components	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
Details about Accumulated Other Comprehensive Income (Loss) Components					Three Months Ended June 30, 2013			Six Months Ended June 30, 2013			Affected Line Item in the Statement of Income
Amortization of items related to defined benefit pension plans:
Net actuarial loss	$	(14	)	(a)	$	(15	)	$	(29	)	(a)
Prior service credit	6			(a)	9			15			(a)
	(8		)	Total before tax	(6		)	(14		)	Total before tax
	3			Tax benefit	2			5			Tax benefit
	$	(5	)	Net of tax	$	(4	)	$	(9	)	Net of tax

Gains on cash flow hedges:
Losses on cash flow hedges:
Commodity contracts	$	3		Cost of sales	$	(8	)	$	(5	)	Cost of sales
	3			Total before tax	(8		)	(5		)	Total before tax
	(1		)	Tax expense	3			2			Tax benefit
	$	2		Net of tax	$	(5	)	$	(3	)	Net of tax

Total reclassifications for the period	$	(3	)	Net of tax	$	(9	)	$	(12	)	Net of tax

_________________________

(a) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost, as further discussed in Note 8. Net periodic benefit cost is reflected in operating expenses and general and administrative expenses.

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8.	EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost related to our defined benefit plans were as follows (in millions) :


	Pension Plans						Other Postretirement Benefit Plans						Pension Plans						Other Postretirement Benefit Plans
	2013			2012			2013			2012			2013			2012			2013			2012
Three months ended March 31:
Three months ended June 30:
Service cost	$	36		$	35		$	3		$	3		$	35		$	35		$	3		$	3
Interest cost	22			23			4			5			22			23			5			6
Expected return on plan assets	(32		)	(31		)	—			—			(34		)	(31		)	—			—
Amortization of:
Net actuarial loss													15			9			—			—
Prior service credit													(6		)	—			(3		)	(6		)
Net periodic benefit cost													$	32		$	36		$	5		$	3

Six months ended June 30:
Service cost													$	71		$	70		$	6		$	6
Interest cost													44			46			9			11
Expected return on plan assets													(66		)	(62		)	—			—
Amortization of:
Net actuarial loss													29			17			—			—
Prior service cost (credit)	(3		)	1			(3		)	(5		)	(9		)	1			(6		)	(11		)
Net actuarial loss	14			8			—			—
Net periodic benefit cost	$	37		$	36		$	4		$	3		$	69		$	72		$	9		$	6

On February 15, 2013, we announced changes to certain of our U.S. qualified pension plans that cover the majority of our U.S. employees who work in our refining segment and corporate operations. Benefits under our primary pension plan will change from a final average pay formula to a cash balance formula with staged effective dates that commence either on July 1, 2013 or January 1, 2015 depending on the age and service of the affected employees. All final average pay benefits will be frozen as of December 31, 2014, with all future benefits to be earned under the new cash balance formula. These plan amendments resulted in a $328 million decrease to pension liabilities and a related increase to other comprehensive income during the ~~three~~six months ended ~~March 31,~~June 30, 2013. The benefit of this remeasurement will be amortized into income through 2025.

As a result of these plan amendments, management ~~has decided to reduce~~reduced its discretionary contributions to our pension plans by $100 million, resulting in expected contributions to our pension plans of $45 million for 2013. During the ~~three~~six months ended ~~March 31,~~June 30, 2013 and 2012, we contributed $818 million and $1016 million, respectively, to our pension plans and $48 million and $410 million, respectively, to our other postretirement benefit plans.

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9.	EARNINGS PER COMMON SHARE

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

Three Months Ended March 31,
2013 2012

Restricted
Stock

Common
Stock

Restricted
Stock

Common
Stock
Earnings per common share:
Net income (loss) attributable to Valero stockholders $ 654
$ (432 )
Less dividends paid:
Common stock 110

83
Nonvested restricted stock 1

—
Undistributed earnings (loss) $ 543

$ (515 )
Weighted-average common shares outstanding 3
550
3
551
Earnings per common share:
Distributed earnings $ 0.20
$ 0.20
$ 0.15
$ 0.15
Undistributed earnings (loss) 0.98
0.98
—
(0.93 )
Total earnings per common share $ 1.18
$ 1.18
$ 0.15
$ (0.78 )

Earnings per common share – assuming dilution:
Net income (loss) attributable to Valero stockholders $ 654
$ (432 )
Weighted-average common shares outstanding 550
551
Common equivalent shares:

Stock options 4
—
Performance awards and
nonvested restricted stock
2
—
Weighted-average common shares outstanding –
assuming dilution
556
551
Earnings per common share – assuming dilution $ 1.18
$ (0.78 )



	Three Months Ended June 30,
	2013				2012
	Restricted Stock		Common Stock		Restricted Stock		Common Stock
Earnings per common share:
Net income attributable to Valero stockholders			$	466			$	831
Less dividends paid:
Common stock			109				82
Nonvested restricted stock			—				1
Undistributed earnings			$	357			$	748
Weighted-average common shares outstanding	3		543		3		550
Earnings per common share:
Distributed earnings	$	0.20	$	0.20	$	0.15	$	0.15
Undistributed earnings	0.66		0.66		1.35		1.35
Total earnings per common share	$	0.86	$	0.86	$	1.50	$	1.50

Earnings per common share – assuming dilution:
Net income attributable to Valero stockholders			$	466			$	831
Weighted-average common shares outstanding			543				550
Common equivalent shares:
Stock options			3				3
Performance awards and nonvested restricted stock			2				2
Weighted-average common shares outstanding – assuming dilution			548				555
Earnings per common share – assuming dilution			$	0.85			$	1.50

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	Six Months Ended June 30,
	2013				2012
	Restricted Stock		Common Stock		Restricted Stock		Common Stock
Earnings per common share:
Net income attributable to Valero stockholders			$	1,120			$	399
Less dividends paid:
Common stock			219				165
Nonvested restricted stock			1				1
Undistributed earnings			$	900			$	233
Weighted-average common shares outstanding	3		546		3		550
Earnings per common share:
Distributed earnings	$	0.40	$	0.40	$	0.30	$	0.30
Undistributed earnings	1.64		1.64		0.42		0.42
Total earnings per common share	$	2.04	$	2.04	$	0.72	$	0.72

Earnings per common share – assuming dilution:
Net income attributable to Valero stockholders			$	1,120			$	399
Weighted-average common shares outstanding			546				550
Common equivalent shares:
Stock options			4				4
Performance awards and nonvested restricted stock			2				2
Weighted-average common shares outstanding – assuming dilution			552				556
Earnings per common share – assuming dilution			$	2.03			$	0.72

The following table reflects potentially dilutive securities (in millions) that were excluded from the calculation of “earnings per common share – assuming dilution” as the effect of including such securities would have been antidilutive. Stock options were excluded from weighted-average common shares outstanding – assuming dilution because the exercise price of the stock option was greater than the average market price of our common shares during each reporting period.

Three Months Ended
March 31,
2013 2012
Common equivalent shares (a) —
6
Stock options (b) 3
6



	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
Stock options	3	6	3	6

~~_______________________~~


~~(a)~~	~~Common equivalent shares (primarily stock options) were excluded from weighted-average common shares outstanding – assuming dilution due to the net loss for the three months ended March 31, 2012.~~


~~(b)~~	Stock options were excluded from weighted-average common shares outstanding – assuming dilution because the exercise price of the stock option was greater than the average market price of our common shares during each reporting period.


~~10.~~	~~SEGMENT INFORMATION~~

~~The following table reflects activity related to our reportable segments (in millions):~~

Refining Retail Ethanol Corporate Total
Three months ended March 31, 2013:
Operating revenues from external
customers
$ 29,553
$ 2,917
$ 1,004
$ —
$ 33,474
Intersegment revenues 2,205
—
55
—
2,260
Operating income (loss) 1,212
42
14
(207 ) 1,061

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 )

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

March 31,
2013 December 31,
2012
Refining $ 40,185
$ 39,490
Retail 2,125
2,043
Ethanol 924
929
Corporate 2,267
2,015
Total assets $ 45,501
$ 44,477

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10.	SEGMENT INFORMATION

As discussed in Note 2, we completed the separation of our retail business on May 1, 2013. Segment activity related to our retail business prior to the separation is reflected in the retail segment results below. Motor fuel sales to CST (our former retail business), which were eliminated in consolidation prior to the separation, are reported as refining segment operating revenues from external customers after May 1, 2013.

The following table reflects activity related to our reportable segments (in millions):



	Refining		Retail		Ethanol		Corporate			Total
Three months ended June 30, 2013:
Operating revenues from external customers	$	31,564	$	979	$	1,491	$	—		$	34,034
Intersegment revenues	671		—		15		—			686
Operating income (loss)	921		39		95		(247		)	808

Three months ended June 30, 2012:
Operating revenues from external customers	30,488		3,062		1,112		—			34,662
Intersegment revenues	2,203		—		46		—			2,249
Operating income (loss)	1,364		172		5		(180		)	1,361

Six months ended June 30, 2013:
Operating revenues from external customers	61,117		3,896		2,495		—			67,508
Intersegment revenues	2,876		—		70		—			2,946
Operating income (loss)	2,133		81		109		(454		)	1,869

Six months ended June 30, 2012:
Operating revenues from external customers	61,638		5,997		2,194		—			69,829
Intersegment revenues	4,458		—		60		—			4,518
Operating income (loss)	1,245		212		14		(354		)	1,117

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



	June 30, 2013		December 31, 2012
Refining	$	40,527	$	39,490
Retail	—		2,043
Ethanol	867		929
Corporate	2,783		2,015
Total assets	$	44,177	$	44,477


11.	SUPPLEMENTAL CASH FLOW INFORMATION

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


	Three Months Ended March 31,						Six Months Ended June 30,
	2013			2012			2013			2012
Decrease (increase) in current assets:
Receivables, net	$	409		$	1,159		$	412		$	1,927
Inventories	(1,074		)	(471		)	(824		)	198
Income taxes receivable	79			(14		)	31			(79		)
Prepaid expenses and other	(233		)	6			2			(15		)
Increase (decrease) in current liabilities:
Accounts payable	561			410			625			(1,413		)
Accrued expenses	181			(100		)	(44		)	(60		)
Taxes other than income taxes	318			9			268			67
Income taxes payable	14			(96		)	(26		)	(60		)
Changes in current assets and current liabilities	$	255		$	903		$	444		$	565

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

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

the amounts shown above for the six months ended June 30, 2013 exclude the change in current assets and current liabilities resulting from the separation of our retail business as described in Note 2;

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

There were no significant noncash investing activities for the six months ended June 30, 2013. Noncash financing activities for the six months ended June 30, 2013 included the exchange of CST’s senior unsecured bonds with the third-party financial institution in satisfaction of our short-term debt as described in Note 2.

There were no significant noncash investing or financing activities for the ~~three~~six months ended ~~March 31, 2013~~ ~~and~~ June 30, 2012.

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

Three Months Ended
March 31,
2013 2012
Interest paid in excess of amount capitalized $ 56
$ 45
Income taxes paid, net 48
142



	Six Months Ended June 30,
	2013		2012
Interest paid in excess of amount capitalized	$	160	$	164
Income taxes paid, net	243		204

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12.	FAIR VALUE MEASUREMENTS

General

GAAP requires that certain ~~financial instruments,~~assets and liabilities be measured at fair value on a recurring or nonrecurring basis in our balance sheets, which are presented below under “Recurring Fair Value Measurements” and “Nonrecurring Fair Value Measurements.” Recurring fair value measurements of assets or liabilities are those that GAAP requires or permits in the balance sheet at the end of each reporting period, such as derivative ~~instruments, be recognized at their~~financial instruments. Nonrecurring fair ~~values~~value measurements of assets or liabilities are those that GAAP requires or permits in ~~our~~the balance ~~sheets. However, other financial instruments,~~sheet in particular circumstances, such as ~~debt obligations, are not required to be recognized at their fair values, but~~ the impairment of property, plant and equipment.

GAAP ~~provides an option to elect fair value accounting for these instruments. GAAP~~also requires the disclosure of the fair values of ~~all~~ financial instruments ~~regardless of whether they are recognized at their fair values or carrying amounts in our balance sheets. For financial instruments recognized at~~when an option to elect fair value ~~GAAP requires the~~accounting has been provided, but such election has not been made. A debt obligation is an example of such a financial instrument. 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~~in our balance sheet is ~~provided~~presented below under “Other Financial Instruments.”

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

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

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

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

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Level 3 - Unobservable inputs for the asset or ~~liability for which there is little, if any, market activity at the measurement date.~~liability. 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~~assets and liabilities recognized at their fair values in our balance sheets categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of ~~March 31,~~June 30, 2013 and December 31, 2012.

We have elected to offset the fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty, including any related cash collateral assets or obligations as shown below; however, fair value amounts by hierarchy level are presented on a gross basis in the tables below. We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.


