Edgar Filing: VALERO ENERGY CORP/TX

VLO Form 10-Q - 6.30.2014

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 June 30, 2014



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 July 31, 2014 was 527,963,334.

VALERO ENERGY CORPORATION

TABLE OF CONTENTS




	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	1
Consolidated Statements of Income for the Three and Six Months Ended June 30, 2014 and 2013	2
Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2014 and 2013	3
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013	4
Condensed Notes to Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3. Quantitative and Qualitative Disclosures About Market Risk	58
Item 4. Controls and Procedures	60
PART II – OTHER INFORMATION
Item 1. Legal Proceedings	61
Item 1A. Risk Factors	61
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 6. Exhibits	62
SIGNATURE	63

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

VALERO ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Par Value)



	June 30, 2014			December 31, 2013
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	3,480		$	4,292
Receivables, net	7,952			8,751
Inventories	6,526			5,758
Income taxes receivable	93			72
Deferred income taxes	275			266
Prepaid expenses and other	124			138
Total current assets	18,450			19,277
Property, plant, and equipment, at cost	34,870			33,933
Accumulated depreciation	(8,748		)	(8,226		)
Property, plant, and equipment, net	26,122			25,707
Deferred charges and other assets, net	2,441			2,276
Total assets	$	47,013		$	47,260
LIABILITIES AND EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	601		$	303
Accounts payable	9,355			9,931
Accrued expenses	584			522
Taxes other than income taxes	1,286			1,345
Income taxes payable	421			773
Deferred income taxes	276			249
Total current liabilities	12,523			13,123
Debt and capital lease obligations, less current portion	5,784			6,261
Deferred income taxes	6,659			6,601
Other long-term liabilities	1,327			1,329
Commitments and contingencies
Equity:
Valero Energy Corporation stockholders’ equity:
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 673,501,593 and 673,501,593 shares issued	7			7
Additional paid-in capital	7,132			7,187
Treasury stock, at cost; 143,579,323 and 137,932,138 common shares	(7,474		)	(7,054		)
Retained earnings	20,120			18,970
Accumulated other comprehensive income	426			350
Total Valero Energy Corporation stockholders’ equity	20,211			19,460
Noncontrolling interests	509			486
Total equity	20,720			19,946
Total liabilities and equity	$	47,013		$	47,260

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Millions of Dollars, Except Per Share Amounts)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Operating revenues	$	34,914		$	34,034		$	68,577		$	67,508
Costs and expenses:
Cost of sales	32,167			31,523			62,797			62,208
Operating expenses:
Refining	967			909			1,939			1,788
Retail	—			57			—			226
Ethanol	111			102			240			179
General and administrative expenses	170			233			330			409
Depreciation and amortization expense	414			405			835			835
Total costs and expenses	33,829			33,229			66,141			65,645
Operating income	1,085			805			2,436			1,863
Other income, net	12			11			27			25
Interest and debt expense, net of capitalized interest	(98		)	(78		)	(198		)	(161		)
Income from continuing operations before income tax expense	999			738			2,265			1,727
Income tax expense	343			276			772			616
Income from continuing operations	656			462			1,493			1,111
Income (loss) from discontinued operations	(63		)	3			(64		)	6
Net income	593			465			1,429			1,117
Less: Net income (loss) attributable to noncontrolling interests	5			(1		)	13			(3		)
Net income attributable to Valero Energy Corporation stockholders	$	588		$	466		$	1,416		$	1,120

Net income attributable to Valero Energy Corporation stockholders:
Continuing operations	$	651		$	463		$	1,480		$	1,114
Discontinued operations	(63		)	3			(64		)	6
Total	$	588		$	466		$	1,416		$	1,120

Earnings per common share:
Continuing operations	$	1.23		$	0.85		$	2.78		$	2.03
Discontinued operations	(0.12		)	0.01			(0.12		)	0.01
Total	$	1.11		$	0.86		$	2.66		$	2.04
Weighted-average common shares outstanding (in millions)	529			543			530			546

Earnings per common share – assuming dilution:
Continuing operations	$	1.22		$	0.84		$	2.77		$	2.02
Discontinued operations	(0.12		)	0.01			(0.12		)	0.01
Total	$	1.10		$	0.85		$	2.65		$	2.03
Weighted-average common shares outstanding – assuming dilution (in millions)	534			548			535			552

Dividends per common share	$	0.25		$	0.20		$	0.50		$	0.40

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Net income	$	593		$	465		$	1,429		$	1,117

Other comprehensive income (loss):
Foreign currency translation adjustment	150			(64		)	76			(268		)
Net gain (loss) on pension and other postretirement benefits	—			6			(2		)	342
Net gain (loss) on derivative instruments designated and qualifying as cash flow hedges	(3		)	(2		)	1			(4		)
Other comprehensive income (loss) before income tax expense (benefit)	147			(60		)	75			70
Income tax expense (benefit) related to items of other comprehensive income (loss)	(2		)	1			(1		)	118
Other comprehensive income (loss)	149			(61		)	76			(48		)

Comprehensive income	742			404			1,505			1,069
Less: Comprehensive income (loss) attributable to noncontrolling interests	5			(1		)	13			(3		)
Comprehensive income attributable to Valero Energy Corporation stockholders	$	737		$	405		$	1,492		$	1,072

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

(Unaudited)



	Six Months Ended June 30,
	2014			2013
Cash flows from operating activities:
Net income	$	1,429		$	1,117
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	835			835
Aruba Refinery asset retirement expense and other	63			—
Deferred income tax expense	73			341
Changes in current assets and current liabilities	(1,024		)	444
Changes in deferred charges and credits and other operating activities, net	2			77
Net cash provided by operating activities	1,378			2,814
Cash flows from investing activities:
Capital expenditures	(954		)	(1,211		)
Deferred turnaround and catalyst costs	(369		)	(449		)
Other investing activities, net	(43		)	(23		)
Net cash used in investing activities	(1,366		)	(1,683		)
Cash flows from financing activities:
Repayment of debt	(200		)	(480		)
Proceeds from the exercise of stock options	32			43
Purchase of common stock for treasury	(455		)	(560		)
Common stock dividends	(266		)	(220		)
Contributions from noncontrolling interests	14			45
Distributions to public unitholders of Valero Energy Partners LP	(4		)	—
Disposition of retail business:
Proceeds from short-term debt in anticipation of separation	—			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	52			24
Net cash used in financing activities	(827		)	(413		)
Effect of foreign exchange rate changes on cash	3			(43		)
Net increase (decrease) in cash and temporary cash investments	(812		)	675
Cash and temporary cash investments at beginning of period	4,292			1,723
Cash and temporary cash investments at end of period	$	3,480		$	2,398

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION

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 six months ended June 30, 2014 and 2013 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited financial statements. Operating results for the three and six months ended June 30, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014.

The balance sheet as of December 31, 2013 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, 2013.

Reclassification

As discussed in Note 3, in May 2014, we abandoned the Aruba Refinery. As a result, the refinery’s results of operations have been presented as discontinued operations in the consolidated statements of income for all periods presented.

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.

Income Taxes

In July 2013, the provisions of Accounting Standards Codification (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 did not affect our financial position or results of operations, nor did it require any additional disclosures.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

New Accounting Pronouncements

In April 2014, the provisions of ASC Topic 205, “Presentation of Financial Statements,” and ASC Topic 360, “Property, Plant, and Equipment,” were amended to change the criteria for reporting discontinued operations. The provisions of these amendments modify the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have or will have a major effect on an entity’s operations and financial results. These amendments require additional disclosures about discontinued operations and new disclosures for other disposals of individually material components of an organization that do not meet the definition of a discontinued operation. In addition, the guidance allows companies to have significant continuing involvement and continuing cash flows with the discontinued operation. These provisions are effective prospectively for annual reporting periods beginning on or after December 15, 2014, and interim periods within those annual periods, with early adoption permitted. The adoption of this guidance effective January 1, 2015 will not affect our financial position or results of operations; however, it may result in changes to the manner in which future dispositions of operations or assets, if any, are presented in our financial statements, or it may require additional disclosures.

In May 2014, the Financial Accounting Standards Board amended the ASC and issued a new accounting standard, Topic 606, “Revenue from Contracts with Customers,” to clarify the principles for recognizing revenue. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires improved interim and annual disclosures that enable the users of financial statements to better understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. The new standard is effective for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period, and can be adopted either retrospectively to each prior reporting period presented using a practical expedient as allowed by the new standard or retrospectively with a cumulative effect adjustment to retained earnings as of the date of initial application. Early adoption is not permitted. We are currently evaluating the effect that adopting this new standard will have on our consolidated financial statements and related disclosures.


2.	VALERO ENERGY PARTNERS LP

In July 2013, we formed Valero Energy Partners LP (VLP), a master limited partnership, to own, operate, develop, and acquire crude oil and refined petroleum products pipelines, terminals, and other transportation and logistics assets. On December 16, 2013, VLP completed its initial public offering (the Offering) of 17,250,000 common units at a price of $23.00 per unit. VLP received $369 million in net proceeds from the sale of the units, after deducting underwriting fees, structuring fees, and other offering costs. As of June 30, 2014, VLP’s assets included crude oil and refined petroleum products pipeline and terminal systems in the U.S. Gulf Coast and U.S. Mid-Continent regions that are integral to the operations of our Port Arthur, McKee, and Memphis Refineries.

As of June 30, 2014 and December 31, 2013, we owned a 68.6 percent limited partner interest and a 2 percent general partner interest in VLP, and the public owned a 29.4 percent limited partner interest. VLP’s cash and temporary cash investments were $382 million and $375 million as of June 30, 2014 and December 31, 2013, respectively. Valero consolidates the financial statements of VLP into its financial statements and as such, VLP’s cash and temporary cash investments are included in Valero’s consolidated cash and temporary

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

cash investments. However, VLP’s cash and temporary cash investments can be used only to settle its obligations. In addition, VLP’s partnership capital attributable to the public’s ownership interest in VLP of $372 million and $370 million as of June 30, 2014 and December 31, 2013, respectively, is reflected in noncontrolling interests.

We have agreements with VLP that establish fees for certain general and administrative services, and operational and maintenance services provided by us. In addition, we have a master transportation services agreement and a master terminal services agreement with VLP under which VLP provides commercial transportation and terminaling services to us. These transactions are eliminated in consolidation.

On July 1, 2014, we sold our Texas Crude Systems Business to VLP for total cash consideration of $154 million. The Texas Crude Systems Business is engaged in the business of transporting, terminaling, and storing crude oil and refined petroleum products through various pipeline and terminal systems that compose the McKee Crude System, the Three Rivers Crude System, and the Wynnewood Products System. In connection with this transaction, we entered into additional schedules under our existing master transportation services agreement and master terminal services agreement with VLP with respect to each system. Each system’s schedule constitutes a binding agreement between us and VLP for transportation or terminaling services (as applicable). Each schedule has an initial term of 10 years with one five-year renewal term at our option and contains minimum throughput requirements and inflation escalators. We also amended and restated our omnibus agreement with VLP and amended our services and secondment agreement with the general partner of VLP. Because Valero consolidates the financial statements of VLP into its financial statements, this transaction will be eliminated in consolidation and will not impact Valero’s consolidated financial position or cash flows. As such, Valero’s consolidated cash and temporary cash investments will not change because of this transaction, however VLP’s cash and temporary cash investments will decrease by $154 million.


3.	DISCONTINUED OPERATIONS

In May 2014, we decided to abandon our Aruba Refinery, except for the associated crude oil and refined products terminal assets that we continue to operate. As a result of our decision, the refinery’s results of operations have been presented in this report as discontinued operations for the three and six months ended June 30, 2014 and 2013.

We had suspended operations of the refinery in 2012 and at that time we wrote off the entire carrying value of the refinery’s idled crude oil processing units and related infrastructure (refining assets) and supplies inventories that supported the refining operations. In addition, we terminated the employees who supported the refining operations and incurred severance costs at that time. Even though we suspended refining operations in 2012, we continued to maintain the refining assets to allow them to be restarted and did not abandon them until our recent decision to no longer pursue options to restart refining operations.

The Aruba Refinery resides on land leased from the Government of Aruba (GOA) and our agreements with the GOA require us to dismantle our leasehold improvements under certain conditions. Because of our May 2014 decision to abandon the refining assets, we believe the GOA will require us to dismantle those assets. As a result, we recognized an asset retirement obligation of $59 million, which was charged to expense during the three months ended June 30, 2014, and is reflected in discontinued operations. We had not recognized an asset retirement obligation previously due to our belief that we would not be required to

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

dismantle the assets as long as we intended to operate them. In the second quarter of 2014, we also recognized liabilities of $4 million relating to obligations under certain contracts, including a liability for the remaining lease payments for the land on which the refining assets reside.

Of the $63 million of liabilities recorded in connection with our decision to abandon the Aruba Refinery, $30 million is classified as a current liability and is reflected in accrued expenses, and $33 million is classified as a long-term liability and is reflected in other long-term liabilities as of June 30, 2014. Our agreements with the GOA require us to complete the dismantlement activities within 3 years.

Selected results of operations of the Aruba Refinery are shown below (in millions).



	Three Months Ended June 30,					Six Months Ended June 30,
	2014			2013		2014			2013
Operating revenues	$	—		$	—	$	—		$	—
Income (loss) before income taxes	(63		)	3		(64		)	6

There was no tax benefit recognized for the loss from discontinued operations for the the three and six months ended June 30, 2014 as we do not expect to realize this tax benefit.


4.	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) and distributing 80 percent of the outstanding shares of CST common stock to our stockholders. 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.

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. 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. We also incurred $30 million in costs during the three months ended June 30, 2013 to effect the separation, which were included in general and administrative expenses.

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.

In November 2013, we disposed of our 20 percent retained interest in CST.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Selected historical results of operations of our retail business prior to the separation are disclosed in Note 11. Subsequent to May 1, 2013 and through June 30, 2013, our share of CST’s results of operations was reflected in “other income, net.” Our share of income taxes incurred directly by CST during this period was reported in the equity in earnings from CST, and as such is not included in income taxes in our statements of income.


5.	INVENTORIES

Inventories consisted of the following (in millions):



	June 30, 2014		December 31, 2013
Refinery feedstocks	$	3,380	$	2,135
Refined products and blendstocks	2,732		3,231
Ethanol feedstocks and products	182		166
Materials and supplies	232		226
Inventories	$	6,526	$	5,758

As of June 30, 2014 and December 31, 2013, the replacement cost (market value) of last in, first out (LIFO) inventories exceeded their LIFO carrying amounts by approximately $7.2 billion and $6.9 billion, respectively. As of June 30, 2014 and December 31, 2013, our non-LIFO inventories accounted for $914 million and $851 million, respectively, of our total inventories.


6.	DEBT

Credit Facilities

Revolver

We have a $3 billion revolving credit facility (the Revolver) that has a maturity date of November 2018. We have the option to increase the aggregate commitments under the Revolver to $4.5 billion, subject to, among other things, the consent of the existing lenders whose commitments will be increased or any additional lenders providing such additional capacity. The Revolver has certain restrictive covenants, including a maximum debt-to-capitalization ratio of 60 percent. As of June 30, 2014 and December 31, 2013, our debt-to-capitalization ratios, calculated in accordance with the terms of the Revolver, were 14 percent and 12 percent, respectively. We believe that we will remain in compliance with this covenant.

VLP Revolver

VLP has a $300 million senior unsecured revolving credit facility agreement (the VLP Revolver) that has a maturity date of December 2018. The VLP Revolver is available only to the operations of VLP, and creditors of VLP do not have recourse against Valero.

Canadian Facility

In addition to the Revolver and the VLP Revolver, one of our Canadian subsidiaries has a C$50 million committed revolving credit facility under which it may borrow and obtain letters of credit that has a maturity date of November 2014.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Activities Under Our Credit Facilities

During the six months ended June 30, 2014 and 2013, we had no borrowings or repayments under the Revolver, the VLP Revolver, or our Canadian revolving credit facility. As of June 30, 2014 and December 31, 2013, we had no borrowings outstanding under these credit facilities.

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



				Amounts Outstanding
	Borrowing Capacity		Expiration	June 30, 2014		December 31, 2013
Letter of credit facilities	$	550	June 2015	$	—	$	278
Revolver	$	3,000	November 2018	$	59	$	59
VLP Revolver	$	300	December 2018	$	—	$	—
Canadian revolving credit facility	C$	50	November 2014	C$	10	C$	10

As of June 30, 2014 and December 31, 2013, we had $206 million and $189 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities.

Non-Bank Debt

During the six months ended June 30, 2014, we made a scheduled debt repayment of $200 million related to our 4.75% senior notes. During the six months ended June 30, 2013, we made scheduled debt repayments of $300 million related to our 4.75% senior notes and $180 million related to our 6.7% senior notes.

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. In July 2014, we amended this facility to extend the maturity date to July 2015. 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.

During the six months ended June 30, 2014 and 2013, we had no proceeds from or repayments under our accounts receivable sales facility. As of June 30, 2014 and December 31, 2013, we had $100 million outstanding under our accounts receivable sales facility.

Capitalized Interest

Capitalized interest was $18 million and $45 million for the three months ended June 30, 2014 and 2013, respectively, and $35 million and $85 million for the six months ended June 30, 2014 and 2013, respectively.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


7.	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 U.S. 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 EPA 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 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 $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, results of operations, or liquidity.

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8.	EQUITY

Reconciliation of Balances

The following is a reconciliation of the beginning and ending balances of equity attributable to our stockholders, equity attributable to the noncontrolling interests, and total equity (in millions):



	Six Months Ended June 30,
	2014									2013
	Valero Stockholders’ Equity			Non- controlling Interests			Total Equity			Valero Stockholders’ Equity			Non- controlling Interests			Total Equity
Balance as of beginning of period	$	19,460		$	486		$	19,946		$	18,032		$	63		$	18,095
Net income (loss)	1,416			13			1,429			1,120			(3		)	1,117
Dividends	(266		)	—			(266		)	(220		)	—			(220		)
Stock-based compensation expense	21			—			21			25			—			25
Tax deduction in excess of stock-based compensation expense	31			—			31			27			—			27
Transactions in connection with stock-based compensation plans:
Stock issuances	32			—			32			43			—			43
Stock repurchases	(76		)	—			(76		)	(196		)	—			(196		)
Stock repurchases under buyback program	(483		)	—			(483		)	(364		)	—			(364		)
Separation of retail business	—			—			—			(499		)	—			(499		)
Contributions from noncontrolling interests	—			14			14			—			45			45
Distributions to public unitholders of Valero Energy Partners LP	—			(4		)	(4		)	—			—			—
Other comprehensive income (loss)	76			—			76			(48		)	—			(48		)
Balance as of end of period	$	20,211		$	509		$	20,720		$	17,920		$	105		$	18,025

The noncontrolling interests relate to third-party ownership interests in VLP and 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):



	Six Months Ended June 30,
	2014			2013
	Common Stock	Treasury Stock		Common Stock	Treasury Stock
Balance as of beginning of period	673	(138	)	673	(121	)
Transactions in connection with stock-based compensation plans:
Stock issuances	—	2		—	3
Stock repurchases	—	(1	)	—	(5	)
Stock repurchases under buyback program	—	(7	)	—	(8	)
Balance as of end of period	673	(144	)	673	(131	)

Common Stock Dividends

On July 29, 2014, our board of directors declared a quarterly cash dividend of $0.275 per common share payable on September 17, 2014 to holders of record at the close of business on August 20, 2014.