																							June 30, 2013
	March 31, 2013																												Total Gross Fair Value		Effect of Counter- party Netting			Effect of Cash Collateral Netting			Net Carrying Value on Balance Sheet		Cash Collateral Paid or Received Not Offset
	Fair Value Hierarchy							Total Gross Fair Value			Effect of Counter- party Netting			Effect of Collateral Netting			Net Carrying Value on Balance Sheet			Cash Collateral Paid or Received Not Offset			Fair Value Hierarchy
	Level 1		Level 2			Level 3		Total Gross Fair Value			Effect of Counter- party Netting			Effect of Collateral Netting			Net Carrying Value on Balance Sheet			Cash Collateral Paid or Received Not Offset			Level 1		Level 2		Level 3
Assets:
Commodity derivative contracts	$	1,036	$	30		$	—	$	1,066		$	(989	)	$	—		$	77		$	—		$	1,015	$	28	$	—	$	1,043	$	(997	)	$	(3	)	$	43	$	—
Physical purchase contracts	—		8			—		8			N/A			N/A			8			N/A			—		5		—		5		N/A			N/A			5		N/A
RINs fixed-price contracts	—		(12		)	—		(12		)	N/A			N/A			(12		)	N/A
Foreign currency contracts																							10		—		—		10		N/A			N/A			10		N/A
Investments of certain benefit plans	91		—			11		102			N/A			N/A			102			N/A			92		—		11		103		N/A			N/A			103		N/A
Total	$	1,127	$	26		$	11	$	1,164		$	(989	)	$	—		$	175					$	1,117	$	33	$	11	$	1,161	$	(997	)	$	(3	)	$	161

Liabilities:
Commodity derivative contracts	$	983	$	30		$	—	$	1,013		$	(989	)	$	(17	)	$	7		$	(82	)	$	997	$	28	$	—	$	1,025	$	(997	)	$	(23	)	$	5	$	(109	)
Foreign currency contracts	3		—			—		3			N/A			N/A			3			N/A
Physical purchase contracts																							—		11		—		11		N/A			N/A			11		N/A
RINs fixed-price contracts																							—		22		—		22		N/A			N/A			22		N/A
Total	$	986	$	30		$	—	$	1,016		$	(989	)	$	(17	)	$	10					$	997	$	61	$	—	$	1,058	$	(997	)	$	(23	)	$	38

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																								December 31, 2012
	December 31, 2012																														Total Gross Fair Value				Effect of Counter- party Netting				Effect of Cash Collateral Netting				Net Carrying Value on Balance Sheet				Cash Collateral Paid or Received Not Offset
	Fair Value Hierarchy						Total Gross Fair Value		Effect of Counter- party Netting				Effect of Collateral Netting				Net Carrying Value on Balance Sheet				Cash Collateral Paid or Received Not Offset			Fair Value Hierarchy
	Level 1		Level 2		Level 3				Effect of Counter- party Netting			Level 1					Net Carrying Value on Balance Sheet			Level 2					Level 3
Assets:							Total Gross Fair Value
Commodity derivative contracts	$	1,143	$	60	$	—	$	1,203	$	(1,189	)		Effect of Collateral Netting		$	—			$	14	Cash Collateral Paid or Received Not Offset				$	—	$	1,143	$	60			$	—			$	1,203			$	(1,189	)		$	—			$	14	$	—
Physical purchase contracts	—		11		—		11		N/A				N/A				11				N/A			—			11		—		11				N/A				N/A				11				N/A
Foreign currency contracts																								1			—		—		1				N/A				N/A				1				N/A
Investments of certain benefit plans	87		—		11		98		N/A				N/A				98				N/A			87			—		11		98				N/A				N/A				98				N/A
Foreign currency contracts	1		—		—		1		N/A				N/A				1				N/A
Total	$	1,231	$	71	$	11	$	1,313	$	(1,189	)		$	—			$	124						$	1,231		$	71	$	11	$	1,313			$	(1,189	)		$	—			$	124

Liabilities:
Commodity derivative contracts	$	1,138	$	70	$	—	$	1,208	$	(1,189	)		$	(13	)		$	6			$	(114	)	$	1,138		$	70	$	—	$	1,208			$	(1,189	)		$	(13	)		$	6			$	(114	)
Biofuels blending obligation	—		10		—		10		N/A				N/A				10				N/A			—			10		—		10				N/A				N/A				10				N/A
Foreign currency contracts	1		—		—		1		N/A				N/A				1				N/A			1			—		—		1				N/A				N/A				1				N/A
Total	$	1,139	$	80	$	—	$	1,219	$	(1,189	)		$	(13	)		$	17						$	1,139		$	80	$	—	$	1,219			$	(1,189	)		$	(13	)		$	17

A description of our ~~financial instruments~~assets and liabilities recognized at fair value along with the valuation methods and inputs we used to ~~measure those instruments at~~develop their fair value measurements 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 or an independent pricing service and are categorized in Level 2 of the fair value hierarchy.

~~RINs~~Renewable Identification Numbers (RINs) fixed-price contracts represent the fair value of fixed-price purchase and sale contracts of ~~RINs. (RINs are defined and described in~~ ~~Note 13~~ ~~under~~ ~~“Compliance Program Price Risk.”)~~RINs entered into for trading purposes. The fair values of these contracts are measured using a market approach based on quoted prices from an independent pricing service and are categorized in Level 2 of the fair value hierarchy.

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

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

Our biofuels blending obligation represents a liability for the purchase of biofuel credits (primarily RINs ~~and RTFCs, as defined and described~~ in ~~Note 13~~ ~~under~~ ~~“Compliance Program Price Risk,”~~the U.S.) needed to satisfy our obligation to blend biofuels into the products we produce. ~~Our obligation~~To the degree we are unable to blend at percentages required under various governmental and regulatory programs, we must purchase biofuel credits to comply with these programs. These programs are further described in Note 13 under “Compliance Program Risk.” This liability is based on our ~~deficiency~~deficit in ~~RINs~~biofuel credits as of the balance sheet date, if any, after considering any biofuel credits acquired or under contract, and ~~RTFCs~~is equal to the product of the biofuel credits deficit and the market price of these ~~instruments~~credits as of the balance sheet date. ~~Our obligation~~This liability is categorized in Level 2 of the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.

~~During~~There were no transfers between Level 1 and Level 2 for assets and liabilities held as of June 30, 2013 and December 31, 2012 that were measured at fair value on a recurring basis.

There was no activity during the three and ~~three~~six months ended ~~March 31,~~June 30, 2013 and 2012~~, there~~ related to the fair value amounts categorized in Level 3 as of June 30, 2013 and December 31, 2012.

Nonrecurring Fair Value Measurements

There were no ~~transfers between~~ assets ~~classified as Level 1 and Level 2.~~

~~The following is a reconciliation of the beginning and ending balances (in millions) for~~or liabilities that were measured at fair value ~~measurements developed using significant unobservable inputs (Level 3)~~on a nonrecurring basis as of June 30, 2013.

The table below presents the fair value of certain assets that were measured at fair value on a nonrecurring basis as of December 31, 2012 (in millions).

2013 2012

Investments
of Certain
Benefit
Plans

Investments
of Certain
Benefit
Plans
Three months ended March 31:
Balance as of beginning of period $ 11
$ 11
Purchases —
—
Total gains (losses) included in
refining operating expenses
—
—
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
$ —
$ —



							Total Fair Value as of December 31, 2012
	Fair Value Hierarchy
	Level 1		Level 2		Level 3
Cancelled capital project	$	—	$	—	$	2	$	2
Property, plant and equipment of convenience stores	—		—		8		8

There were no liabilities that were measured at fair value on a nonrecurring basis as of December 31, 2012.

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~~Nonrecurring Fair Value Measurements~~

~~There were no assets or liabilities that were measured~~During the six months ended June 30, 2012, we recognized asset impairment losses of $595 million and $16 million related to our Aruba Refinery and certain equipment associated with a permanently cancelled capital project at one of our refineries, respectively. These impairment losses resulted from the fair value measurement of those assets on a nonrecurring basis ~~during the~~ ~~three~~ ~~months ended~~ as of March 31, ~~2013~~.

~~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
Total Loss
Recognized
During the
Three Months Ended
March 31,
2012
Level 1 Level 2 Level 3
Total
Fair Value
as of
March 31,
2012

Assets:
Long-lived assets of
the Aruba Refinery
$ —
$ —
$ 350
$ 350
$ 595
Cancelled capital project —
—
2
2
16

~~There were no liabilities that were measured at fair value on a nonrecurring basis during the~~ ~~three~~ ~~months ended~~ ~~March 31, 2012~~.

~~Aruba Refinery~~

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

~~Cancelled Capital Project~~

~~In March 2012, we wrote down the carrying value of equipment associated with a permanently cancelled capital project at one of our refineries and recognized an asset impairment loss of~~ ~~$16 million~~.

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Other Financial Instruments

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


	March 31, 2013				December 31, 2012				June 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash and temporary cash investments	$	1,857	$	1,857	$	1,723	$	1,723	$	2,398	$	2,398	$	1,723	$	1,723
Equity investment in CST									114		465		—		—
Financial liabilities:
Debt (excluding capital leases)	6,821		8,414		7,000		8,621		6,522		7,736		7,000		8,621

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

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

The fair value of our equity investment in CST is determined using the market approach based on the quoted price of CST stock from a national securities exchange (Level 1).

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

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13.	PRICE RISK MANAGEMENT ACTIVITIES

General

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~~rates. We enter into derivative instruments to manage some of these ~~risks. We also enter into~~risks, including 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~~below under “Risk Management Activities by Type of Risk.” These derivative instruments are recorded as either assets or liabilities measured at their fair values (see Note 12)., as summarized below under “Fair Values of Derivative Instruments.” In addition, the effect of these derivative instruments on our income is summarized below under “Effect of Derivative Instruments on Income and Other Comprehensive Income.”

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

We are also exposed to market risk related to the volatility in the price of credits needed to comply with various governmental and regulatory programs. To manage this risk, we enter into contracts to purchase these credits when prices are deemed favorable. Some of these contracts are derivative instruments; however, we elect the normal purchase and sale exception and do not record these contracts at their fair values.

~~Table~~Risk Management Activities by Type of ~~Contents~~

~~VALERO ENERGY CORPORATION AND SUBSIDIARIES~~

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

Risk

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

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

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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 ~~March 31,~~June 30, 2013, 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		2013
Crude oil and refined products:
Futures – long		~~369~~8,062
Futures – short		~~3,256~~10,954
Physical contracts - long		~~2,887~~2,892

Cash Flow Hedges

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

As of ~~March 31,~~June 30, 2013, 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		2013
Crude oil and refined products:
Futures – long		~~1,829~~7,938
Futures – short		~~347~~5,527
Physical contracts – short		~~1,482~~2,411

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~~VALERO ENERGY CORPORATION AND SUBSIDIARIES~~

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

Economic Hedges

– Economic hedges represent commodity derivative instruments that are not designated as fair value or cash flow hedges and are used to manage price volatility in certain (i) refinery

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

As of ~~March 31,~~June 30, 2013, we had the following outstanding commodity derivative instruments that were used as economic hedges and commodity derivative instruments related to the physical purchase of corn at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as natural gas contracts that are presented in billions of British thermal units, corn contracts that are presented in thousands of ~~bushels)~~bushels, and soybean oil contracts that are presented in thousands of pounds).


	Notional Contract Volumes by Year of Maturity		Notional Contract Volumes by Year of Maturity
Derivative Instrument	2013	2014	2013	2014
Crude oil and refined products:
Swaps – long	2,267	—	3,510	—
Swaps – short	1,550	—	2,585	—
Futures – long	50,113	17	39,316	58
Futures – short	69,216	—	53,514	—
Options – long	2	—
Natural gas:
Options – long	12,250	—	10,750	—
Options – short	3,000	—
Corn:
Futures – long	19,320	5	28,405	5
Futures – short	39,620	420	49,030	1,180
Physical contracts – long	17,358	447	21,678	1,215
Soybean oil:
Futures – long			5,220	—
Futures – short			27,900	—

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Trading Derivatives

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

As of ~~March 31,~~June 30, 2013, we had the following outstanding commodity and other 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, corn contracts that are presented in thousands of bushels, and RINs contracts that are presented in thousands of gallons).


	Notional Contract Volumes by Year of Maturity		Notional Contract Volumes by Year of Maturity
Derivative Instrument	2013	2014	2013	2014
Crude oil and refined products:
Swaps – long	43,972	16,915	26,255	21,135
Swaps – short	43,972	16,915	26,255	21,135
Futures – long	106,227	22,518	99,886	37,527
Futures – short	105,432	22,793	99,311	37,927
Options – long	18,660	—	26,321	—
Options – short	17,310	—	25,256	—
Natural gas:
Futures – long	3,500	—	1,700	—
Futures – short	1,500	—	750	—
Options – long	1,250	—	1,700	—
Options – short	250	—
Corn:
Swaps – long	1,125	—	145	—
Swaps – short	500	—	145	—
Futures – long	2,555	—	5,620	—
Futures – short	2,555	—	5,620	—
RINs:
Fixed-price contracts – long	15,600	—
Fixed-price contracts – short	33,038	—
Other:
RINs fixed-price contracts – short			25,000	—

~~Compliance Program Price Risk~~

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~~VALERO ENERGY CORPORATION AND SUBSIDIARIES~~

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

~~Obligation to Blend Biofuels~~

We are obligated to blend biofuels into the products we produce in most of the countries in which we operate, and these countries set annual quotas for the percentage of biofuels that must be blended into the motor fuels consumed in these countries. As a producer of motor fuels from petroleum, we are obligated to blend biofuels into the products we produce at a rate that is at least equal to the applicable quota. To the degree we are unable to blend at the applicable rate in the U.S. and the United Kingdom (U.K.), we must purchase Renewable Identification Numbers (RINs) in the U.S. and Renewable Transport Fuel 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 these instruments is deemed favorable. During the ~~three~~ ~~months ended~~ ~~March 31, 2013, we purchased a portion of our expected obligation for 2013 due to rising RINs prices. The cost of meeting our obligations under this compliance program was~~ ~~$130 million~~ ~~and~~ ~~$67 million~~ ~~for the~~ ~~three~~ ~~months ended~~ ~~March 31, 2013~~ ~~and~~ ~~2012, respectively. 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, 2013, costs incurred to meet our obligations under this compliance program were immaterial. 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, which was reflected in cost of sales.~~

~~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, 2013~~, no ~~costs were incurred to meet our obligation under this compliance program. For the~~ ~~three~~ ~~months ended~~ ~~March 31, 2012, the cost of meeting our obligation under this compliance program was~~ ~~$1 million, which was reflected in refining operating expenses.~~

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, 2013~~ ~~and~~ ~~December 31, 2012, we had~~ no ~~futures contracts outstanding related to this compliance program. For the~~ ~~three~~ ~~months ended~~ ~~March 31, 2012, the loss recognized in income on these derivative instruments designated as economic hedges was immaterial and therefore not separately presented in the table below under~~ ~~“Effect of Derivative Instruments on Income and Other Comprehensive Income.”~~

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~~VALERO ENERGY CORPORATION AND SUBSIDIARIES~~

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

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,~~June 30, 2013 or December 31, 2012, or during the three and ~~three~~six months ended ~~March 31,~~June 30, 2013 and 2012.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Foreign Currency Risk

We are exposed to exchange rate fluctuations on transactions entered into by our international operations that are denominated in currencies other than the local (functional) currencies of those operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of ~~March 31,~~June 30, 2013, we had commitments to purchase $~~576~~581 million of U.S. dollars. These commitments matured on or before ~~April 30,~~July 31, 2013, resulting in an immaterial loss in the ~~second~~third quarter of 2013.

Compliance Program Price Risk

We are exposed to market risk related to the volatility in the price of credits needed to comply with various governmental and regulatory programs. The most significant programs impacting our operations are those that require us to blend biofuels into the products we produce, and we are subject to such programs in most of the countries in which we operate. 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, we must purchase biofuel credits (primarily RINs in the U.S.). We are exposed to the volatility in the market price of these credits, and we manage that risk by purchasing biofuel credits when prices are deemed favorable. Due to rising RINs prices in the U.S. during the six months ended June 30, 2013, we purchased a portion of our expected RINs obligation for 2013. The cost of meeting our obligations under these compliance programs was $137 million and $59 million for the three months ended June 30, 2013 and 2012, respectively, and $267 million and $126 million for the six months ended June 30, 2013 and 2012, respectively. These amounts are reflected in cost of sales.

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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 ~~March 31,~~June 30, 2013 and December 31, 2012 (in millions) and the line items in the balance sheets in which the fair values are reflected. See Note 12 for additional information related to the fair values of our derivative instruments.

As indicated in Note 12, we net fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty under master netting arrangements, including cash collateral assets and obligations. 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.


	Balance Sheet Location	March 31, 2013				Balance Sheet Location	June 30, 2013
	Balance Sheet Location	Asset Derivatives		Liability Derivatives		Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	14	$	28	Receivables, net	$	49	$	53

Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	1,022	$	953	Receivables, net	$	966	$	942
Swaps	Receivables, net	17		15		Receivables, net	16		11
Swaps	Prepaid expenses and other	1		1		Prepaid expenses and other	2		1
Swaps	Accrued expenses	5		11		Accrued expenses	5		11
Options	Receivables, net	5		3		Receivables, net	4		6
Options	Prepaid expenses and other	2		1		Prepaid expenses and other	1		—
Options	Accrued expenses	—		1		Accrued expenses	—		1
Physical purchase contracts	Inventories	13		5		Inventories	5		11
RINs fixed-price contracts	Prepaid expenses and other	7		19		Prepaid expenses and other	—		22
Foreign currency contracts	Accrued expenses	—		3		Receivables, net	10		—
Total		$	1,072	$	1,012		$	1,009	$	1,005
Total derivatives		$	1,086	$	1,040		$	1,058	$	1,058

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Balance Sheet Location	December 31, 2012
	Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	77	$	64
Swaps	Receivables, net	15		13
Swaps	Prepaid expenses and other	2		2
Total		$	94	$	79

Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	1,066	$	1,073
Swaps	Receivables, net	9		6
Swaps	Accrued expenses	32		46
Options	Receivables, net	1		4
Options	Accrued expenses	1		—
Physical purchase contracts	Inventories	11		—
Foreign currency contracts	Receivables, net	1		—
Foreign currency contracts	Accrued expenses	—		1
Total		$	1,121	$	1,130
Total derivatives		$	1,215	$	1,209

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.

There were no material amounts due from counterparties in the refining or financial services industry as of ~~March 31,~~June 30, 2013 or December 31, 2012. These amounts represent the aggregate amount payable to us by companies in those industries, reduced by payables from us to those companies under master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party. We do not require any collateral or other security to support derivative instruments into which we enter. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments on Income and Other Comprehensive Income

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

Derivatives in Fair Value
Hedging Relationships

Location of Gain (Loss)
Recognized in Income
on Derivatives
Three Months Ended
March 31,
2013 2012
Commodity contracts:
Loss recognized in
income on derivatives
Cost of sales $ (1 ) $ (267 )
Gain recognized in
income on hedged item
Cost of sales —
228
Loss recognized in
income on derivatives
(ineffective portion)
Cost of sales (1 ) (39 )



Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended June 30,						Six Months Ended June 30,
Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2013			2012			2013			2012
Commodity contracts:
Gain (loss) recognized in income on derivatives	Cost of sales	$	(20	)	$	87		$	(21	)	$	(180	)
Gain (loss) recognized in income on hedged item	Cost of sales	22			(91		)	22			137
Gain (loss) recognized in income on derivatives (ineffective portion)	Cost of sales	2			(4		)	1			(43		)

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 ~~three~~six months ended ~~March 31,~~June 30, 2013 and 2012. There were no amounts recognized in income for hedged firm commitments that no longer qualified as fair value hedges during the three or sixmonths ended ~~March 31,~~June 30, 2013. ~~No amounts were~~We recognized a gain of $28 million in income for hedged firm commitments that no longer ~~qualify~~qualified as fair value hedges ~~for~~during the three and ~~three~~six months ended ~~March 31,~~June 30, 2012.

Derivatives in Cash Flow
Hedging Relationships

Location of Gain (Loss)
Recognized in Income
on Derivatives
Three Months Ended
March 31,
2013 2012
Commodity contracts:
Gain recognized in
OCI on derivatives
(effective portion)
$ 1
$ 47
Gain reclassified from
accumulated OCI
into income
(effective portion)
Cost of sales 3
48
Loss recognized in
income on derivatives
(ineffective portion)
Cost of sales (1 ) (5 )



Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended June 30,						Six Months Ended June 30,
Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2013			2012			2013			2012
Commodity contracts:
Gain (loss) recognized in OCI on derivatives (effective portion)		$	(10	)	$	(31	)	$	(9	)	$	16
Gain (loss) reclassified from accumulated OCI into income (effective portion)	Cost of sales	(8		)	(12		)	(5		)	36
Gain (loss) recognized in income on derivatives (ineffective portion)	Cost of sales	(2		)	31			(3		)	26

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For cash flow hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and ~~three~~six months ended ~~March 31,~~June 30, 2013 and 2012. For the three and ~~three~~six months ended ~~March 31,~~June 30, 2013, cash flow hedges primarily related to forward sales of gasoline and distillates, and associated forward purchases of crude oil, with $12 million of cumulative after-tax losses on cash flow hedges remaining in accumulated other comprehensive income. We estimate that $13 million of the deferred loss as of ~~March 31,~~June 30, 2013 will be reclassified into cost of sales over the next 12 months as a result of hedged transactions that are forecasted to occur. For the three and ~~three~~six months ended ~~March 31,~~June 30, 2013 and 2012, there were no amounts reclassified from accumulated other comprehensive income into income as a result of the discontinuance of cash flow hedge accounting.


Derivatives Designated as Economic Hedges and Other Derivative Instruments	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,					Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended June 30,				Six Months Ended June 30,
	Location of Gain (Loss) Recognized in Income on Derivatives	2013		2012			Location of Gain (Loss) Recognized in Income on Derivatives	2013		2012		2013		2012
Commodity contracts	Cost of sales	$	35	$	(151	)	Cost of sales	$	246	$	574	$	281	$	423
Foreign currency contracts	Cost of sales	25		(23		)	Cost of sales	11		1		36		(22		)
Total		$	60	$	(174	)		$	257	$	575	$	317	$	401


Trading Derivatives	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,						Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended June 30,					Six Months Ended June 30,
Trading Derivatives	Location of Gain (Loss) Recognized in Income on Derivatives	2013			2012			Location of Gain (Loss) Recognized in Income on Derivatives	2013			2012		2013			2012
Commodity contracts	Cost of sales	$	2		$	(4	)	Cost of sales	$	3		$	8	$	5		$	4
RINs contracts	Cost of sales	(13		)	—
RINs fixed-price contracts								Cost of sales	(7		)	—		(20		)	—
Total		$	(11	)	$	(4	)		$	(4	)	$	8	$	(15	)	$	4

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

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

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

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

future refining margins, including gasoline and distillate margins;

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

~~future~~ ethanol margins;

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

anticipated levels of crude oil and refined product inventories;

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

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

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

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

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

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

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

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

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

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

the level of consumer demand, including seasonal fluctuations;

refinery overcapacity or undercapacity;

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

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

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

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

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

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

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

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

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

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

legislative or regulatory action, including the introduction or enactment of legislation or rulemakings by governmental authorities, including tax and environmental regulations, such as those to be implemented under the California Global Warming Solutions Act (also known as AB 32) and the United States (U.S.) Environmental Protection Agency’s (EPA) regulation of greenhouse gases, which may adversely affect our business or operations;

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

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

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

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

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

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OVERVIEW AND OUTLOOK

Overview

For the ~~first~~second quarter of 2013, we reported net income attributable to Valero stockholders of $~~654~~466 million, or $~~1.18~~0.85 per share (assuming dilution), compared to ~~a net loss attributable to Valero stockholders of~~ $~~432~~831 million, or $~~0.78~~1.50 per share (assuming dilution), for the ~~first~~second quarter of 2012.

The ~~increase~~decrease in net income attributable to Valero stockholders of $~~1.1 billion~~365 million was primarily due to the ~~increase~~decrease of $~~1.3 billion~~553 million in our operating income as outlined by business segment in the following table (in millions):


	Three Months Ended March 31,									Three Months Ended June 30,
	2013			2012			Change			2013			2012			Change
Operating income (loss) by business segment:
Refining	$	1,212		$	(119	)	$	1,331		$	921		$	1,364		$	(443	)
Retail	42			40			2			39			172			(133		)
Ethanol	14			9			5			95			5			90
Corporate	(207		)	(174		)	(33		)	(247		)	(180		)	(67		)
Total	$	1,061		$	(244	)	$	1,305		$	808		$	1,361		$	(553	)

The ~~results for~~$443 million decrease in refining segment operating income in the ~~first~~second quarter of ~~2012 were significantly impacted by asset impairment losses of~~ ~~$611 million, of which~~ ~~$595 million~~2013 ~~related~~compared to ~~our Aruba Refinery (as further discussed in~~ ~~Note 3~~ ~~of Condensed Notes to Consolidated Financial Statements). Excluding these noncash asset impairment losses, total operating income for~~ the ~~first~~second quarter of 2012 ~~would have been $367 million, reflecting a $694 million favorable increase between the quarters, and our refining operating income for the~~ ~~first quarter~~ of ~~2012~~ ~~would have been~~ ~~$492 million, reflecting a~~ ~~$720 million~~ ~~favorable increase between the years.~~

~~The~~ ~~$720 million~~ ~~increase in refining segment operating income~~ was primarily due to ~~higher~~lower refining ~~throughput~~ margins in each of our ~~regions, except the U.S. West Coast.~~regions. The ~~increase~~decrease in refining ~~throughput~~ margins was ~~mainly due to an increase in margins~~the result of significantly lower discounts for ~~diesel and jet fuel and wider discounts on crude oil.~~

~~Our U.S. Gulf Coast region benefited during the~~ ~~first quarter~~ of ~~2013~~ ~~from improved discounts on heavy~~ sour crude oils, versus a Brent benchmark crude oil plus contributions from our new hydrocracker at our Port Arthur Refinery. Our U.S. Mid-Continent region continued to benefit from lower cost U.S. inland (domestic) light crude oils during the quarter. Because the market for refined products generally tracks the pricehigher costs of Brent crude oil, we benefit when domestic light crude oils that are priced off of West Texas Intermediate (WTI) are discounted relative to Brent. Domestic light crude oils remain discounted relative to Brent due to the significant development of domestic crude oil reserves and increased deliveries of crude oil from Canada. Our North Atlantic region continued to benefit during the quarter from higher refined product prices largely due to a reduction of supply in the region that began in 2012 as a result of numerous refinery shutdowns in the U.S. East Coast, Caribbean, and Western Europe, that continued into 2013.

~~Outlook~~

We expect that the benefit we receive from processing domestic light crude oils will continue during 2013. However, this benefit may decrease as various crude oil pipeline and logistics projects are completed. These projects will allow these cost-advantaged crude oils from the inland U.S. and Canada to be transported to the U.S. Gulf Coast, which is expected to result in a narrowing of the price differential of WTI-priced crude oil relative to Brent-priced crude oil. As a result, margins have declined in the second quarter for refineries in the U.S. Mid-Continent region that process WTI-priced crude oils. In addition, heavy sour crude oil discounts have narrowed in the second quarter of 2013.