Income Tax Effects related to Components of Other Comprehensive Income

The tax effects allocated to each component of other comprehensive income (loss) were as follows (in millions):



	Three Months Ended June 30,
	2014									2013
	Before-Tax Amount			Tax Expense (Benefit)			Net Amount			Before-Tax Amount			Tax Expense (Benefit)			Net Amount
Foreign currency translation adjustment	$	150		$	—		$	150		$	(64	)	$	—		$	(64	)
Pension and other postretirement benefits:
Amounts reclassified into income related to:
Net actuarial loss	9			3			6			15			5			10
Prior service credit	(9		)	(5		)	(4		)	(9		)	(4		)	(5		)
Net gain on pension and other postretirement benefits	—			(2		)	2			6			1			5
Derivative instruments designated and qualifying as cash flow hedges:
Net loss arising during the period	(3		)	—			(3		)	(10		)	(3		)	(7		)
Net loss reclassified into income	—			—			—			8			3			5
Net loss on cash flow hedges	(3		)	—			(3		)	(2		)	—			(2		)
Other comprehensive income (loss)	$	147		$	(2	)	$	149		$	(60	)	$	1		$	(61	)

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Six Months Ended June 30,
	2014									2013
	Before-Tax Amount			Tax Expense (Benefit)			Net Amount			Before-Tax Amount			Tax Expense (Benefit)			Net Amount
Foreign currency translation adjustment	$	76		$	—		$	76		$	(268	)	$	—		$	(268	)
Pension and other postretirement benefits:
Gain arising during the period related to plan amendments	—			—			—			328			115			213
Amounts reclassified into income related to:
Net actuarial loss	17			6			11			29			10			19
Prior service credit	(19		)	(8		)	(11		)	(15		)	(6		)	(9		)
Net gain (loss) on pension and other postretirement benefits	(2		)	(2		)	—			342			119			223
Derivative instruments designated and qualifying as cash flow hedges:
Net gain (loss) arising during the period	4			2			2			(9		)	(3		)	(6		)
Net (gain) loss reclassified into income	(3		)	(1		)	(2		)	5			2			3
Net gain (loss) on cash flow hedges	1			1			—			(4		)	(1		)	(3		)
Other comprehensive income (loss)	$	75		$	(1	)	$	76		$	70		$	118		$	(48	)

Accumulated Other Comprehensive Income

Changes in accumulated other comprehensive income by component, net of tax, were as follows (in millions):



	Foreign Currency Translation Adjustment		Defined Benefit Plans Items			Gains and (Losses) on Cash Flow Hedges			Total
Balance as of December 31, 2013	$	408	$	(58	)	$	—		$	350
Other comprehensive income before reclassifications	76		—			2			78
Amounts reclassified from accumulated other comprehensive income (loss)	—		—			(2		)	(2		)
Net other comprehensive income	76		—			—			76
Balance as of June 30, 2014	$	484	$	(58	)	$	—		$	426

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	Foreign Currency Translation Adjustment			Defined Benefit Plans Items			Gains and (Losses) on Cash Flow Hedges			Total
Balance as of December 31, 2012	$	665		$	(558	)	$	1		$	108
Other comprehensive income (loss) before reclassifications	(268		)	213			(6		)	(61		)
Amounts reclassified from accumulated other comprehensive income (loss)	—			10			3			13
Net other comprehensive income (loss)	(268		)	223			(3		)	(48		)
Separation of retail business	(159		)	—			—			(159		)
Balance as of June 30, 2013	$	238		$	(335	)	$	(2	)	$	(99	)

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9.	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
	2014			2013			2014			2013
Three months ended June 30:
Service cost	$	30		$	35		$	1		$	3
Interest cost	23			22			4			5
Expected return on plan assets	(33		)	(34		)	—			—
Amortization of:
Prior service credit	(5		)	(6		)	(4		)	(3		)
Net actuarial loss	9			15			—			—
Net periodic benefit cost	$	24		$	32		$	1		$	5

Six months ended June 30:
Service cost	$	60		$	71		$	3		$	6
Interest cost	46			44			8			9
Expected return on plan assets	(66		)	(66		)	—			—
Amortization of:
Prior service credit	(10		)	(9		)	(9		)	(6		)
Net actuarial loss	17			29			—			—
Net periodic benefit cost	$	47		$	69		$	2		$	9

In February 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 changed 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 six months ended June 30, 2013. The benefit of this remeasurement will be amortized into income through 2025.

Our anticipated contributions to our pension and other postretirement benefit plans during 2014 have not changed from amounts previously disclosed in our financial statements for the year ended December 31, 2013. We contributed $22 million and $22 million, respectively, to our pension plans and $9 million and $8 million, respectively, to our other postretirement benefit plans during the six months ended June 30, 2014 and 2013.

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10.	EARNINGS PER COMMON SHARE

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



	Three Months Ended June 30,
	2014				2013
	Restricted Stock		Common Stock		Restricted Stock		Common Stock
Earnings per common share from continuing operations:
Net income attributable to Valero stockholders from continuing operations			$	651			$	463
Less dividends paid:
Common stock			133				109
Undistributed earnings			$	518			$	354
Weighted-average common shares outstanding	2		529		3		543
Earnings per common share from continuing operations:
Distributed earnings	$	0.25	$	0.25	$	0.20	$	0.20
Undistributed earnings	0.98		0.98		0.65		0.65
Total earnings per common share from continuing operations	$	1.23	$	1.23	$	0.85	$	0.85

Earnings per common share from continuing operations – assuming dilution:
Net income attributable to Valero stockholders from continuing operations			$	651			$	463
Weighted-average common shares outstanding			529				543
Common equivalent shares:
Stock options			3				3
Performance awards and nonvested restricted stock			2				2
Weighted-average common shares outstanding – assuming dilution			534				548
Earnings per common share from continuing operations – assuming dilution			$	1.22			$	0.84

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	Six Months Ended June 30,
	2014				2013
	Restricted Stock		Common Stock		Restricted Stock		Common Stock
Earnings per common share from continuing operations:
Net income attributable to Valero stockholders from continuing operations			$	1,480			$	1,114
Less dividends paid:
Common stock			265				219
Nonvested restricted stock			1				1
Undistributed earnings			$	1,214			$	894
Weighted-average common shares outstanding	2		530		3		546
Earnings per common share from continuing operations:
Distributed earnings	$	0.50	$	0.50	$	0.40	$	0.40
Undistributed earnings	2.28		2.28		1.63		1.63
Total earnings per common share from continuing operations	$	2.78	$	2.78	$	2.03	$	2.03

Earnings per common share from continuing operations – assuming dilution:
Net income attributable to Valero stockholders from continuing operations			$	1,480			$	1,114
Weighted-average common shares outstanding			530				546
Common equivalent shares:
Stock options			3				4
Performance awards and nonvested restricted stock			2				2
Weighted-average common shares outstanding – assuming dilution			535				552
Earnings per common share from continuing operations – assuming dilution			$	2.77			$	2.02

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table reflects potentially dilutive securities (in millions) that were excluded from the calculation of “earnings per common share from continuing operations – assuming dilution” as the effect of including such securities would have been antidilutive. 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 June 30,		Six Months Ended June 30,
	2014	2013	2014	2013
Stock options	1	3	1	3

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11.	SEGMENT INFORMATION

In May 2013, we completed the separation of our retail business, CST, and as a result, we no longer operate a retail business or report retail segment operating results. Segment activity related to our retail business prior to the separation is reflected in the retail segment results below. Motor fuel sales to CST, 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		Ethanol		Retail		Corporate			Total
Three months ended June 30, 2014:
Operating revenues from external customers	$	33,457	$	1,457	$	—	$	—		$	34,914
Intersegment revenues	—		9		—		—			9
Operating income (loss)	1,079		187		—		(181		)	1,085

Three months ended June 30, 2013:
Operating revenues from external customers	31,564		1,491		979		—			34,034
Intersegment revenues	671		15		—		—			686
Operating income (loss)	918		95		39		(247		)	805

Six months ended June 30, 2014:
Operating revenues from external customers	65,909		2,668		—		—			68,577
Intersegment revenues	—		34		—		—			34
Operating income (loss)	2,359		430		—		(353		)	2,436

Six months ended June 30, 2013:
Operating revenues from external customers	61,117		2,495		3,896		—			67,508
Intersegment revenues	2,876		70		—		—			2,946
Operating income (loss)	2,127		109		81		(454		)	1,863

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



	June 30, 2014		December 31, 2013
Refining	$	41,326	$	40,834
Ethanol	937		889
Corporate	4,750		5,537
Total assets	$	47,013	$	47,260

In March 2014, we purchased an idled corn ethanol plant in Mount Vernon, Indiana for $34 million from a wholly owned subsidiary of Aventine Renewable Energy Holdings, Inc. We expect to resume production during the third quarter of 2014. We will finalize our purchase accounting once a determination of the fair values of the assets acquired and liabilities assumed is available, pending the completion of independent appraisals and other evaluations.


12.	SUPPLEMENTAL CASH FLOW INFORMATION

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



	Six Months Ended June 30,
	2014			2013
Decrease (increase) in current assets:
Receivables, net	$	837		$	412
Inventories	(721		)	(824		)
Income taxes receivable	(16		)	31
Prepaid expenses and other	11			2
Increase (decrease) in current liabilities:
Accounts payable	(707		)	625
Accrued expenses	12			(44		)
Taxes other than income taxes	(71		)	268
Income taxes payable	(369		)	(26		)
Changes in current assets and current liabilities	$	(1,024	)	$	444

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 4;

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


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


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

There were no significant noncash investing activities for the six months ended June 30, 2014 and 2013. Noncash financing activities for the six months ended June 30, 2014 included an accrual of $104 million for the purchase of 2,000,000 shares of our common stock, which was settled in early July 2014. 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 4.

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



	Six Months Ended June 30,
	2014		2013
Interest paid in excess of amount capitalized	$	197	$	160
Income taxes paid, net	1,054		243

Cash flows related to the discontinued operations of the Aruba Refinery were immaterial for the six months ended June 30, 2014 and 2013.