~~Table of Contents~~

Our investment strategy focuses on three areas — logistics, processing cost-advantaged crude oil, and distillates-focused hydrocracking. In order to take advantage of the significant growth in crude oil production in the U.S. and Canada, we are investing in more logistics projects in order to transport these discounted crude oils to our refineries and to increase our ability to export products. For example, during the first quarter of 2013, we ordered 2,500 additional rail cars and invested in other logistics assets. Since much of the new production is light crude oil, we are investing at certain of our refineries to increase the front-end flexibility to process more volumes of these cost-advantaged crude oils. Our other growth investments focus on completing our hydrocracker projects to produce more diesel and jet fuel. We expect the hydrocracker at our St. Charles Refinery to commence operations late in the second quarter of 2013.

Recent refinery closures in the U.S. East Coast, Caribbean, and Western Europe and additional closures expected to occur in the industry combined with poor reliability and low utilization in Latin American refineries create opportunities for competitive refineries to export quality products at higher margins. However, some marginally profitable refineries may continue to be operated, which could negatively impact refined product margins.

~~Turnaround activity continues in the second quarter of 2013 with work at our Meraux and McKee Refineries plus a plant-wide turnaround planned for two months at our Quebec City Refinery.~~

Thus far in the second quarter of 2013, ethanol margins have improved primarily due to declining corn prices. We expect a continued modest improvement in ethanol margins throughout 2013 relative to those in 2012.

Energy markets and margins are volatile, and we expect them to continue to be volatile in the near to mid-term. Due to our obligation to blend biofuels into the products we produce in most of the countries in which we operate, and our inability to blend biofuels at the applicable rate in the U.S., we must purchasebiofuel credits (primarily Renewable Identification Numbers (RINs) inneeded to comply with the U.S. federal Renewable Fuel Standard (RFS)), and are therefore exposed to the volatility in the market price of these financial instruments. During the first quarter of 2013, we purchased a portion of our expected obligation for 2013 due to rising RINs prices. As further discussed in Note 13 of Condensed Notes to Consolidated Financial Statements, the cost of meeting our obligations under this compliance program was higher natural gas costs.~~$130 million~~ for the first quarter of 2013. We estimate that the cost of meeting our obligation for the full year of 2013 is between $500 million and $750 million based on recent RINs prices and our estimate of the expected RINs purchase requirement.

On May 1, 2013, we completed the separation of our retail business, creating an independent public company named CST Brands, Inc. (CST), and as a result, we no longer operate a retail business. Therefore, retail segment operating income for the second quarter of 2013 reflects the operations of our former retail business for only the month of April 2013, which is the primary reason for the $133 million decrease in retail segment operating income in the second quarter of 2013 compared to the second quarter of 2012. ~~This transaction~~The separation of our retail business is more fully discussed in Note 2 of Condensed Notes to Consolidated Financial Statements.

Our ethanol segment operating income in the second quarter of 2013 increased $90 million compared to the second quarter of 2012 due to higher gross margins per gallon and higher production volumes. Ethanol prices increased quarter over quarter due to a decrease in the supply of ethanol resulting from lower industry production volumes throughout 2012 and the first quarter of 2013. Demand for ethanol, however, remained consistent and drove the increase in ethanol prices as supplies were decreasing. We increased our production of ethanol in the second quarter of 2013 to capture the improved economics of higher gross margins per gallon during the quarter.

For the first six months of 2013, we reported net income attributable to Valero stockholders of $1.1 billion, or $2.03 per share (assuming dilution), compared to $399 million, or $0.72 per share (assuming dilution), for the first six months of 2012.

Table of Contents

The increase in net income attributable to Valero stockholders of $721 million was primarily due to the increase of $752 million in our operating income as outlined by business segment in the following table (in millions):



	Six Months Ended June 30,
	2013			2012			Change
Operating income (loss) by business segment:
Refining	$	2,133		$	1,245		$	888
Retail	81			212			(131		)
Ethanol	109			14			95
Corporate	(454		)	(354		)	(100		)
Total	$	1,869		$	1,117		$	752

The results for the first six months of 2012 were significantly impacted by asset impairment losses of $611 million primarily related to our Aruba Refinery, which are further discussed in Note 3 of Condensed Notes to Consolidated Financial Statements. Excluding these noncash asset impairment losses, total operating income for the first six months of 2012 would have been $1.7 billion and the increase in total operating income and refining segment operating income in the first six months of 2013 compared to the first six months of 2012 would have been $141 million and $277 million, respectively.

The $277 million increase in refining segment operating income in the first six months of 2013 compared to the first six months of 2012 was primarily due to higher refining margins in most of our regions, which resulted from improved gasoline and distillate margins. These improvements, however, were negatively impacted by higher costs of biofuel credits (primarily RINs in the U.S.), and higher natural gas costs during the second quarter of 2013. The $131 million decrease in retail segment operating income in the first six months of 2013 compared to the first six months of 2012 was primarily due to the separation of our retail business on May 1, 2013, as previously discussed, and the reasons for the $95 million increase in ethanol segment operating income between the six-month periods are also consistent with those previously discussed.

Outlook

During 2011, 2012 and the first quarter of 2013, our refining segment benefited from processing heavy sour crude oils (such as Maya crude oil) due to the favorable discounts between the price of this type of crude oil and the price of Brent crude oil. Because the market for refined products generally tracks the price of Brent crude oil, which is a benchmark sweet crude oil, we ~~announced~~benefit when we process crude oils that are priced at a discount to Brent crude oil. During the second quarter of 2013, the discount in the price of heavy sour crude oils compared to the price of Brent crude oil narrowed significantly and negatively impacted our refining margins. For the remainder of 2013, we ~~were evaluating~~expect the discounts on heavy sour crude oils to improve as heavy Canadian crude oils are transported into the U.S. Gulf Coast region and increased offshore production in the U.S. Gulf Coast is anticipated. Energy markets and margins are volatile, and we expect them to continue to be volatile in the near to mid-term.

We are obligated to blend biofuels into the products we produce, and because we are unable to blend biofuels at the applicable rates, we must purchase biofuel credits (primarily RINs in the U.S.) in the open market and are therefore exposed to the volatility in the market price of these credits. During the first six months of 2013, the market price of RINs increased significantly, resulting in higher costs. As further discussed in Note 13 of Condensed Notes to Consolidated Financial Statements, the cost of meeting our obligations under various biofuel blending compliance programs was $267 million for the first six months of 2013. We estimate that the cost of meeting our obligation for the full year of 2013 will be between $600 million and $800 million based on recent prices for these biofuel credits and our estimate of the expected purchase requirement.

We continue to evaluate forming a master limited partnership for our ~~growing~~ portfolio of logistics assets. ~~We expect to continue to evaluate this strategy during the second half of 2013.~~

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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)

(millions of dollars, except per share amounts)


	Three Months Ended March 31,									Three Months Ended June 30,
	2013			2012			Change			2013			2012			Change
Operating revenues	$	33,474		$	35,167		$	(1,693	)	$	34,034		$	34,662		$	(628	)
Costs and expenses:
Cost of sales	30,685			33,035			(2,350		)	31,523			31,621			(98		)
Operating expenses:
Refining	876			964			(88		)	906			868			38
Retail	169			166			3			57			170			(113		)
Ethanol	77			87			(10		)	102			85			17
General and administrative expenses	176			164			12			233			171			62
Depreciation and amortization expense:
Refining	358			337			21			369			338			31
Retail	30			27			3			11			29			(18		)
Ethanol	11			10			1			11			10			1
Corporate	31			10			21			14			9			5
Asset impairment losses (a)	—			611			(611		)
Total costs and expenses	32,413			35,411			(2,998		)	33,226			33,301			(75		)
Operating income (loss)	1,061			(244		)	1,305
Other income, net	14			6			8
Operating income										808			1,361			(553		)
Other income (expense), net										11			(5		)	16
Interest and debt expense, net of capitalized interest	(83		)	(99		)	16			(78		)	(74		)	(4		)
Income (loss) before income tax expense	992			(337		)	1,329
Income before income tax expense										741			1,282			(541		)
Income tax expense	340			95			245			276			452			(176		)
Net income (loss)	652			(432		)	1,084
Net income										465			830			(365		)
Less: Net loss attributable to noncontrolling interests	(2		)	—			(2		)	(1		)	(1		)	—
Net income (loss) attributable to Valero stockholders	$	654		$	(432	)	$	1,086
Net income attributable to Valero stockholders										$	466		$	831		$	(365	)

Earnings per common share – assuming dilution	$	1.18		$	(0.78	)	$	1.96		$	0.85		$	1.50		$	(0.65	)

________________

See note references on page 43.

3839

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Refining Operating Highlights

(millions of dollars, except per barrel amounts)

Three Months Ended March 31,
2013 2012 Change
Refining:
Operating income (loss) (a) $ 1,212
$ (119 ) $ 1,331
Throughput margin per barrel (b) $ 10.59
$ 7.71
$ 2.88
Operating costs per barrel (a):
Operating expenses 3.79
4.15
(0.36 )
Depreciation and amortization expense 1.55
1.45
0.10
Total operating costs per barrel 5.34
5.60
(0.26 )
Operating income per barrel (a) $ 5.25
$ 2.11
$ 3.14

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude 494
451
43
Medium/light sour crude 419
555
(136 )
Sweet crude 1,089
956
133
Residuals 224
169
55
Other feedstocks 83
144
(61 )
Total feedstocks 2,309
2,275
34
Blendstocks and other 257
280
(23 )
Total throughput volumes 2,566
2,555
11

Yields (thousand barrels per day):
Gasolines and blendstocks 1,198
1,191
7
Distillates 909
911
(2 )
Other products (c) 480
469
11
Total yields 2,587
2,571
16

~~_______________~~

~~See note references on page~~ 43.

~~Table of Contents~~

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

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


	Three Months Ended March 31,									Three Months Ended June 30,
	2013			2012			Change			2013		2012		Change
U.S. Gulf Coast (a):
Refining:
Operating income	$	591		$	235		$	356		$	921	$	1,364	$	(443	)
Throughput volumes (thousand barrels per day)	1,421			1,476			(55		)
Throughput margin per barrel (b)	$	10.00		$	6.92		$	3.08		$	9.26	$	10.63	$	(1.37	)
Operating costs per barrel:
Operating expenses	3.77			3.67			0.10			3.82		3.59		0.23
Depreciation and amortization expense	1.61			1.50			0.11			1.56		1.40		0.16
Total operating costs per barrel	5.38			5.17			0.21			5.38		4.99		0.39
Operating income per barrel	$	4.62		$	1.75		$	2.87		$	3.88	$	5.64	$	(1.76	)

U.S. Mid-Continent:
Operating income	$	477		$	254		$	223
Throughput volumes (thousand barrels per day)	424			398			26
Throughput margin per barrel (b)	$	17.41		$	13.80		$	3.61
Operating costs per barrel:
Operating expenses	3.37			5.31			(1.94		)
Depreciation and amortization expense	1.55			1.50			0.05
Total operating costs per barrel	4.92			6.81			(1.89		)
Operating income per barrel	$	12.49		$	6.99		$	5.50
Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude										488		390		98
Medium/light sour crude										463		609		(146		)
Sweet crude										896		1,022		(126		)
Residuals										315		215		100
Other feedstocks										120		122		(2		)
Total feedstocks										2,282		2,358		(76		)
Blendstocks and other										324		300		24
Total throughput volumes										2,606		2,658		(52		)

North Atlantic:
Operating income	$	186		$	61		$	125
Throughput volumes (thousand barrels per day)	485			461			24
Throughput margin per barrel (b)	$	8.45		$	5.64		$	2.81
Operating costs per barrel:
Operating expenses	3.32			3.52			(0.20		)
Depreciation and amortization expense	0.86			0.66			0.20
Total operating costs per barrel	4.18			4.18			—
Operating income per barrel	$	4.27		$	1.46		$	2.81

U.S. West Coast:
Operating loss	$	(42	)	$	(58	)	$	16
Throughput volumes (thousand barrels per day)	236			220			16
Throughput margin per barrel (b)	$	6.26		$	6.32		$	(0.06	)
Operating costs per barrel:
Operating expenses	5.68			6.56			(0.88		)
Depreciation and amortization expense	2.56			2.67			(0.11		)
Total operating costs per barrel	8.24			9.23			(0.99		)
Operating loss per barrel	$	(1.98	)	$	(2.91	)	$	0.93

Operating income for regions above	$	1,212		$	492		$	720
Asset impairment losses (a)	—			(611		)	611
Total refining operating income (loss)	$	1,212		$	(119	)	$	1,331
Yields (thousand barrels per day):
Gasolines and blendstocks										1,281		1,294		(13		)
Distillates										910		918		(8		)
Other products (c)										441		469		(28		)
Total yields										2,632		2,681		(49		)

_______________

See note references on page 43.