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13.	FAIR VALUE MEASUREMENTS

General

U.S. GAAP requires or permits certain assets and liabilities to be measured at fair value on a recurring or nonrecurring basis in our balance sheets, and those assets and liabilities are presented below under “Recurring Fair Value Measurements” and “Nonrecurring Fair Value Measurements.” Assets and liabilities measured at fair value on a recurring basis, such as derivative financial instruments, are measured at fair value at the end of each reporting period. Assets and liabilities measured at fair value on a nonrecurring basis, such as the impairment of property, plant and equipment, are measured at fair value in particular circumstances.

U.S. GAAP also requires the disclosure of the fair values of financial instruments when an option to elect fair value 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 the fair values of financial instruments not recognized at fair value in our balance sheet is presented below under “Other Financial Instruments.”

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


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


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

•

Level 3 - Unobservable inputs for the asset or liability. 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.

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Recurring Fair Value Measurements

The tables below present information (in millions) about our 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 June 30, 2014 and December 31, 2013.

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, 2014
							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
	Level 1		Level 2		Level 3
Assets:
Commodity derivative contracts	$	1,182	$	28	$	—	$	1,210	$	(1,182	)	$	(5	)	$	23	$	—
Investments of certain benefit plans	100		—		11		111		n/a			n/a			111		n/a
Total	$	1,282	$	28	$	11	$	1,321	$	(1,182	)	$	(5	)	$	134

Liabilities:
Commodity derivative contracts	$	1,260	$	32	$	—	$	1,292	$	(1,182	)	$	(109	)	$	1	$	(159	)
Biofuels blending obligation	—		77		—		77		n/a			n/a			77		n/a
Physical purchase contracts	—		11		—		11		n/a			n/a			11		n/a
Foreign currency contracts	13		—		—		13		n/a			n/a			13		n/a
Total	$	1,273	$	120	$	—	$	1,393	$	(1,182	)	$	(109	)	$	102

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	December 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
	Level 1		Level 2		Level 3
Assets:
Commodity derivative contracts	$	499	$	38	$	—	$	537	$	(505	)	$	(7	)	$	25	$	—
Investments of certain benefit plans	98		—		11		109		n/a			n/a			109		n/a
Total	$	597	$	38	$	11	$	646	$	(505	)	$	(7	)	$	134

Liabilities:
Commodity derivative contracts	$	492	$	24	$	—	$	516	$	(505	)	$	(6	)	$	5	$	(76	)
Biofuels blending obligation	—		11		—		11		n/a			n/a			11		n/a
Physical purchase contracts	—		5		—		5		n/a			n/a			5		n/a
Foreign currency contracts	8		—		—		8		n/a			n/a			8		n/a
Total	$	500	$	40	$	—	$	540	$	(505	)	$	(6	)	$	29

A description of our assets and liabilities recognized at fair value along with the valuation methods and inputs we used to develop their fair value measurements are as follows:

•

Commodity derivative contracts consist primarily of exchange-traded futures and swaps, and as disclosed in Note 14, 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 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 14, 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.

•

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

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 Renewable Identification Numbers (RINs) in the U.S.) needed to satisfy our obligation to blend biofuels into the products we produce. 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 14 under “Compliance Program Price Risk.” This liability is based on our deficit in biofuel credits as of the balance sheet date, if any, after considering any biofuel credits acquired or under contract, and is equal to the product of the biofuel credits deficit and the market price of these credits as of the balance sheet date. 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.

There were no transfers between Level 1 and Level 2 for assets and liabilities held as of June 30, 2014 and December 31, 2013 that were measured at fair value on a recurring basis.

There was no activity during the three and six months ended June 30, 2014 and 2013 related to the fair value amounts categorized in Level 3 as of June 30, 2014 and December 31, 2013.

Nonrecurring Fair Value Measurements

There were no assets or liabilities that were measured at fair value on a nonrecurring basis as of June 30, 2014 and December 31, 2013.

Other Financial Instruments

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



	June 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash and temporary cash investments	$	3,480	$	3,480	$	4,292	$	4,292
Financial liabilities:
Debt (excluding capital leases)	6,348		7,862		6,525		7,659

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


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


•	The fair value of debt is determined primarily using the market approach based on quoted prices provided by third-party brokers and vendor pricing services (Level 2).

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


14.	PRICE RISK MANAGEMENT ACTIVITIES

We are exposed to market risks related to the volatility in the price of commodities, interest rates, and foreign currency exchange rates. We enter into derivative instruments to manage some of these risks, including derivative instruments related to the various commodities we purchase or produce, interest rate swaps, and foreign currency exchange and purchase contracts, as described 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 13), 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 into 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 exception and do not record these contracts at their fair values.

Risk Management Activities by Type of 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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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


•	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 June 30, 2014, we had no outstanding commodity derivative instruments that were entered into to hedge crude oil and refined product inventories and no commodity derivative instruments related to the physical purchase of crude oil and refined products at a fixed price.


•	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 June 30, 2014, we had the following outstanding commodity derivative instruments that were entered into to hedge forecasted purchases of crude oil and sales of 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		2014
Crude oil and refined products:
Futures – long		6,006
Futures – short		2,793
Physical contracts – short		3,213

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

•

Economic Hedges – Economic hedges represent commodity derivative instruments that are not designated as fair value or cash flow hedges and are used to manage price volatility in certain (i) refinery feedstock, refined product, animal fat feedstock, 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 June 30, 2014, we had the following outstanding commodity derivative instruments that were used as economic hedges, as well as commodity derivative instruments related to the physical purchase of corn at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as corn contracts that are presented in thousands of bushels, and soybean oil contracts that are presented in thousands of pounds).



	Notional Contract Volumes by Year of Maturity
Derivative Instrument	2014	2015
Crude oil and refined products:
Swaps – long	10,145	—
Swaps – short	10,286	30
Futures – long	89,761	39
Futures – short	108,422	1
Corn:
Futures – long	20,770	5
Futures – short	43,805	3,415
Physical contracts – long	24,339	3,405
Soybean oil:
Futures – long	115,440	—
Futures – short	212,520	—

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


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

As of June 30, 2014, we had the following outstanding commodity derivative instruments that were entered into for trading purposes. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes represent thousands of barrels, except those identified as natural gas contracts that are presented in billions of British thermal units).



	Notional Contract Volumes by Year of Maturity
Derivative Instrument	2014	2015
Crude oil and refined products:
Swaps – long	10,650	120
Swaps – short	10,650	120
Futures – long	96,138	16,519
Futures – short	95,818	16,194
Options – long	700	—
Options – short	1,150	—
Natural gas:
Futures – long	250	1,800
Futures – short	750	—
Options – long	500	—

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 June 30, 2014 or December 31, 2013, or during the three and six months ended June 30, 2014 and 2013.

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 June 30, 2014, we had commitments to purchase $692 million of U.S. dollars. The majority of these commitments matured on or before July 31, 2014, resulting in an immaterial gain in the third quarter of 2014.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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. The cost of meeting our obligations under these compliance programs was $91 million and $137 million for the three months ended June 30, 2014 and 2013, respectively, and $183 million and $267 million for the six months ended June 30, 2014 and 2013, respectively. These amounts are reflected in cost of sales.

Fair Values of Derivative Instruments

The following tables provide information about the fair values of our derivative instruments as of June 30, 2014 and December 31, 2013 (in millions) and the line items in the balance sheets in which the fair values are reflected. See Note 13 for additional information related to the fair values of our derivative instruments.

As indicated in Note 13, 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	June 30, 2014
	Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	3	$	2

Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	1,179	$	1,258
Swaps	Receivables, net	26		29
Swaps	Accrued expenses	2		3
Physical purchase contracts	Inventories	—		11
Foreign currency contracts	Accrued expenses	—		13
Total		$	1,207	$	1,314
Total derivatives		$	1,210	$	1,316

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Balance Sheet Location	December 31, 2013
	Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	25	$	36

Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	474	$	455
Swaps	Receivables, net	33		18
Swaps	Prepaid expenses and other	3		—
Swaps	Accrued expenses	—		5
Options	Receivables, net	2		2
Physical purchase contracts	Inventories	—		5
Foreign currency contracts	Accrued expenses	—		8
Total		$	512	$	493
Total derivatives		$	537	$	529

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 June 30, 2014 or December 31, 2013. 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

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 June 30,						Six Months Ended June 30,
Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2014			2013			2014			2013
Commodity contracts:
Gain (loss) recognized in income on derivatives	Cost of sales	$	5		$	(20	)	$	(26	)	$	(21	)
Gain (loss) recognized in income on hedged item	Cost of sales	(5		)	22			25			22
Gain (loss) recognized in income on derivatives (ineffective portion)	Cost of sales	—			2			(1		)	1

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 six months ended June 30, 2014 and 2013. There were no amounts recognized in income for hedged firm commitments that no longer qualified as fair value hedges during the three and six months ended June 30, 2014 and 2013.



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	2014			2013			2014			2013
Commodity contracts:
Gain (loss) recognized in OCI on derivatives (effective portion)		$	(3	)	$	(10	)	$	4		$	(9	)
Gain (loss) reclassified from accumulated OCI into income (effective portion)	Cost of sales	—			(8		)	3			(5		)
Gain (loss) recognized in income on derivatives (ineffective portion)	Cost of sales	3			(2		)	(1		)	(3		)

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VALERO ENERGY CORPORATION

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 six months ended June 30, 2014 and 2013. For the three and six months ended June 30, 2014, cash flow hedges primarily related to forward purchases of crude oil, with no cumulative after-tax gains or losses on cash flow hedges remaining in accumulated other comprehensive income. For the three and six months ended June 30, 2014 and 2013, 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 June 30,					Six Months Ended June 30,
	Location of Gain (Loss) Recognized in Income on Derivatives	2014			2013		2014			2013
Commodity contracts	Cost of sales	$	(136	)	$	246	$	(132	)	$	281
Foreign currency contracts	Cost of sales	(32		)	11		(23		)	36
Total		$	(168	)	$	257	$	(155	)	$	317



Trading Derivatives	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	2014		2013			2014		2013
Commodity contracts	Cost of sales	$	4	$	3		$	3	$	5
RINs fixed-price contracts	Cost of sales	—		(7		)	—		(20		)
Total		$	4	$	(4	)	$	3	$	(15	)

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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 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 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, 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 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;


•	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 second quarter of 2014, we reported net income attributable to Valero stockholders from continuing operations of $651 million, or $1.22 per share (assuming dilution), compared to $463 million, or $0.84 per share (assuming dilution), for the second quarter of 2013. The increase of $188 million was due primarily to the increase of $280 million in our operating income as outlined by business segment in the table below (in millions).



	Three Months Ended June 30,
	2014			2013			Change
Operating income (loss) by business segment:
Refining	$	1,079		$	918		$	161
Ethanol	187			95			92
Retail	—			39			(39		)
Corporate	(181		)	(247		)	66
Total	$	1,085		$	805		$	280

The $161 million increase in refining segment operating income in the second quarter of 2014 compared to the second quarter of 2013 was due primarily to higher refining throughput margin per barrel and higher throughput volumes in most of our regions, partially offset by higher energy costs and higher depreciation expense between the periods. Our ethanol segment operating income increased $92 million in the second quarter of 2014 compared to the second quarter of 2013 due to higher gross margin per gallon.

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, we did not have any retail segment operating results for the second quarter of 2014, resulting in the $39 million decrease in retail segment operating income in the second quarter of 2014 compared to the second quarter of 2013.

For the first six months of 2014, we reported net income attributable to Valero stockholders from continuing operations of $1.5 billion, or $2.77 per share (assuming dilution), compared to $1.1 billion, or $2.02 per share (assuming dilution), for the first six months of 2013. The increase of $366 million was due primarily to the increase of $573 million in our operating income as outlined by business segment in the table below (in millions).



	Six Months Ended June 30,
	2014			2013			Change
Operating income (loss) by business segment:
Refining	$	2,359		$	2,127		$	232
Ethanol	430			109			321
Retail	—			81			(81		)
Corporate	(353		)	(454		)	101
Total	$	2,436		$	1,863		$	573

The $232 million increase in refining segment operating income in the first six months of 2014 compared to the first six months of 2013 was due primarily to higher refining throughput margin per barrel and higher throughput volumes in most of our regions, partially offset by higher energy costs and higher depreciation expense between the periods. Our ethanol segment operating income increased $321 million in the first six

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months of 2014 compared to the first six months of 2013 due to higher gross margin per gallon, partially offset by higher energy costs.

As previously discussed, we no longer operate a retail business. Therefore, we did not have any retail segment operating results for the first six months of 2014, which resulted in the $81 million decrease in retail segment operating income in the first six months of 2014 compared to the first six months of 2013.

In May 2014, we decided to abandon our Aruba Refinery, except for the associated crude oil and refined products terminal assets that we continue to operate, as further described in Note 3 of Condensed Notes to Consolidated Financial Statements. As a result, the Aruba Refinery’s results of operations have been presented as discontinued operations for all periods presented under “RESULTS OF OPERATIONS.”

Additional analysis of the changes in the operating income of our business segments and other components of net income attributable to Valero stockholders is provided below under “RESULTS OF OPERATIONS.”

Outlook

Our refining segment benefits from processing sour crude oils (such as Mars and Maya crude oil) and light sweet crude oils (such as West Texas Intermediate and Louisiana Light Sweet crude oil) due to the favorable discounts between the prices of these types 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 benefit when we process crude oils that are priced at a discount to Brent crude oil. The discounts in the prices of certain light sweet crude oils and sour crude oils compared to the price of Brent crude oil in the second quarter of 2014 widened compared to the second quarter of 2013, which positively impacted our refining margins. Thus far in the third quarter of 2014, discounts on most crude oils have narrowed compared to the second quarter of 2014, and we expect these discounts to remain volatile. As the end of the summer driving season approaches, we expect gasoline margins to follow the normal seasonal trend and decline from current levels. Energy markets and margins are volatile, and we expect them to continue to be volatile in the near to mid-term.

Thus far in the third quarter of 2014, ethanol margins have widened slightly. However, we expect lower average ethanol margins for the remainder of 2014 as compared to the first six months of 2014 as ethanol production is expected to increase due to the favorable ethanol margin environment.

We are exposed to volatility in the market price of biofuel credits (primarily Renewable Identification Numbers (RINs) needed to comply with the U.S. federal Renewable Fuel Standard), which we purchase in the open market to meet our obligation to blend biofuels into the products we produce. During the first six months of 2014, the market prices of RINs have been lower than the prices we experienced during 2013. We estimate that the cost of meeting our obligation for the full year of 2014 will be between $300 million and $400 million. Because the market price of RINs is volatile and is significantly impacted by biofuel blending rates that are established by the U.S. EPA, it is difficult for us to predict reliably the market price of RINs.

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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 June 30,
	2014			2013 (b)			Change
Operating revenues	$	34,914		$	34,034		$	880
Costs and expenses:
Cost of sales	32,167			31,523			644
Operating expenses:
Refining	967			909			58
Retail	—			57			(57		)
Ethanol	111			102			9
General and administrative expenses	170			233			(63		)
Depreciation and amortization expense:
Refining	391			369			22
Retail	—			11			(11		)
Ethanol	12			11			1
Corporate	11			14			(3		)
Total costs and expenses	33,829			33,229			600
Operating income	1,085			805			280
Other income, net	12			11			1
Interest and debt expense, net of capitalized interest	(98		)	(78		)	(20		)
Income from continuing operations before income tax expense	999			738			261
Income tax expense	343			276			67
Income from continuing operations	656			462			194
Income (loss) from discontinued operations	(63		)	3			(66		)
Net income	593			465			128
Less: Net income (loss) attributable to noncontrolling interests	5			(1		)	6
Net income attributable to Valero stockholders	$	588		$	466		$	122

Net income attributable to Valero stockholders:
Continuing operations	$	651		$	463		$	188
Discontinued operations	(63		)	3			(66		)
Total	$	588		$	466		$	122

Earnings per common share – assuming dilution:
Continuing operations	$	1.22		$	0.84		$	0.38
Discontinued operations	(0.12		)	0.01			(0.13		)
Total	$	1.10		$	0.85		$	0.25

________________

See note references on page 43.

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Refining Operating Highlights (a)

(millions of dollars, except per barrel amounts)



	Three Months Ended June 30,
	2014		2013		Change
Refining:
Operating income	$	1,079	$	918	$	161

Throughput margin per barrel (c)	$	9.84	$	9.26	$	0.58
Operating costs per barrel:
Operating expenses	3.90		3.83		0.07
Depreciation and amortization expense	1.58		1.56		0.02
Total operating costs per barrel	5.48		5.39		0.09
Operating income per barrel	$	4.36	$	3.87	$	0.49

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude oil	428		488		(60		)
Medium/light sour crude oil	472		463		9
Sweet crude oil	1,084		896		188
Residuals	235		315		(80		)
Other feedstocks	152		120		32
Total feedstocks	2,371		2,282		89
Blendstocks and other	350		324		26
Total throughput volumes	2,721		2,606		115

Yields (thousand barrels per day):
Gasolines and blendstocks	1,318		1,281		37
Distillates	1,034		910		124
Other products (d)	405		441		(36		)
Total yields	2,757		2,632		125

_______________

See note references on page 43.

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Refining Operating Highlights by Region (e)

(millions of dollars, except per barrel amounts)



	Three Months Ended June 30,
	2014		2013		Change
U.S. Gulf Coast (a):
Operating income	$	660	$	411	$	249
Throughput volumes (thousand barrels per day)	1,567		1,530		37

Throughput margin per barrel (c)	$	10.03	$	8.12	$	1.91
Operating costs per barrel:
Operating expenses	3.82		3.66		0.16
Depreciation and amortization expense	1.58		1.51		0.07
Total operating costs per barrel	5.40		5.17		0.23
Operating income per barrel	$	4.63	$	2.95	$	1.68

U.S. Mid-Continent:
Operating income	$	250	$	343	$	(93	)
Throughput volumes (thousand barrels per day)	426		422		4

Throughput margin per barrel (c)	$	12.07	$	14.20	$	(2.13	)
Operating costs per barrel:
Operating expenses	3.91		3.69		0.22
Depreciation and amortization expense	1.70		1.59		0.11
Total operating costs per barrel	5.61		5.28		0.33
Operating income per barrel	$	6.46	$	8.92	$	(2.46	)

North Atlantic:
Operating income	$	145	$	70	$	75
Throughput volumes (thousand barrels per day)	462		370		92

Throughput margin per barrel (c)	$	7.78	$	7.18	$	0.60
Operating costs per barrel:
Operating expenses	3.20		3.90		(0.70		)
Depreciation and amortization expense	1.13		1.20		(0.07		)
Total operating costs per barrel	4.33		5.10		(0.77		)
Operating income per barrel	$	3.45	$	2.08	$	1.37

U.S. West Coast:
Operating income	$	24	$	94	$	(70	)
Throughput volumes (thousand barrels per day)	266		284		(18		)

Throughput margin per barrel (c)	$	8.66	$	10.81	$	(2.15	)
Operating costs per barrel:
Operating expenses	5.59		4.93		0.66
Depreciation and amortization expense	2.08		2.22		(0.14		)
Total operating costs per barrel	7.67		7.15		0.52
Operating income per barrel	$	0.99	$	3.66	$	(2.67	)

Total refining operating income	$	1,079	$	918	$	161

_______________

See note references on page 43.