Table of Contents

~~Average Market Reference Prices and Differentials~~Refining Operating Highlights by Region (d)

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

amounts)

Three Months Ended March 31,
2013 2012 Change
Feedstocks:
Brent crude oil $ 112.63
$ 118.34
$ (5.71 )
Brent less WTI crude oil 18.33
15.46
2.87
Brent less Alaska North Slope (ANS) crude oil 2.31
0.65
1.66
Brent less Louisiana Light Sweet (LLS) crude oil (2.49 ) (1.82 ) (0.67 )
Brent less Mars crude oil 2.32
2.39
(0.07 )
Brent less Maya crude oil 9.68
9.33
0.35
LLS crude oil 115.12
120.16
(5.04 )
LLS less Mars crude oil 4.81
4.21
0.60
LLS less Maya crude oil 12.17
11.15
1.02
WTI crude oil 94.30
102.88
(8.58 )

Natural gas (dollars per million British thermal units) 3.43
2.39
1.04

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less Brent 6.55
7.12
(0.57 )
Ultra-low-sulfur diesel less Brent 16.97
14.24
2.73
Propylene less Brent 6.48
(12.48 ) 18.96
Conventional 87 gasoline less LLS 4.06
5.30
(1.24 )
Ultra-low-sulfur diesel less LLS 14.48
12.42
2.06
Propylene less LLS 3.99
(14.30 ) 18.29
U.S. Mid-Continent:
Conventional 87 gasoline less WTI 23.83
18.28
5.55
Ultra-low-sulfur diesel less WTI 35.48
27.75
7.73
North Atlantic:
Conventional 87 gasoline less Brent 10.96
7.73
3.23
Ultra-low-sulfur diesel less Brent 18.70
15.87
2.83
U.S. West Coast:
CARBOB 87 gasoline less ANS 14.10
14.24
(0.14 )
CARB diesel less ANS 21.37
18.28
3.09
CARBOB 87 gasoline less WTI 30.12
29.05
1.07
CARB diesel less WTI 37.39
33.09
4.30
New York Harbor corn crush (dollars per gallon) (0.08 ) (0.05 ) (0.03 )



	Three Months Ended June 30,
	2013		2012		Change
U.S. Gulf Coast:
Operating income	$	414	$	637	$	(223	)
Throughput volumes (thousand barrels per day)	1,530		1,491		39
Throughput margin per barrel (b)	$	8.12	$	9.50	$	(1.38	)
Operating costs per barrel:
Operating expenses	3.63		3.40		0.23
Depreciation and amortization expense	1.51		1.41		0.10
Total operating costs per barrel	5.14		4.81		0.33
Operating income per barrel	$	2.98	$	4.69	$	(1.71	)

U.S. Mid-Continent:
Operating income	$	343	$	444	$	(101	)
Throughput volumes (thousand barrels per day)	422		404		18
Throughput margin per barrel (b)	$	14.20	$	17.61	$	(3.41	)
Operating costs per barrel:
Operating expenses	3.69		3.97		(0.28		)
Depreciation and amortization expense	1.59		1.55		0.04
Total operating costs per barrel	5.28		5.52		(0.24		)
Operating income per barrel	$	8.92	$	12.09	$	(3.17	)

North Atlantic:
Operating income	$	70	$	172	$	(102	)
Throughput volumes (thousand barrels per day)	370		473		(103		)
Throughput margin per barrel (b)	$	7.18	$	8.01	$	(0.83	)
Operating costs per barrel:
Operating expenses	3.90		3.22		0.68
Depreciation and amortization expense	1.20		0.80		0.40
Total operating costs per barrel	5.10		4.02		1.08
Operating income per barrel	$	2.08	$	3.99	$	(1.91	)

U.S. West Coast:
Operating income	$	94	$	111	$	(17	)
Throughput volumes (thousand barrels per day)	284		290		(6		)
Throughput margin per barrel (b)	$	10.81	$	10.95	$	(0.14	)
Operating costs per barrel:
Operating expenses	4.93		4.62		0.31
Depreciation and amortization expense	2.22		2.11		0.11
Total operating costs per barrel	7.15		6.73		0.42
Operating income per barrel	$	3.66	$	4.22	$	(0.56	)

Total refining operating income	$	921	$	1,364	$	(443	)

_______________

See note references on page 43.

Table of Contents

~~Retail~~Average Market Reference Prices and ~~Ethanol Operating Highlights~~Differentials

(~~millions of~~ dollars per barrel, except ~~per gallon amounts)~~as noted)

Three Months Ended March 31,
2013 2012 Change
Retail–U.S.:
Operating income $ 18
$ 11
$ 7
Company-operated fuel sites (average) 1,033
997
36
Fuel volumes (gallons per day per site) 5,048
5,046
2
Fuel margin per gallon (e) $ 0.08
$ 0.05
$ 0.03
Merchandise sales $ 293
$ 288
$ 5
Merchandise margin (percentage of sales) 29.7 % 29.5 % 0.2 %
Margin on miscellaneous sales $ 22
$ 24
$ (2 )
Operating expenses $ 107
$ 104
$ 3
Depreciation and amortization expense $ 21
$ 18
$ 3

Retail–Canada:
Operating income $ 24
$ 29
$ (5 )
Fuel volumes (thousand gallons per day) 2,987
3,097
(110 )
Fuel margin per gallon (e) $ 0.26
$ 0.26
$ —
Merchandise sales $ 59
$ 58
$ 1
Merchandise margin (percentage of sales) 27.5 % 29.3 % (1.8 )%
Margin on miscellaneous sales $ 11
$ 11
$ —
Operating expenses $ 62
$ 62
$ —
Depreciation and amortization expense $ 9
$ 9
$ —

Ethanol:

Operating income $ 14
$ 9
$ 5
Production (thousand gallons per day) 2,712
3,478
(766 )
Gross margin per gallon of production (b) $ 0.42
$ 0.34
$ 0.08
Operating costs per gallon of production:

Operating expenses 0.31
0.28
0.03
Depreciation and amortization expense 0.05
0.03
0.02
Total operating costs per gallon of production 0.36
0.31
0.05
Operating income per gallon of production $ 0.06
$ 0.03
$ 0.03



	Three Months Ended June 30,
	2013			2012			Change
Feedstocks:
Brent crude oil	$	103.36		$	108.95		$	(5.59	)
Brent less WTI crude oil	9.17			15.51			(6.34		)
Brent less Alaska North Slope (ANS) crude oil	(0.91		)	(0.65		)	(0.26		)
Brent less Louisiana Light Sweet (LLS) crude oil	(1.78		)	0.02			(1.80		)
Brent less Mars crude oil	3.53			4.22			(0.69		)
Brent less Maya crude oil	5.46			9.86			(4.40		)
LLS crude oil	105.14			108.93			(3.79		)
LLS less Mars crude oil	5.31			4.20			1.11
LLS less Maya crude oil	7.24			9.84			(2.60		)
WTI crude oil	94.19			93.44			0.75

Natural gas (dollars per million British thermal units)	4.00			2.24			1.76

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less Brent	9.73			8.32			1.41
Ultra-low-sulfur diesel less Brent	16.79			14.65			2.14
Propylene less Brent	(6.76		)	(10.39		)	3.63
Conventional 87 gasoline less LLS	7.95			8.34			(0.39		)
Ultra-low-sulfur diesel less LLS	15.01			14.67			0.34
Propylene less LLS	(8.54		)	(10.37		)	1.83
U.S. Mid-Continent:
Conventional 87 gasoline less WTI	26.11			27.33			(1.22		)
Ultra-low-sulfur diesel less WTI	29.30			30.32			(1.02		)
North Atlantic:
Conventional 87 gasoline less Brent	11.34			12.43			(1.09		)
Ultra-low-sulfur diesel less Brent	18.17			16.11			2.06
U.S. West Coast:
CARBOB 87 gasoline less ANS	21.18			18.20			2.98
CARB diesel less ANS	17.09			15.09			2.00
CARBOB 87 gasoline less WTI	31.26			34.36			(3.10		)
CARB diesel less WTI	27.17			31.25			(4.08		)
New York Harbor corn crush (dollars per gallon)	0.28			(0.06		)	0.34

_______________

See note references on page 43.

Table of Contents

Retail and Ethanol Operating Highlights

(millions of dollars, except per gallon amounts)



	Three Months Ended June 30,
	2013		2012		Change
Retail:
Operating income	$	39	$	172	$	(133	)

Ethanol:
Operating income	$	95	$	5	$	90
Production (thousand gallons per day)	3,508		3,352		156
Gross margin per gallon of production (b)	$	0.65	$	0.32	$	0.33
Operating costs per gallon of production:
Operating expenses	0.32		0.28		0.04
Depreciation and amortization expense	0.03		0.03		—
Total operating costs per gallon of production	0.35		0.31		0.04
Operating income per gallon of production	$	0.30	$	0.01	$	0.29

_______________

See note references below.

The following notes relate to references on pages 3839 through 4243.

(a)

~~Asset impairment losses~~

On May 1, 2013, we completed the separation of our retail business to CST. This transaction is more fully discussed in Note 2 of Condensed Notes to Consolidated Financial Statements. As a result and effective May 1, 2013, our results of operations no longer include those of CST, except for our share of CST’s results of operations associated with the equity interest in CST retained by us, which is reflected in “other income (expense), net” in the three months ended ~~March 31, 2012 include~~June 30, 2013. The nature and significance of our post-separation participation in the supply of motor fuel to CST represents a ~~$595 million loss on~~continuation of activities with CST for accounting purposes. As such, the ~~write down~~historical results of ~~the Aruba Refinery and a $16 million loss~~operations related to ~~equipment associated with a permanently cancelled capital project at another refinery.~~CST have not been reported as discontinued operations in the statements of income.

The asset impairment loss related to the Aruba Refinery resulted from our decision in March 2012 to suspend refining operations at the refinery. Subsequently, in September 2012, we suspended refining operations indefinitely and reorganized the refinery into a crude oil and refined projects terminal; however, we continue to maintain the refining assets to allow them to be restarted and do not consider them abandoned.

The total asset impairment loss of $611 million ($605 million after taxes) is reflected in refining segment operating loss for the three months ended March 31, 2012, but it is excluded from operating costs per barrel and operating income per barrel for the refining segment and U.S. Gulf Coast region.


(b)	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.


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

(d)

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


~~(e)~~	~~Fuel margin per gallon is presented net of credit card fees.~~

General

Operating revenues decreased ~~5 percent~~$628 million (or ~~$1.7 billion~~2 percent) ~~for~~in the ~~first~~second quarter of 2013 compared to the ~~first~~second quarter of 2012 primarily as a result of lower average refined product prices between the two periods related to our refining segment operations. Operating income ~~and income before income tax expense each increased~~decreased $~~1.3 billion~~553 million ~~for~~in the ~~first~~second quarter of 2013 compared to ~~amounts reported for~~ the ~~first~~second quarter of 2012 primarily due to a $~~1.3 billion~~443 million ~~increase~~decrease in refining segment operating income, a $2133 million ~~increase~~decrease in retail segment operating income, and a $62 million increase in general and administrative expenses. These decreases in operating income, however, were partially offset by a $90 million increase in ethanol segment operating income. The reasons for these changes in the operating results of our segments and general and administrative expenses, as well as other items that affected our income, are discussed below.

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Refining

Refining segment operating income decreased $443 million from $1.4 billion in the second quarter of 2012 to $921 million in the second quarter of 2013 due to a $374 million decrease in refining margin, a $38 million increase in operating expenses, and a $31 million increase in depreciation and amortization expense.

Refining margin decreased $374 million (a $1.37 per barrel decrease) for the second quarter of 2013 compared to the second quarter of 2012 primarily due to the following:

Lower discounts on heavy sour crude oils - Because the market for refined products generally tracks the price of Brent crude oil, which is a benchmark sweet crude oil, we benefit when we process crude oils that are priced at a discount to Brent crude oil. During the second quarter of 2013, the discount in the price of heavy sour crude oils compared to the price of Brent crude oil narrowed significantly. For example, Maya crude oil, which is a sour crude oil, sold at a discount of $5.46 per barrel to Brent crude oil during the second quarter of 2013 compared to a discount of $9.86 per barrel during the second quarter of 2012, representing an unfavorable decrease of $4.40 per barrel. Therefore, the lower discount on the sour crude oils we processed negatively impacted our refining margin. We estimate that the decrease in the discounts for heavy sour crude oils that we processed had a negative impact to our refining margin of approximately $195 million, quarter versus quarter.

Higher costsof biofuel credits - As more fully described in Note 13 of Condensed Notes to Consolidated Financial Statements, we must purchase biofuel credits in order to meet our biofuel blending obligations under various government and regulatory compliance programs, and the cost of these credits (primarily RINs in the U.S.) increased by $78 million from $59 million in the second quarter of 2012 to $137 million in the second quarter of 2013. This increase was due to an increase in the market price of RINs caused by an ongoing expectation in the market of a shortage in available RINs by early next year when the RFS requires increased volumes of biofuel to be blended into refined products and a resulting increase in demand for RINs.

Higher natural gas prices - During the second quarter of 2013, natural gas prices increased to an average market price of $4.00 per mmBtu from $2.24 per mmBtu in the second quarter of 2012, resulting in an increase in natural gas costs and a corresponding decrease in our refining margin of approximately $57 million. Natural gas prices increased in 2013 due to a reduced supply of natural gas combined with the expected increase in demand from power generation plants as they switch from coal to natural gas. We use natural gas as a feedstock to produce hydrogen that is used in the refining process; therefore, the cost of natural gas impacts our refining margin as well as our operating expenses, which are discussed below.

The increase of $38 million in operating expenses was primarily due to a $50 million increase in energy costs related to higher natural gas costs and an $18 million increase in maintenance expenses due to higher maintenance activities in the second quarter of 2013 related to outages at our Meraux and Port Arthur Refineries. These increases were partially offset by a $23 million decrease in operating expenses incurred by our Aruba Refinery, whose operations were suspended in March 2012.

The increase of $31 million in depreciation and amortization expense was due to additional depreciation expense associated with new capital projects that began operating subsequent to the second quarter of 2012, consisting primarily of the new hydrocracker at our Port Arthur Refinery that began operating in late 2012.