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Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)



	Three Months Ended June 30,
	2014			2013			Change
Feedstocks:
Brent crude oil	$	109.74		$	103.36		$	6.38
Brent less West Texas Intermediate (WTI) crude oil	6.68			9.17			(2.49		)
Brent less Alaska North Slope (ANS) crude oil	0.51			(0.91		)	1.42
Brent less Louisiana Light Sweet (LLS) crude oil	3.41			(1.78		)	5.19
Brent less Mars crude oil	8.22			3.53			4.69
Brent less Maya crude oil	13.95			5.46			8.49
LLS crude oil	106.33			105.14			1.19
LLS less Mars crude oil	4.81			5.31			(0.50		)
LLS less Maya crude oil	10.54			7.24			3.30
WTI crude oil	103.06			94.19			8.87

Natural gas (dollars per million British thermal units (MMBtu))	4.56			4.00			0.56

Products:
U.S. Gulf Coast:
CBOB gasoline less Brent	7.33			7.51			(0.18		)
Ultra-low-sulfur diesel less Brent	12.81			16.79			(3.98		)
Propylene less Brent	(5.00		)	(6.76		)	1.76
CBOB gasoline less LLS	10.74			5.73			5.01
Ultra-low-sulfur diesel less LLS	16.22			15.01			1.21
Propylene less LLS	(1.59		)	(8.54		)	6.95
U.S. Mid-Continent:
CBOB gasoline less WTI (f)	16.00			26.11			(10.11		)
Ultra-low-sulfur diesel less WTI	20.99			29.30			(8.31		)
North Atlantic:
CBOB gasoline less Brent	11.69			10.89			0.80
Ultra-low-sulfur diesel less Brent	14.19			18.17			(3.98		)
U.S. West Coast:
CARBOB 87 gasoline less ANS	19.72			21.18			(1.46		)
CARB diesel less ANS	17.16			17.09			0.07
CARBOB 87 gasoline less WTI	25.89			31.26			(5.37		)
CARB diesel less WTI	23.33			27.17			(3.84		)
New York Harbor corn crush (dollars per gallon)	0.68			0.28			0.40

_______________

See note references on page 43.

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Retail and Ethanol Operating Highlights

(millions of dollars, except per gallon amounts)



	Three Months Ended June 30,
	2014		2013		Change
Ethanol:
Operating income	$	187	$	95	$	92
Production (thousand gallons per day)	3,276		3,508		(232		)

Gross margin per gallon of production (c)	$	1.04	$	0.65	$	0.39
Operating costs per gallon of production:
Operating expenses	0.37		0.32		0.05
Depreciation and amortization expense	0.04		0.03		0.01
Total operating costs per gallon of production	0.41		0.35		0.06
Operating income per gallon of production	$	0.63	$	0.30	$	0.33

Retail:
Operating income	$	—	$	39	$	(39	)

_______________

See note references below.

The following notes relate to references on pages 39 through 43.

(a)

In May 2014, we decided to abandon our Aruba Refinery, except for the associated crude oil and refined products terminal assets that we continue to operate. This transaction is more fully described in Note 3 to Condensed Notes to Consolidated Financial Statements. As a result of our decision, the results attributable to the Aruba Refinery operations have been presented as discontinued operations and the operating highlights for the refining segment and the U.S. Gulf Coast region exclude the Aruba Refinery for all periods presented.

(b)

On May 1, 2013, we completed the separation of our retail business to CST. This transaction is more fully discussed in Note 4 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 at that time, which is reflected in “other income, net” in the three months ended June 30, 2013.


(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, sulfur, 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, 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.


(f)	U.S. Mid-Continent product specifications for gasoline changed on September 16, 2013 to CBOB gasoline. Therefore, average market reference prices for comparable products meeting the new specifications required in this region are provided for all periods presented.

General

Operating revenues increased $880 million (or 3 percent) in the second quarter of 2014 compared to the second quarter of 2013 primarily as a result of increased revenues from our refining segment due to an increase in both throughput volumes and refined product prices quarter over quarter in most of our regions.

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Operating income increased $280 million in the second quarter of 2014 compared to the second quarter of 2013 due primarily to a $161 million increase in refining segment operating income, a $92 million increase in ethanol segment operating income, and a $63 million decrease in general and administrative expenses, partially offset by a $39 million decrease in retail segment operating income. The reasons for these changes in the operating results of our segments and other items that affected our income are discussed below.

Refining

Refining segment operating income increased $161 million from $918 million in the second quarter of 2013 to $1.1 billion in the second quarter of 2014, due primarily to a $241 million increase in refining margin partially offset by a $58 million increase in operating expenses and a $22 million increase in depreciation and amortization expense.

Refining margin increased $241 million (a $0.58 per barrel increase) for the second quarter of 2014 compared to the second quarter of 2013 due primarily to the following:

•

Higher discounts on light sweet crude oils and 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 2014, the discount in the price of light sweet crude oils and sour crude oils processed in our U.S. Gulf Coast region widened compared to the price of Brent crude oil. For example, in our U.S. Gulf Coast region, we processed LLS crude oil, a light sweet crude oil, which sold at a discount of $3.41 per barrel to Brent crude oil during the second quarter of 2014 compared to a premium of $1.78 per barrel during the second quarter of 2013, representing a favorable increase of $5.19 per barrel. Another example is Maya crude oil, which is a sour crude oil that sold at a discount of $13.95 per barrel to Brent crude oil during the second quarter of 2014 compared to a discount of $5.46 per barrel during the second quarter of 2013, representing a favorable increase of $8.49 per barrel. Therefore, the higher discounts on the light sweet crude oils and the sour crude oils we processed favorably impacted our refining margin. We estimate that the increase in the discounts for sweet crude oils and sour crude oils that we processed had a positive impact to our refining margin of approximately $170 million and $400 million, respectively, quarter over quarter.

•

Higher throughput volumes - Refining throughput volumes increased by 115,000 barrels per day in the second quarter of 2014 compared to the second quarter of 2013 due to less turnaround activity and higher utilization rates spurred by the increased availability of discounted North American light crude oils on the U.S. Gulf Coast. We estimate that the increase in refining throughput volumes had a positive impact on our refining margin of approximately $100 million for all regions quarter over quarter.

•

Decrease in gasoline margins - We experienced a decrease in gasoline margins throughout most of our regions during the second quarter of 2014 compared to the second quarter of 2013. For example, the WTI-based reference margin for U.S. Mid-Continent CBOB gasoline was $16.00 per barrel during the second quarter of 2014 compared to $26.11 per barrel during the second quarter of 2013, representing an unfavorable decrease of $10.11 per barrel. Another example is the ANS-based reference margin for U.S. West Coast CARBOB gasoline, which was $19.72 per barrel during the second quarter of 2014 compared to $21.18 per barrel during the second quarter of 2013, representing an unfavorable decrease of $1.46 per barrel. We estimate that the declines in gasoline margins per barrel during the second quarter of 2014 compared to the second quarter of 2013 had a negative impact to our refining margin of approximately $160 million.

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•

Decrease in distillate margins - We also experienced a decrease in distillate margins for most of our refining regions during the second quarter of 2014 compared to the second quarter of 2013. For example, the Brent-based reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $12.81 per barrel for the second quarter of 2014 compared to $16.79 per barrel for the second quarter of 2013 representing an unfavorable decrease of $3.98 per barrel. We estimate that the decline in distillate margins per barrel during the second quarter of 2014 compared to the second quarter of 2013 had a negative impact to our refining margin of approximately $240 million.

The increase of $58 million in operating expenses was due primarily to a $46 million increase in energy costs related to higher natural gas prices ($4.56 per MMBtu for the second quarter of 2014 compared to $4.00 per MMBtu for the second quarter of 2013) combined with higher use of natural gas due to the increase in throughput volumes.

The increase of $22 million in depreciation and amortization expense was due primarily to additional depreciation expense associated with the new hydrocracker at our St. Charles Refinery and our joint venture biofuels plant that began operating in July 2013.

Ethanol

Ethanol segment operating income was $187 million in the second quarter of 2014 compared to $95 million in the second quarter of 2013. The $92 million increase in operating income was due primarily to a $102 million increase in gross margin (a $0.39 per gallon increase), partially offset by a $9 million increase in operating expenses.

Ethanol segment gross margin per gallon increased to $1.04 per gallon in the second quarter of 2014 from $0.65 per gallon in the second quarter of 2013 due primarily to the following:

•

Lower corn prices - Corn prices decreased quarter over quarter as many of the corn-producing regions of the U.S. Mid-Continent recovered from a drought that began in 2012. For example, the Chicago Board of Trade (CBOT) corn price was $4.79 per bushel in the second quarter of 2014 compared to $6.61 per bushel in the second quarter of 2013. The decrease in the price of corn that we processed during the second quarter of 2014 favorably impacted our ethanol margin by approximately $260 million.

•

Lower ethanol prices - Ethanol prices decreased quarter over quarter as they were impacted by the decrease in corn prices. For example, the New York Harbor ethanol price was $2.43 per gallon in the second quarter of 2014 compared to $2.68 per gallon in the second quarter of 2013. The decrease in the price of ethanol per gallon during the second quarter of 2014 had an unfavorable impact to our ethanol margin of approximately $90 million.

•

Lower throughput volumes - Ethanol production volumes decreased by 232,000 gallons per day during the second quarter of 2014 compared to the second quarter of 2013 resulting from rail disruptions in the U.S. Mid-Continent that began in the first quarter of 2014 and continued into the second quarter of 2014. We estimate that the decrease in ethanol production volumes negatively impacted our ethanol gross margin by approximately $50 million quarter over quarter.


•	Lower co-product prices - The decrease in corn prices quarter over quarter had a negative effect on the prices we received for corn-related ethanol co-products, such as distillers grains and corn oil. The decrease in co-products prices had an unfavorable impact to our ethanol margin of approximately $40 million.

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Corporate Expenses and Other

General and administrative expenses decreased $63 million from the second quarter of 2013 to the second quarter of 2014. This decrease was due primarily to $52 million of environmental and legal reserve adjustments and $30 million for transaction costs related to the separation of our retail business on May 1, 2013 that were recorded in the second quarter of 2013 that did not recur.

“Interest and debt expense, net of capitalized interest” for the second quarter of 2014 increased $20 million from the second quarter of 2013. This increase was due primarily to a $27 million decrease in capitalized interest due to completion of several large capital projects in the second quarter of 2013, including the new hydrocracker at our St. Charles Refinery, partially offset by a $6 million favorable impact from the decrease in average borrowings between the quarters.

Income tax expense increased $67 million from the second quarter of 2013 to the second quarter of 2014 due to higher income from continuing operations before income tax expense, partially offset by the impact of an increase in our U.S. manufacturing deduction during the second quarter of 2014 and income taxes related to the separation of CST in the second quarter of 2013 that did not recur.

“Income (loss) from discontinued operations, net of income taxes” for the second quarter of 2014 includes expenses of $59 million for an asset retirement obligation and $4 million for certain contractual obligations associated with our decision in May 2014 to abandon the Aruba Refinery, as further described in Note 3 to Condensed Notes to Consolidated Financial Statements.

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Financial Highlights (a)

(millions of dollars, except per share amounts)



	Six Months Ended June 30,
	2014			2013 (b)			Change
Operating revenues	$	68,577		$	67,508		$	1,069
Costs and expenses:
Cost of sales	62,797			62,208			589
Operating expenses:
Refining	1,939			1,788			151
Retail	—			226			(226		)
Ethanol	240			179			61
General and administrative expenses	330			409			(79		)
Depreciation and amortization expense:
Refining	788			727			61
Retail	—			41			(41		)
Ethanol	24			22			2
Corporate	23			45			(22		)
Total costs and expenses	66,141			65,645			496
Operating income	2,436			1,863			573
Other income, net	27			25			2
Interest and debt expense, net of capitalized interest	(198		)	(161		)	(37		)
Income from continuing operations before income tax expense	2,265			1,727			538
Income tax expense	772			616			156
Income from continuing operations	1,493			1,111			382
Income (loss) from discontinued operations	(64		)	6			(70		)
Net income	1,429			1,117			312
Less: Net income (loss) attributable to noncontrolling interests	13			(3		)	16
Net income attributable to Valero stockholders	$	1,416		$	1,120		$	296

Net income attributable to Valero stockholders:
Continuing operations	$	1,480		$	1,114		$	366
Discontinued operations	(64		)	6			(70		)
Total	$	1,416		$	1,120		$	296

Earnings per common share – assuming dilution:
Continuing operations	$	2.77		$	2.02		$	0.75
Discontinued operations	(0.12		)	0.01			(0.13		)
Total	$	2.65		$	2.03		$	0.62

_______________

See note references on page 51.

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Refining Operating Highlights (a)

(millions of dollars, except per barrel amounts)



	Six Months Ended June 30,
	2014		2013		Change
Refining:
Operating income	$	2,359	$	2,127	$	232

Throughput margin per barrel (c)	$	10.36	$	9.92	$	0.44
Operating costs per barrel:
Operating expenses	3.95		3.83		0.12
Depreciation and amortization expense	1.60		1.55		0.05
Total operating costs per barrel	5.55		5.38		0.17
Operating income per barrel	$	4.81	$	4.54	$	0.27

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude oil	453		491		(38		)
Medium/light sour crude oil	491		441		50
Sweet crude oil	1,074		992		82
Residuals	219		270		(51		)
Other feedstocks	140		101		39
Total feedstocks	2,377		2,295		82
Blendstocks and other	334		291		43
Total throughput volumes	2,711		2,586		125

Yields (thousand barrels per day):
Gasolines and blendstocks	1,307		1,239		68
Distillates	1,029		910		119
Other products (d)	410		461		(51		)
Total yields	2,746		2,610		136

_______________

See note references on page 51.

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Refining Operating Highlights by Region (e)

(millions of dollars, except per barrel amounts)



	Six Months Ended June 30,
	2014			2013		Change
U.S. Gulf Coast (a):
Operating income	$	1,543		$	999	$	544
Throughput volumes (thousand barrels per day)	1,576			1,476		100

Throughput margin per barrel (c)	$	10.75		$	9.02	$	1.73
Operating costs per barrel:
Operating expenses	3.72			3.72		—
Depreciation and amortization expense	1.62			1.56		0.06
Total operating costs per barrel	5.34			5.28		0.06
Operating income per barrel	$	5.41		$	3.74	$	1.67

U.S. Mid-Continent:
Operating income	$	480		$	820	$	(340	)
Throughput volumes (thousand barrels per day)	412			423		(11		)

Throughput margin per barrel (c)	$	12.33		$	15.80	$	(3.47	)
Operating costs per barrel:
Operating expenses	4.17			3.53		0.64
Depreciation and amortization expense	1.72			1.57		0.15
Total operating costs per barrel	5.89			5.10		0.79
Operating income per barrel	$	6.44		$	10.70	$	(4.26	)

North Atlantic:
Operating income	$	343		$	256	$	87
Throughput volumes (thousand barrels per day)	466			427		39

Throughput margin per barrel (c)	$	8.63		$	7.89	$	0.74
Operating costs per barrel:
Operating expenses	3.45			3.57		(0.12		)
Depreciation and amortization expense	1.11			1.01		0.10
Total operating costs per barrel	4.56			4.58		(0.02		)
Operating income per barrel	$	4.07		$	3.31	$	0.76

U.S. West Coast:
Operating income (loss)	$	(7	)	$	52	$	(59	)
Throughput volumes (thousand barrels per day)	257			260		(3		)

Throughput margin per barrel (c)	$	7.98		$	8.76	$	(0.78	)
Operating costs per barrel:
Operating expenses	5.95			5.27		0.68
Depreciation and amortization expense	2.18			2.38		(0.20		)
Total operating costs per barrel	8.13			7.65		0.48
Operating income (loss) per barrel	$	(0.15	)	$	1.11	$	(1.26	)

Total refining operating income	$	2,359		$	2,127	$	232

_______________

See note references on page 51.

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Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)



	Six Months Ended June 30,
	2014			2013			Change
Feedstocks:
Brent crude oil	$	108.82		$	108.00		$	0.82
Brent less WTI crude oil	7.93			13.75			(5.82		)
Brent less ANS crude oil	1.28			0.70			0.58
Brent less LLS crude oil	3.15			(2.13		)	5.28
Brent less Mars crude oil	7.32			2.93			4.39
Brent less Maya crude oil	16.20			7.57			8.63
LLS crude oil	105.67			110.13			(4.46		)
LLS less Mars crude oil	4.17			5.06			(0.89		)
LLS less Maya crude oil	13.05			9.70			3.35
WTI crude oil	100.89			94.25			6.64

Natural gas (dollars per million British thermal units)	4.90			3.72			1.18

Products:
U.S. Gulf Coast:
CBOB gasoline less Brent	4.56			6.11			(1.55		)
Ultra-low-sulfur diesel less Brent	13.99			16.88			(2.89		)
Propylene less Brent	(1.19		)	(0.14		)	(1.05		)
CBOB gasoline less LLS	7.71			3.98			3.73
Ultra-low-sulfur diesel less LLS	17.14			14.75			2.39
Propylene less LLS	1.96			(2.27		)	4.23
U.S. Mid-Continent:
CBOB gasoline less WTI (f)	14.55			24.97			(10.42		)
Ultra-low-sulfur diesel less WTI	23.43			32.39			(8.96		)
North Atlantic:
CBOB gasoline less Brent	8.54			10.12			(1.58		)
Ultra-low-sulfur diesel less Brent	18.40			18.44			(0.04		)
U.S. West Coast:
CARBOB 87 gasoline less ANS	14.96			17.64			(2.68		)
CARB diesel less ANS	17.30			19.23			(1.93		)
CARBOB 87 gasoline less WTI	21.61			30.69			(9.08		)
CARB diesel less WTI	23.95			32.28			(8.33		)
New York Harbor corn crush (dollars per gallon)	0.94			0.10			0.84

_______________

See note references on page 51.

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Retail and Ethanol Operating Highlights

(millions of dollars, except per gallon amounts)



	Six Months Ended June 30,
	2014		2013		Change
Ethanol:
Operating income	$	430	$	109	$	321
Production (thousand gallons per day)	3,186		3,112		74

Gross margin per gallon of production (c)	$	1.20	$	0.55	$	0.65
Operating costs per gallon of production:
Operating expenses	0.41		0.32		0.09
Depreciation and amortization expense	0.04		0.04		—
Total operating costs per gallon of production	0.45		0.36		0.09
Operating income per gallon of production	$	0.75	$	0.19	$	0.56

Retail:
Operating income	$	—	$	81	$	(81	)

_______________

See note references below.

The following notes relate to references on pages 47 through 51.

(a)

(b)


(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, sulfur, and asphalt.

(e)


(f)	U.S. Mid-Continent product specifications for gasoline changed on September 16, 2013 to CBOB gasoline. Therefore, average market reference prices for comparable products meeting the new specifications required in this region are provided for all periods presented.

General

Operating revenues increased $1.1 billion (or 2 percent) in the first six months of 2014 compared to the first six months of 2013 primarily as a result of an increase in throughput volumes between the two periods related

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to our refining segment operations. In addition, operating income increased $573 million in the first six months of 2014 compared to the first six months of 2013 due primarily to a $232 million increase in refining segment operating income, a $321 million increase in ethanol segment operating income, and a $79 million decrease in general and administrative expenses, partially offset by a $81 million decrease in retail 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.

Refining

Refining segment operating income increased $232 million from $2.1 billion in the first six months of 2013 to $2.4 billion in the first six months of 2014, due primarily to a $444 million increase in refining margin, partially offset by a $151 million increase in operating expenses and a $61 million increase in depreciation and amortization expense.