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Retail

Retail segment operating income was $39 million for the second quarter of 2013 compared to $172 million for the second quarter of 2012. The $133 million decrease was primarily due to the separation of our retail business on May 1, 2013, which is more fully described in Note 2 of Notes to Consolidated Financial Statements. As a result of the separation, retail segment operating income for the second quarter of 2013 reflects the operations of our former retail business for only the month of April 2013.

Ethanol

Ethanol segment operating income was $95 million in the second quarter of 2013 compared to $5 million in the second quarter of 2012. The $90 million increase in operating income was primarily due to a $108 million increase in gross margin (a $0.33 per gallon increase), partially offset by a $17 million increase in operating expenses.

Gross margin increased primarily due to higher ethanol prices combined with increased ethanol production volumes between the second quarter of 2012 and the second quarter of 2013. Ethanol prices increased quarter over quarter due to a decrease in the supply of ethanol in the market. The decrease in supply resulted from reduced production in 2012 and early 2013 as the industry responded to a narrowing of gross margins, which were due to higher corn prices primarily caused by the drought in the corn-producing regions of the U.S. Mid-Continent that began in the second quarter of 2012. By the first quarter of 2013, ethanol inventory levels in the U.S. had declined to their lowest level in over three years and as a result, prices increased significantly beginning late in the first quarter of 2013. These price increases and increased demand resulted in higher production volumes, and our production volumes increased by 156,000 gallons per day between the comparable periods.

The $17 million increase in operating expenses during the second quarter of 2013 was due to a $17 million increase in energy costs primarily resulting from higher natural gas prices during the second quarter of 2013.

Corporate Expenses and Other

General and administrative expenses increased $62 million from the second quarter of 2012 to the second quarter of 2013 primarily due to $52 million of environmental and legal reserves that were recorded in the second quarter of 2013 and $30 million for transaction costs related to the separation of our retail business on May 1, 2013. These increases were partially offset by decreases in various other miscellaneous expenses.

“Interest and debt expense, net of capitalized interest” for the second quarter of 2013 increased $4 million from the second quarter of 2012. This increase was primarily due to an $8 million decrease in capitalized interest due to a corresponding decrease in capital expenditures, partially offset by a $13 million favorable impact from the decrease in average borrowings between the quarters.

Income tax expense decreased $176 million from the second quarter of 2012 to the second quarter of 2013 mainly as a result of lower income before income tax expense. Income tax expense for the three months ended June 30, 2013 also included $9 million incurred as a result of the separation of our retail business on May 1, 2013.

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Financial Highlights (a)

(millions of dollars, except per share amounts)



	Six Months Ended June 30,
	2013			2012			Change
Operating revenues	$	67,508		$	69,829		$	(2,321	)
Costs and expenses:
Cost of sales	62,208			64,656			(2,448		)
Operating expenses:
Refining	1,782			1,832			(50		)
Retail	226			336			(110		)
Ethanol	179			172			7
General and administrative expenses	409			335			74
Depreciation and amortization expense:
Refining	727			675			52
Retail	41			56			(15		)
Ethanol	22			20			2
Corporate	45			19			26
Asset impairment losses (b)	—			611			(611		)
Total costs and expenses	65,639			68,712			(3,073		)
Operating income	1,869			1,117			752
Other income, net	25			1			24
Interest and debt expense, net of capitalized interest	(161		)	(173		)	12
Income before income tax expense	1,733			945			788
Income tax expense	616			547			69
Net income	1,117			398			719
Less: Net loss attributable to noncontrolling interests	(3		)	(1		)	(2		)
Net income attributable to Valero stockholders	$	1,120		$	399		$	721

Earnings per common share – assuming dilution	$	2.03		$	0.72		$	1.31

_______________

See note references on page 50.

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Refining Operating Highlights

(millions of dollars, except per barrel amounts)



	Six Months Ended June 30,
	2013		2012		Change
Refining:
Operating income	$	2,133	$	1,245	$	888
Throughput margin per barrel (c)	$	9.92	$	9.20	$	0.72
Operating costs per barrel:
Operating expenses (b)	3.81		3.86		(0.05		)
Depreciation and amortization expense	1.55		1.43		0.12
Total operating costs per barrel	5.36		5.29		0.07
Operating income per barrel	$	4.56	$	3.91	$	0.65

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude	491		420		71
Medium/light sour crude	441		582		(141		)
Sweet crude	992		989		3
Residuals	270		192		78
Other feedstocks	101		133		(32		)
Total feedstocks	2,295		2,316		(21		)
Blendstocks and other	291		290		1
Total throughput volumes	2,586		2,606		(20		)

Yields (thousand barrels per day):
Gasolines and blendstocks	1,239		1,243		(4		)
Distillates	910		915		(5		)
Other products (d)	461		468		(7		)
Total yields	2,610		2,626		(16		)

_______________

See note references on page 50.

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Refining Operating Highlights by Region (e)

(millions of dollars, except per barrel amounts)



	Six Months Ended June 30,
	2013		2012			Change
U.S. Gulf Coast (b):
Operating income	$	1,005	$	872		$	133
Throughput volumes (thousand barrels per day)	1,476		1,483			(7		)
Throughput margin per barrel (c)	$	9.02	$	8.21		$	0.81
Operating costs per barrel:
Operating expenses	3.70		3.53			0.17
Depreciation and amortization expense	1.56		1.45			0.11
Total operating costs per barrel	5.26		4.98			0.28
Operating income per barrel	$	3.76	$	3.23		$	0.53

U.S. Mid-Continent:
Operating income	$	820	$	698		$	122
Throughput volumes (thousand barrels per day)	423		401			22
Throughput margin per barrel (c)	$	15.80	$	15.72		$	0.08
Operating costs per barrel:
Operating expenses	3.53		4.64			(1.11		)
Depreciation and amortization expense	1.57		1.52			0.05
Total operating costs per barrel	5.10		6.16			(1.06		)
Operating income per barrel	$	10.70	$	9.56		$	1.14

North Atlantic:
Operating income	$	256	$	233		$	23
Throughput volumes (thousand barrels per day)	427		467			(40		)
Throughput margin per barrel (c)	$	7.89	$	6.84		$	1.05
Operating costs per barrel:
Operating expenses	3.57		3.37			0.20
Depreciation and amortization expense	1.01		0.73			0.28
Total operating costs per barrel	4.58		4.10			0.48
Operating income per barrel	$	3.31	$	2.74		$	0.57

U.S. West Coast:
Operating income	$	52	$	53		$	(1	)
Throughput volumes (thousand barrels per day)	260		255			5
Throughput margin per barrel (c)	$	8.76	$	8.96		$	(0.20	)
Operating costs per barrel:
Operating expenses	5.27		5.46			(0.19		)
Depreciation and amortization expense	2.38		2.35			0.03
Total operating costs per barrel	7.65		7.81			(0.16		)
Operating income per barrel	$	1.11	$	1.15		$	(0.04	)

Operating income for regions above	$	2,133	$	1,856		$	277
Asset impairment losses (b)	—		(611		)	611
Total refining operating income	$	2,133	$	1,245		$	888

_______________

See note references on page 50.

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Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)



	Six Months Ended June 30,
	2013			2012			Change
Feedstocks:
Brent crude oil	$	108.00		$	113.64		$	(5.64	)
Brent less WTI crude oil	13.75			15.48			(1.73		)
Brent less ANS crude oil	0.70			(0.01		)	0.71
Brent less LLS crude oil	(2.13		)	(0.91		)	(1.22		)
Brent less Mars crude oil	2.93			3.30			(0.37		)
Brent less Maya crude oil	7.57			9.59			(2.02		)
LLS crude oil	110.13			114.55			(4.42		)
LLS less Mars crude oil	5.06			4.21			0.85
LLS less Maya crude oil	9.70			10.50			(0.80		)
WTI crude oil	94.25			98.16			(3.91		)

Natural gas (dollars per million British thermal units)	3.72			2.32			1.40

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less Brent	8.14			7.72			0.42
Ultra-low-sulfur diesel less Brent	16.88			14.44			2.44
Propylene less Brent	(0.14		)	(11.44		)	11.30
Conventional 87 gasoline less LLS	6.01			6.81			(0.80		)
Ultra-low-sulfur diesel less LLS	14.75			13.53			1.22
Propylene less LLS	(2.27		)	(12.35		)	10.08
U.S. Mid-Continent:
Conventional 87 gasoline less WTI	24.97			22.80			2.17
Ultra-low-sulfur diesel less WTI	32.39			29.03			3.36
North Atlantic:
Conventional 87 gasoline less Brent	11.15			10.08			1.07
Ultra-low-sulfur diesel less Brent	18.44			15.99			2.45
U.S. West Coast:
CARBOB 87 gasoline less ANS	17.64			16.22			1.42
CARB diesel less ANS	19.23			16.69			2.54
CARBOB 87 gasoline less WTI	30.69			31.71			(1.02		)
CARB diesel less WTI	32.28			32.18			0.10
New York Harbor corn crush (dollars per gallon)	0.10			(0.05		)	0.15

_______________

See note references on page 50.

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Retail and Ethanol Operating Highlights

(millions of dollars, except per gallon amounts)



	Six Months Ended June 30,
	2013		2012		Change
Retail:
Operating income	$	81	$	212	$	(131	)

Ethanol:
Operating income	$	109	$	14	$	95
Production (thousand gallons per day)	3,112		3,415		(303		)
Gross margin per gallon of production (c)	$	0.55	$	0.33	$	0.22
Operating costs per gallon of production:
Operating expenses	0.32		0.28		0.04
Depreciation and amortization expense	0.04		0.03		0.01
Total operating costs per gallon of production	0.36		0.31		0.05
Operating income per gallon of production	$	0.19	$	0.02	$	0.17

_______________

See note references below.

The following notes relate to references on pages 46 through 50.

(a)

On May 1, 2013, we completed the separation of our retail business to CST. This transaction is more fully discussed in Note 2 of Condensed Notes to Consolidated Financial Statements. As a result and effective May 1, 2013, our results of operations no longer include those of CST, except for our share of CST’s results of operations associated with the equity interest in CST retained by us, which is reflected in “other income (expense), net” in the six months ended June 30, 2013. The nature and significance of our post-separation participation in the supply of motor fuel to CST represents a continuation of activities with CST for accounting purposes. As such, the historical results of operations related to CST have not been reported as discontinued operations in the statements of income.

(b)

Asset impairment losses for the six months ended June 30, 2012 include a $595 million loss on the write down of the Aruba Refinery and a $16 million loss related to equipment associated with a permanently cancelled capital project at another refinery. The asset impairment loss related to the Aruba Refinery resulted from our decision in March 2012 to suspend refining operations at the refinery. Subsequently, in September 2012, we suspended refining operations indefinitely and reorganized the refinery into a crude oil and refined products terminal; however, we continue to maintain the refining assets to allow them to be restarted and do not consider them abandoned. The total asset impairment loss of $611 million ($605 million after taxes) is reflected in refining segment operating income for the six months ended June 30, 2012, but it is excluded from operating costs per barrel and operating income per barrel for the refining segment and U.S. Gulf Coast region.


(c)	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.


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

(e)

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

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General

Operating revenues decreased $2.3 billion (or 3 percent) in the first six months of 2013 compared to the first six months of 2012 primarily as a result of lower average refined product prices between the two periods related to our refining segment operations. However, operating income increased $752 million in the first six months of 2013 compared to the first six months of 2012 primarily due to an $888 million increase in refining segment operating income and a $95 million increase in ethanol segment operating income, ~~which~~partially offset by a $131 million decrease in retail segment operating income and a $74 million increase in general and administrative expenses. The reasons for these changes in the operating results of our segments and general and administrative expenses, as well as other items that affected our income, are discussed below.

Refining

Refining segment operating income increased $~~1.3~~888 million from $1.2 billion ~~from an operating loss of~~in the first ~~$119 million~~six ~~for the~~ ~~first quarter~~months of 2012 to ~~operating income of~~ $~~1.2~~2.1 billion ~~for~~in the first ~~first quarter~~six months of 2013. ~~The~~ ~~$1.3 billion~~This increase, ~~in operating income~~however, was ~~impacted by~~largely the result of $611 million in asset impairment ~~loss~~losses in the first ~~first quarter~~six months of 2012 primarily related to our Aruba ~~Refinery. (See~~ Refinery, which is more fully described in Note 3 of Condensed Notes to Consolidated Financial ~~Statements for further discussion of the impairment losses.)~~Statements. Excluding the prior year asset impairment losses, refining segment operating income increased $~~720~~277 million ~~primarily~~ due to a $~~653~~279 million increase in refining margin and ana $8850 million decrease in operating ~~expenses.~~expenses, partially offset by a $52 million increase in depreciation and amortization expense.

~~The increase in our refining~~Refining margin ofincreased $~~653~~279 million (a $~~2.88~~0.72 per barrel ~~increase, or 37 percent)~~increase) in the first six months of 2013 compared to the first ~~quarter~~six months of 2012, primarily due to the following:

Increase in gasoline and distillate margins - We experienced improved gasoline and distillate margins throughout all our regions for the first six months of 2013 compared to the first six months of 2012. For example, the WTI-based benchmark reference margin for U.S. Mid-Continent conventional 87 gasoline was $24.97 per barrel for the first six months of 2013 compared to $22.80 per barrel for the first six months of 2012, representing a favorable increase of $2.17 per barrel. In addition the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel (a type of distillate) was $32.39 per barrel for the first six months of 2013 as compared to $29.03 per barrel for the first ~~first quarter~~six months of 2012 ~~resulted from margin improvements generated by our U.S. Gulf Coast, U.S. Mid-Continent, and North Atlantic regions, which experienced~~, representing a favorable increase of $3.36 per barrel. We estimate that the increases in ~~refining margin of $350 million (a~~ ~~$3.08~~gasoline and distillate margins per barrel ~~increase), $165 million (a~~ ~~$3.61~~ ~~per barrel increase), and $132 millions (a~~ ~~$2.81~~ ~~per barrel increase), respectively. The increase in refining margin was mainly due to an increase in margins for diesel and jet fuel and wider discounts on crude oils.~~

~~The $350 million increase in refining margin~~ in the ~~U.S. Gulf Coast was primarily~~first six months of 2013 compared to the ~~result~~first six months of a ~~$0.35~~2012 per barrel increase in the discount between the price of Maya crude oil and other heavy sour crude oils that price at a discount to Maya versus Brent crude oil. Brent crude oil is the type of crude oil used by the market to set the price of refined products, but certain of our refineries in the U.S. Gulf Coast region process heavy sour crude oils like Maya and Maya-type crude oils; therefore, the increase in the price discount between Maya-type crude oils versus Brent crude oil had a positive impact to our refining margin of approximately $130 million and $400 million, respectively, for all refining regions.

Higher costs of biofuel credits - As more fully described in ~~this region. Maya-type crude oil discounts improved~~Note 13 of Condensed Notes to Consolidated Financial Statements, we must purchase biofuel credits in order to meet our biofuel blending obligation under various government and regulatory compliance programs, and the cost of these credits (primarily RINs in the U.S.) increased by $141 million from $126 million for the first six months of 2012 to $267 million in the first six months of 2013. This increase was due to ~~additional availability of these crude oils~~an increase in the ~~U.S. Gulf~~market price of RINs caused by an ongoing expectation in the market of a shortage in available RINs by early next year when the RFS requires increased volumes of biofuel to be blended into refined products and a resulting increase in demand for RINs.

Higher natural gas prices - During the first six months of 2013, natural gas prices increased to an average market price of $3.72 per mmBtu from $2.32 per mmBtu in the first six months of 2012, resulting in an increase in natural gas costs and a corresponding decrease in our refining margin of approximately $83 million. Natural gas prices increased in 2013 due to a reduced supply of natural gas combined with the expected increase in demand from power generation plants as they switch from coal to natural gas. We use natural gas as a feedstock to produce hydrogen that is used in the refining process; therefore, the

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~~Coast. The U.S. Gulf Coast region also benefited from strong diesel and jet fuel margins during the first quarter~~cost of ~~2013. The ultra-low-sulfur diesel margin versus Brent crude oil increased by~~ ~~$2.73~~ per barrel in the U.S. Gulf Coast region as compared to the first quarter of 2012 due to refinery closures in the Atlantic Basin, which tightened refining industry fundamentals in the U.S. Gulf Coast region. In addition,natural gas impacts our ~~new hydrocracker at our Port Arthur Refinery contributed to our strong performance in the U.S. Gulf Coast region for the first quarter of 2013.~~

~~The $165 million increase in~~ refining margin in the U.S. Mid-Continent region was largely due to improved gasoline and distillate margins of approximately $120 million in that region in the first quarter of 2013 compared to the first quarter of 2012. For example, the U.S. Mid-Continent benchmark reference margins for conventional 87 gasoline and ultra-low-sulfur diesel, a type of distillate, increased first quarter 2013 over first quarter 2012 by ~~$5.55~~ ~~per barrel and~~ ~~$7.73~~ ~~per barrel, respectively, and these increases~~as well as our operating expenses, which are due to wider discounts on domestic light crude oils and stronger gasoline and diesel margins during the first quarter of 2013 compared to the first quarter of 2012. The discount between the price of WTI crude oil versus Brent crude oil improved ~~$2.87~~ ~~per barrel and improved refining margin by approximately $60 million. WTI crude oil priced at a discount to Brent crude oil of~~ ~~$18.33~~ ~~per barrel during the first quarter of 2013 compared to a discount of~~ ~~$15.46~~ per barrel for the first quarter of 2012. These significant discounts are due to increases in crude oil production within the U.S. Mid-Continent region and increased deliveries of crude oil from Canada into that region, coupled with the inability to transport significant quantities of that crude oil to other regions of the country. Gasoline and diesel margins were relatively weak during the first quarter of 2012 and returned to more normal levels during the first quarter of 2013. The relatively weak margins during the first quarter of 2012 were attributed to higher industry utilization rates in the U.S. Mid-Continent region and relatively low turnarounds.

The $132 million increase in refining margin in the North Atlantic region was also due to improved gasoline and distillate margins in that region in the first quarter of 2013 compared to the first quarter of 2012. For example, the North Atlantic benchmark reference margins for conventional 87 gasoline and ultra-low-sulfur diesel increased first quarter 2013 over first quarter 2012 by ~~$3.23~~ ~~per barrel and~~ ~~$2.83~~ per barrel, respectively, and these increases were due largely to a reduction in the supply of refined products, which resulted from the continued shutdown of refineries in the U.S. East Coast, Caribbean, and Western Europe.discussed below.

The decrease of $8850 million in ~~refining~~ operating expenses ~~discussed above~~ was primarily due to a ~~$42~~$65 million decrease in operating expenses incurred by the Aruba Refinery, whose operations were suspended in March ~~2012. The remaining decrease in refining operating expenses of $46 million was primarily due to~~2012, a ~~$59~~$41 million decrease in maintenance expenses due to higher maintenance activities in the first quarter of 2012, and a ~~$48~~$43 million decrease in insurance and other expense primarily due to a $32 million decrease in insurance reserves related to the favorable settlement of a ~~lawsuit, and a $10 million decrease in catalyst and chemical costs due to lower-cost catalysts used in certain of our fluid catalytic cracking units,~~lawsuit. These decreases were partially offset by a ~~$61~~$111 million increase in energy costs related to higher natural gas ~~costs,~~costs.

The increase of $52 million in depreciation and ~~a $14 million increase in employee-related expenses~~amortization expense was due to ~~higher compensation~~additional depreciation expense ~~and increased employee benefit costs.~~associated with new capital projects that began operating subsequent to the second quarter of 2012, consisting primarily of the new hydrocracker at our Port Arthur Refinery that began operating in late 2012.

Retail

Retail segment operating income was $4281 million for the first ~~first quarter~~six months of 2013 compared to $40212 million for the first ~~first quarter~~six of ~~2012. This~~ ~~5 percent~~ ~~(or~~ ~~$2 million~~) increase was primarily due to a $13 million increase in fuel margin from our U.S. retail operations, partially offset by a $4 million decrease in fuel margin from our Canadian retail operations and a $3 million increase both in operating expenses and depreciation and amortization in our U.S. retail operations.

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Our U.S. retail fuel margin improved during the first quarter of 2013 due to increased fuel volumes sold as a result of more retail sites combined with improved fuel margin per gallon as wholesale motor fuel prices were lower during the ~~first quarter~~ of ~~2013~~ ~~as compared to the~~ ~~first quarter~~months of 2012. The ~~Canadian~~$131 million decrease was primarily due to the separation of our retail ~~fuel margin~~business on May 1, 2013, which is more fully described in ~~the first quarter~~Note 2 of ~~2013 was impacted by a decline in fuel volumes sold as~~Notes to Consolidated Financial Statements. As a result of ~~fewer~~the separation, retail ~~sites combined with a decline in~~segment operating income for the ~~fuel margin per gallon, which was due to pricing pressure from~~first six months of 2013 reflects the operations of our ~~competitors during~~former retail business for the ~~quarter.~~first four months of 2013.

Ethanol

Ethanol segment operating income was $14109 million ~~for~~in the first ~~first quarter~~six months of 2013 compared to $914 million ~~for~~in the first ~~first quarter~~six months of 2012. The $595 million increase in operating income was primarily due to a $10104 million ~~decrease~~increase in ~~operating expense due to lower ethanol production,~~gross margin (a $0.22 per gallon increase), partially offset by a $47 million increase in operating expenses.

Gross margin increased primarily due to higher ethanol prices between the first six months of 2012 and the first six months of 2013. Gross margin per gallon was $0.55 per gallon for the first six months of 2013 compared to $0.33 per gallon for the first six months of 2012. Ethanol prices increased period over period due to a decrease in the supply of ethanol in the market. The decrease in supply resulted from reduced production in 2012 and early 2013 as the industry responded to a narrowing of gross ~~margin.~~

~~The gross margin decreased primarily~~margins, which were due to higher corn prices ~~relative to the average selling price of ethanol between the quarters. The increase in average corn prices from the~~ ~~first quarter~~ of ~~2012~~ ~~to the~~ ~~first quarter~~ of ~~2013~~ ~~was~~ primarily caused by the drought in the corn-producing regions of the U.S. Mid-Continent that began in the second quarter of ~~2012, which negatively impacted gross margin by $0.28 per gallon. The impact~~2012. By the first quarter of 2013, ethanol inventory levels in the U.S. had declined to their lowest level in over three years and as a result, prices increased significantly beginning late in the first quarter of 2013. These price increases and increased demand resulted in higher ~~corn prices was partially offset by an~~industry production volumes. Despite the increase in production that occurred during the ~~average selling price~~second quarter of ~~ethanol between the comparable periods which favorably impacted gross margin per gallon by $0.24 per gallon.~~

~~In addition,~~2013, our ethanol production decreased ~~766,000~~303,000 gallons per day ~~between~~in the ~~comparable periods as~~first six months of 2013 compared to the first six months of 2012 because three plants that were idled during the last half of 2012 did not restart production until late in the first quarter of 2013.

The ~~reduction~~$7 million increase in operating expenses during the first ~~first quarter~~six months of 2013 compared to the first six months of 2012 was primarily due to ~~a $7 million decrease~~an increase in ~~chemicals expense and a $3 million decrease in maintenance expenses~~energy costs compared to the first ~~first quarter~~six months of 2012 resulting from the ~~lower production~~higher natural gas prices during the first ~~quarter~~six months of 2013.

Corporate Expenses and Other

General and administrative expenses increased $1274 million from the first ~~first quarter~~six months of 2012 to the first ~~first quarter~~six months of 2013 primarily due to ~~a $5~~$52 million ~~increase related to~~of environmental and legal reserves that were recorded in the second quarter of 2013 and $4$30 million for ~~professional fees incurred~~transaction costs related to the separation of our retail ~~business.~~business

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on May 1, 2013. These increases were partially offset by decreases in various other miscellaneous expenses. The increase in corporate depreciation and amortization expense was primarily due to $20 million of losses incurred on the sale of certain corporate property.

“Interest and debt expense, net of capitalized interest” for the first ~~first quarter~~six months of 2013 decreased $1612 million from the first ~~first quarter~~six months of 2012. This decrease was primarily due to a ~~$13~~$26 million favorable impact from the decrease in average borrowings and a $12 million write-off of unamortized debt discounts related to the early redemption of certain industrial revenue bonds in the first quarter of 2012, partially offset by a $1220 million decrease in capitalized interest due to a corresponding decrease in capital expenditures between the ~~quarters.~~two periods.

Income tax expense increased $~~245~~69 million from the first ~~first quarter~~six months of 2012 to the first ~~first quarter~~six months of 2013 mainly as a result of higher income before income tax expense. However, the variation in the customary relationship between income tax expense and income before income tax expense for the ~~first quarter~~six ofmonths ended June 30, 2012 was primarily due to not recognizing the tax benefits associated with the asset impairment loss of $595 million related to the Aruba Refinery as we did not expect to realize a tax benefit from these losses. Income tax expense for the six months ended June 30, 2013 also included $9 million incurred as a result of the separation of our retail business on May 1, 2013.

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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2013 and 2012

Net cash provided by operating activities for the first ~~three~~six months of 2013 of $~~1.5~~2.8 billion was generated primarily from operating income discussed above under “RESULTS OF OPERATIONS” combined with favorable changes in current assets and current liabilities. Net cash provided by operating activities for the first ~~three~~six months of 2012 was also ~~1.5~~$2.8 billion and was generated from operating income excluding the asset impairment losses combined with favorable changes in current assets and current liabilities. The changes in cash provided by or used in working capital during the first ~~three~~six months of 2013 and 2012 are shown in Note 11 of Condensed Notes to Consolidated Financial Statements.

The net cash provided by operating activities ~~during~~combined with $735 million of net cash received in connection with the ~~first~~ ~~three~~ ~~months~~separation of our retail business (consisting of ~~2013~~$550 million of proceeds on short-term debt, a $500 million cash distribution from CST less $315 million of cash retained by CST) were used mainly to:

fund $~~864 million~~1.7 billion of capital expenditures and deferred turnaround and catalyst costs;

make scheduled long-term note repayments of $~~180~~480 million;

purchase common stock for treasury of $~~304~~560 million;

pay common stock dividends of $~~111~~220 million; and

increase available cash on hand by $~~134~~675 million.

The net cash provided by operating activities during the first ~~three~~six months of 2012 combined with $160 million of proceeds on a note receivable related to the sale of the Paulsboro Refinery, $300 million of proceeds from the remarketing of the 4.0% Gulf Opportunity Zone Revenue Bonds Series 2010, $1.1 billion in borrowings under our revolving credit facility, and $1.3 billion of proceeds from the sale of receivables under our accounts receivable sales facility were used mainly to:

fund $~~884 million~~1.7 billion of capital expenditures and deferred turnaround and catalyst costs;

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

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

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

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make a repayment under our accounts receivable sales facility of $~~150 million~~1.5 billion;

purchase common stock for treasury of $~~106~~147 million;

pay common stock dividends of $83166 million; and

increase available cash on hand by $~~535~~271 million.

Capital Investments

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

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

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During the ~~three~~six months ended ~~March 31,~~June 30, 2013, we expended $~~577 million~~1.2 billion for capital expenditures and $~~287~~449 million for deferred turnaround and catalyst costs. Capital expenditures for the ~~three~~six months ended ~~March 31,~~June 30, 2013 included ~~$15~~$40 million of costs related to environmental projects.

For 2013, we expect to incur approximately ~~$2.2~~$2.85 billion for capital investments ~~(approximately~~of which approximately $100 million ~~of which~~ is for environmental ~~projects)~~projects and approximately $650 million is for deferred turnaround and catalyst costs. The capital expenditure estimate excludes expenditures related to strategic business acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.

Contractual Obligations

As of ~~March 31,~~June 30, 2013, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities.

~~During the~~ ~~three~~ ~~months ended~~ ~~March 31, 2013, we had~~ There were no material changes outside the ordinary course of our business with respect to ~~our debt, capital lease~~these contractual obligations ~~operating leases, purchase obligations, or other long-term liabilities.~~during the six months ended June 30, 2013.

On March 20, 2013, in anticipation of the separation, CST entered into a credit agreement providing for $800 million of senior secured credit facilities (consisting of a $500 million term loan and a revolving credit facility with a borrowing capacity of up to $300 million). Borrowings under the term loan and revolving credit facility bear interest at a base rate or LIBOR rate as prescribed in the agreement. The credit agreement matures on May 1, 2018 and has certain restrictive covenants. As of ~~March 31,~~June 2013, ~~no amounts were outstanding under these credit facilities. This credit facility was retained by CST after the separation from us.~~

~~We intend to make a scheduled debt repayment of $300 million related to our 4.75% notes that mature in June 2013.~~

~~We have~~we had an accounts receivable sales facility with a group of third-party entities and financial institutions to sell eligible trade receivables on a revolving basis up to $1.5 billion~~, which matures in~~ . In July 2013,~~. We anticipate that~~ we ~~will be able to renew~~amended this facility ~~prior~~ to ~~its expiration in~~ extend the maturity date to July ~~2013~~.2014.

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



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

We cannot provide assurance that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell, or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any

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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.

Other Commercial Commitments

As of ~~March 31,~~June 30, 2013, we had outstanding letters of credit under our committed lines of credit as follows (in millions):


	Borrowing Capacity		Expiration	Outstanding Letters of Credit		Borrowing Capacity		Expiration	Outstanding Letters of Credit
Letter of credit facilities	$	550	June 2013	$	550	$	550	June 2014	$	250
Revolving credit facility	$	3,000	December 2016	$	59	$	3,000	December 2016	$	59
Canadian revolving credit facility	C$	50	November 2013	C$	10	C$	50	November 2013	C$	9

As of ~~March 31,~~June 30, 2013, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of ~~March 31,~~June 30, 2013 expire during 2013 and 2014. ~~We anticipate that we will be able to renew the~~ ~~$550 million~~ ~~letter of credit facilities prior to their expiration in~~ ~~June 2013~~.

Other Matters Impacting Liquidity and Capital Resources

Pension Plan Funded Status

~~We have~~ ~~$30 million~~ ~~of minimum required contributions during 2013 to one of our international pension plans that have minimum funding requirements.~~

In February 2013, we announced amendments to certain of our pension plans that ~~will reduce~~reduced our benefit costs and obligations for 2013 and future years, as further discussed in Note 8 of Condensed Notes to Consolidated Financial Statements. As a result of these plan amendments, management ~~has decided to reduce~~reduced its discretionary contributions to our pension plans by $100 million, resulting in expected contributions to our pension plans of $45 million for 2013. In addition, we plan to contribute approximately $21 million to our other postretirement benefit plans during 2013.

Stock Purchase Programs

As of ~~March 31,~~June 30, 2013, we have approvals under common stock purchase programs to purchase approximately $3.0 billion of our common stock.

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Environmental Matters

Our operations are subject to extensive environmental regulations by governmental authorities relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our operating facilities could require material additional expenditures to comply with environmental laws and regulations. See Note 6 of Condensed Notes to Consolidated Financial Statements for a further discussion of our environmental matters.

Tax Matters

As of ~~March 31,~~June 30, 2013, 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~~

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~~through 2007,~~these audits, and we are vigorously contesting certain tax positions and assertions from the IRS. We have made significant progress during the ~~three~~six months ended ~~March 31,~~June 30, 2013 in resolving certain of these matters with the IRS ~~but~~and have agreed to settle the audit related to the 2004 and 2005 tax years for a group of our subsidiaries. We expect to finalize the settlement ~~agreements have not yet been reached.~~agreement within the next six months for an amount consistent with the recorded amount of unrecognized tax benefits associated with that audit. We are continuing to work with the IRS to resolve ~~these~~the remaining matters and we believe that they will also be resolved for amounts ~~consistent with~~that do not exceed the recorded amounts of unrecognized tax benefits associated with these matters. As of ~~March 31,~~June 30, 2013, the total amount of unrecognized tax benefits was $386 million, with $8 million reflected in “income taxes payable” and $378 million reflected in “other long-term liabilities” ~~in our balance sheet was $389 million,~~, and this total amount did not change significantly during the ~~three~~six months ended ~~March 31,~~June 30, 2013. We do not believe that settlement agreements related to the remaining audits will be finalized and that cash will be paid to the IRS in connection with such settlements within the next 12 months, but the complexity of these matters makes it difficult to predict the timing of their resolution. ~~As such, no amount of total unrecognized tax benefits has been reflected as a current liability in our balance sheet as of~~ ~~March 31, 2013~~. Should we ultimately settle for amounts consistent with our estimates, we believe that we will have sufficient cash on hand at that time to make such payments.

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,~~June 30, 2013, ~~$1.2 billion~~$995 million of our cash and temporary cash investments was held by our international subsidiaries.

Financial Regulatory Reform

In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Wall Street Reform Act). Key provisions of the Wall Street Reform Act create new statutory requirements that require most derivative instruments to be traded on exchanges and routed through clearinghouses, as well as impose new recordkeeping and reporting responsibilities on market participants. While certain final rules implementing the Wall Street Reform Act became effective in the fourth quarter of 2012, others continue to become effective in 2013 and 2014. Although we cannot predict the ultimate impact of these rules, which may result in higher clearing costs and more reporting requirements with respect to our derivative activities, we believe they will not have a material impact on our financial position, results of operations, or liquidity.

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Concentration of Customers

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

Sources of Liquidity

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

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CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with ~~U. S.~~U.S. generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported in our financial statements and accompanying notes. Actual results could differ from those estimates. Our critical accounting policies are disclosed in our annual report on Form 10-K for the year ended December 31, 2012.

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Item 3.	Quantitative and Qualitative Disclosures About Market Risk

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 swaps, futures, and options to hedge:

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

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

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

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

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


	Derivative Instruments Held For						Derivative Instruments Held For
	Non-Trading Purposes			Trading Purposes			Non-Trading Purposes			Trading Purposes
March 31, 2013:
June 30, 2013:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	$	(253	)	$	(3	)	$	(157	)	$	(9	)
10% decrease in underlying commodity prices	255			(8		)	154			(11		)

December 31, 2012:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	(131		)	(9		)	(131		)	(9		)
10% decrease in underlying commodity prices	135			(1		)	135			(1		)

See Note 13 of Condensed Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of ~~March 31,~~June 30, 2013.

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~~COMPLIANCE PROGRAM PRICE RISK~~

We are exposed to market risks related to the volatility in the price of financial instruments associated with various governmental and regulatory compliance programs that we must purchase in the open market to comply with these programs. To reduce the impact of this risk on our results of operations and cash flows, we may enter into derivative instruments, such as futures. As of ~~March 31, 2013, 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, 2013~~.

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 ~~March 31,~~June 30, 2013 or December 31, 2012.


	March 31, 2013																							June 30, 2013
	Expected Maturity Dates																							Expected Maturity Dates
	2013			2014			2015			2016			2017			There- after			Total			Fair Value		2013			2014			2015			2016			2017			There- after			Total			Fair Value
Debt:
Fixed rate	$	300		$	200		$	475		$	—		$	950		$	4,824		$	6,749		$	8,314	$	—		$	200		$	475		$	—		$	950		$	4,824		$	6,449		$	7,636
Average interest rate	4.8		%	4.8		%	5.2		%	—		%	6.4		%	7.3		%	6.8		%			—		%	4.8		%	5.2		%	—		%	6.4		%	7.3		%	6.9		%
Floating rate	$	100		$	—		$	—		$	—		$	—		$	—		$	100		$	100	$	100		$	—		$	—		$	—		$	—		$	—		$	100		$	100
Average interest rate	0.9		%	—		%	—		%	—		%	—		%	—		%	0.9		%			0.9		%	—		%	—		%	—		%	—		%	—		%	0.9		%

	December 31, 2012																							December 31, 2012
	Expected Maturity Dates																							Expected Maturity Dates
	2013			2014			2015			2016			2017			There- after			Total			Fair Value		2013			2014			2015			2016			2017			There- after			Total			Fair Value
Debt:
Fixed rate	$	480		$	200		$	475		$	—		$	950		$	4,824		$	6,929		$	8,521	$	480		$	200		$	475		$	—		$	950		$	4,824		$	6,929		$	8,521
Average interest rate	5.5		%	4.8		%	5.2		%	—		%	6.4		%	7.3		%	6.8		%			5.5		%	4.8		%	5.2		%	—		%	6.4		%	7.3		%	6.8		%
Floating rate	$	100		$	—		$	—		$	—		$	—		$	—		$	100		$	100	$	100		$	—		$	—		$	—		$	—		$	—		$	100		$	100
Average interest rate	0.9		%	—		%	—		%	—		%	—		%	—		%	0.9		%			0.9		%	—		%	—		%	—		%	—		%	—		%	0.9		%

FOREIGN CURRENCY RISK

As of ~~March 31,~~June 30, 2013, we had commitments to purchase $~~576~~581 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before ~~April 30,~~July 31, 2013, resulting in an immaterial loss in the ~~second~~third quarter of 2013.

COMPLIANCE PROGRAM PRICE RISK

We are exposed to market risk related to the volatility in the price of credits needed to comply with various governmental and regulatory programs. We manage this risk by purchasing credits when prices are deemed favorable. See Note 13 of Condensed Notes to Consolidated Financial Statements for a discussion about these compliance programs.

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Item 4. Controls and Procedures


(a)	Evaluation of disclosure controls and procedures.

Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of ~~March 31,~~June 30, 2013.


(b)	Changes in internal control over financial reporting.

There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION


Item 1.	Legal Proceedings

The information below describes new proceedings or material developments in proceedings that we previously reported in our annual report on Form 10-K for the year ended December 31, 2012., or our quarterly report on Form 10-Q for the quarter ended March 31, 2013.

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 impossible 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 in the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.

EPA (McKee Refinery). In the second quarter of 2013, the EPA issued a proposed penalty demand of $112,000 based on alleged findings from its 2012 investigation at our McKee Refinery under the EPA’s Risk Management Program. We are working with the EPA to resolve this matter.

EPA (St. Charles Refinery). In the second quarter of 2013, the EPA issued to our St. Charles Refinery a draft Compliance Agreement and Final Order assessing a penalty of $440,000 for various alleged violations under the Clean Air Act’s Section 112(r) and the EPA’s Risk Management Program. We are working with the EPA to resolve this matter.

South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). In our annual report on Form 10-K for the year ended December 31, 2012, we disclosed that the SCAQMD had issued multiple notices of violation (NOVs) to our Wilmington Refinery for alleged reporting violations and excess emissions. In the second quarter of 2013, we resolved five of these NOVs. We continue to work with the SCAQMD to resolve the remaining outstanding NOVs issued in 2012 and 2013.

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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, 2012.

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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)
January 2013 225,024
$ 37.06
225,024
—
$3.34 billion
February 2013 32,339
$ 45.14
32,339
—
$3.34 billion
March 2013 6,611,293
$ 44.55
7,066
6,604,227
$3.0 billion
Total 6,868,656
$ 44.31
264,429
6,604,227
$3.0 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)
April 2013	2,873,547	$	41.84	2,873,547	—	$3.0 billion
May 2013	12,488	$	39.05	12,488	—	$3.0 billion
June 2013	3,596,933	$	37.42	1,631,750	1,965,183	$3.0 billion
Total	6,482,968	$	39.38	4,517,785	1,965,183	$3.0 billion

(a)

The shares reported in this column represent purchases settled during the three months ended ~~March 31,~~June 30, 2013 relating to (a) our purchases of shares in open-market transactions to meet our obligations under employee stock compensation plans, and (b) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our incentive compensation plans.

(b)

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

Item 6. Exhibits



Exhibit No.	Description

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

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

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

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

101	Interactive Data Files

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Table of Contents

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: ~~May 8,~~August 7, 2013

5562



	2013		2012
	Investments of Certain Benefit Plans		Investments of Certain Benefit Plans
Three months ended March 31:
Balance as of beginning of period	$	11	$	11
Purchases	—		—
Total gains (losses) included in refining operating expenses	—		—
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	$	—	$	—



	Fair Value Measurements Using								Total Loss Recognized During the Three Months Ended March 31, 2012
	Level 1		Level 2		Level 3		Total Fair Value as of March 31, 2012
Assets:
Long-lived assets of the Aruba Refinery	$	—	$	—	$	350	$	350	$	595
Cancelled capital project	—		—		2		2		16