Refining margin increased $444 million (a $0.44 per barrel increase) in the first six months of 2014 compared to the first six months of 2013, due primarily to the following:

•

Higher discounts on light sweet crude oils and 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. In the first six months of 2014, the discount in the price of light sweet crude oils compared to the price of Brent crude oil widened significantly. For example, LLS crude oil processed in our U.S. Gulf Coast region, which is a light sweet crude oil, sold at a discount of $3.15 per barrel to Brent crude oil in the first six months of 2014 compared to a premium of $2.13 per barrel in the first six months of 2013, representing a favorable increase of $5.28 per barrel. Another example is Maya crude oil, a sour crude oil, which sold at a discount of $16.20 per barrel to Brent crude oil during the first six months of 2014 compared to a discount of $7.57 per barrel during the first six months of 2013, representing a favorable increase of $8.63 per barrel. Therefore, the higher discounts on the light sweet crude oils and the sour crude oils we processed favorably impacted our refining margin. These favorable light sweet crude oil discounts in the U.S. Gulf Coast region were partially offset by the narrowing of the discount of WTI crude oil compared to Brent crude oil processed in our U.S. Mid-Continent region from $13.75 per barrel in the first six months of 2013 to $7.93 per barrel in the first six months of 2014, representing an unfavorable decrease of $5.82 per barrel. We estimate that the increase in the discounts for light sweet crude oils and sour crude oils that we processed during the first six months of 2014 had a positive impact to our refining margin of approximately $200 million and $600 million, respectively.


•	Higher throughput volumes - Refining throughput volumes increased by 125,000 barrels per day in the first six months of 2014 compared to the first six months of 2013. We estimate that the increase in refining throughput volumes had a positive impact on our refining margin of approximately $230 million.

•

Lower costs of biofuel credits - As more fully described in Note 14 of Condensed Notes to Consolidated Financial Statements, we 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.) decreased by $84 million from $267 million for the first six months of 2013 to $183 million in the first six months of 2014. This decrease was due primarily to a reduction in the market price of RINs between the two periods.

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•

Decrease in gasoline margins - We experienced a decrease in gasoline margins throughout all our regions during the first six months of 2014 compared to the first six months of 2013. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was $4.56 per barrel during the first six months of 2014 compared to $6.11 per barrel during the first six months of 2013, representing an unfavorable decrease of $1.55 per barrel. We estimate that the declines in gasoline margins per barrel during the first six months of 2014 compared to the first six months of 2013 had a negative impact to our refining margin of approximately $420 million.

•

Decrease in distillate margins - We also experienced a decrease in distillate margins for all our refining regions during the first six months of 2014 compared to the first six months of 2013. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $13.99 per barrel for the first six months of 2014 compared to $16.88 per barrel for the first six months of 2013, representing an unfavorable decrease of $2.89 per barrel. We estimate that the decline in distillate margins per barrel during the first six months of 2014 compared to the first six months of 2013 had a negative impact to our refining margin of approximately $330 million.

The increase of $151 million in operating expenses was due primarily to a $119 million increase in energy costs related to higher natural gas prices ($4.90 per MMBtu for the first six months of 2014 compared to $3.72 per MMBtu for the first six months of 2013) combined with higher use of natural gas due to the increase in throughput volumes.

The increase of $61 million in depreciation and amortization expense was due primarily to additional depreciation expense of $34 million associated with the new hydrocracker at our St. Charles Refinery and our joint venture biofuels plant that began operating in July 2013 and an increase in refinery turnaround and catalyst amortization expense of $12 million resulting from the completion of turnaround projects at our Texas City and Quebec City Refineries.

Ethanol

Ethanol segment operating income was $430 million for the first six months of 2014 compared to $109 million for the first six months of 2013. The $321 million increase in operating income was due primarily to a $384 million increase in gross margin (a $0.65 per gallon increase), partially offset by a $61 million increase in operating expenses.

Ethanol segment gross margin per gallon increased to $1.20 per gallon for the first six months of 2014 from $0.55 per gallon for the first six months of 2013 due primarily to the following:

•

Lower corn prices - Corn prices decreased period over period as many of the corn-producing regions of the U.S. Mid-Continent recovered from a drought that began in 2012. For example, the CBOT corn price was $4.66 per bushel for the first six months of 2014 compared to $6.94 per bushel for the first six months of 2013. The decrease in the price of corn that we processed during the first six months of 2014 favorably impacted our ethanol margin by approximately $500 million.


•	Lower co-product prices - The decrease in corn prices quarter over quarter had a negative effect on the prices we received for corn-related ethanol co-products, such as distillers grains and corn oil. The decrease in co-products prices had an unfavorable impact to our ethanol margin of approximately $80 million.

The $61 million increase in operating expenses during the first six months of 2014 compared to the first six months of 2013 was due primarily to increased energy costs and chemical costs. The increase in energy costs of $40 million was due primarily to the severe winter weather in the U.S. in the first quarter of 2014 that

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caused a significant increase in regional natural gas prices combined with higher use of natural gas due to the increase in production volumes. The increase in chemical costs of $10 million was due to higher production volumes.

Corporate Expenses and Other

General and administrative expenses decreased $79 million from the first six months of 2013 to the first six months of 2014 due primarily to $52 million of environmental and legal reserve adjustments and $30 million for transaction costs related to the separation of our retail business on May 1, 2013 that were recorded during the first six months of 2013 that did not recur.

Depreciation and amortization expense decreased $22 million due to a $20 million loss on the sale of certain corporate property in 2013 that was reflected in depreciation and amortization expense.

“Interest and debt expense, net of capitalized interest” for the first six months of 2014 increased $37 million from the first six months of 2013. This increase was due primarily to a $50 million decrease in capitalized interest due to completion of several large capital projects during the latter part of the first six months of 2014 including the new hydrocracker at our St. Charles Refinery, partially offset by a $12 million favorable impact from a decrease in average borrowings.

Income tax expense increased $156 million from the first six months of 2013 to the first six months of 2014 mainly as a result of higher income from continuing operations before income tax expense, partially offset by the impact of an increase in our U.S. manufacturing deduction during the first six months of 2014 and income taxes related to the separation of CST in the first six months of 2013 that did not recur.

“Income (loss) from discontinued operations, net of income taxes” for the six months ended June 30, 2014 includes expenses of $59 million for an asset retirement obligation and $4 million for certain contractual obligations associated with our decision in May 2014 to abandon the Aruba Refinery, as further described in Note 3 to Condensed Notes to Consolidated Financial Statements.

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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Six Months Ended June 30, 2014 and 2013

Net cash provided by operating activities for the first six months of 2014 was $1.4 billion compared to $2.8 billion for the first six months of 2013. The decrease in net cash provided by operating activities was due primarily to the impact of an increase in accounts payable in the first six months of 2013 and a decrease in accounts payable in the first six months of 2014 resulting from a difference in the timing of the purchases of and payments for crude oil between the two periods. The changes in cash provided by or used in working capital during the first six months of 2014 and 2013 are shown in Note 12 of Condensed Notes to Consolidated Financial Statements.

The net cash provided by operating activities during the first six months of 2014, along with $812 million from available cash on hand, was used mainly to:


•	fund $1.3 billion of capital expenditures and deferred turnaround and catalyst costs;


•	make a scheduled long-term note repayment of $200 million;


•	purchase common stock for treasury of $455 million; and


•	pay common stock dividends of $266 million.

The net cash provided by operating activities during the first six months of 2013 combined with $735 million of net cash received in connection with the separation of our retail business (consisting of $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 $1.7 billion of capital expenditures and deferred turnaround and catalyst costs;


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


•	purchase common stock for treasury of $560 million;


•	pay common stock dividends of $220 million; and


•	increase available cash on hand by $675 million.

Capital Investments

For 2014, we expect to incur approximately $3.0 billion for capital investments of which approximately $700 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 June 30, 2014, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities. There were no material changes outside the ordinary course of business with respect to these contractual obligations during the six months ended June 30, 2014.

As of June 30, 2014, 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.

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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 by the ratings agencies, 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 (stable outlook)
Fitch Ratings		BBB (stable outlook)

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

Other Commercial Commitments

As of June 30, 2014, we had outstanding letters of credit under our committed lines of credit as follows (in millions):



	Borrowing Capacity		Expiration	Outstanding Letters of Credit
Letter of credit facilities	$	550	June 2015	$	—
Revolving credit facility	$	3,000	November 2018	$	59
Valero Energy Partners LP Revolver	$	300	December 2018	$	—
Canadian revolving credit facility	C$	50	November 2014	C$	10

As of June 30, 2014, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of June 30, 2014 expire in 2014 through 2017.

Other Matters Impacting Liquidity and Capital Resources

Pension Plan Funding

We plan to contribute approximately $38 million to our pension plans and $19 million to our postretirement plans during 2014.

Stock Purchase Programs

As of June 30, 2014, we have approval under our $3 billion common stock purchase program to purchase approximately $2.3 billion of our common stock.

Environmental Matters

Our operations are subject to extensive environmental regulations by governmental authorities relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our operating

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facilities could require material additional expenditures to comply with environmental laws and regulations. See Note 7 of Condensed Notes to Consolidated Financial Statements for a further discussion of our environmental matters.

Tax Matters

During the first six months of 2014, we paid approximately $400 million in tax payments that related to 2013 and that were recorded in income taxes payable as of December 31, 2013. In addition, we currently believe the cash we will pay for income taxes for 2014 will exceed amounts that we paid in 2013 and that such amounts may exceed the total income tax expense that will be reflected on our statement of income. This belief is based primarily on a decrease in deductions that we expect to claim on our U.S. federal income tax return for depreciation on our property, plant, and equipment. In prior years, the U.S. federal government enacted certain legislation that provided for the deduction of depreciation on an accelerated basis on newly built equipment as a means of encouraging capital investment by businesses. This legislation, however, generally did not extend beyond 2013. Although we expect the amount of cash required to pay our 2014 income taxes to increase compared to recent years, we believe that we will generate sufficient cash from operations and have sufficient cash on hand to make our tax payments as they become due.

The Internal Revenue Service (IRS) has ongoing tax audits related to our U.S. federal tax returns from 2002 through 2011 and we have received Revenue Agent Reports (RARs) in connection with the audits for tax years 2002 through 2009. We are vigorously contesting certain tax positions and assertions included in the RARs and we have made significant progress in resolving certain of these matters with the IRS. During the six months ended June 30, 2014, we settled the audit related to the 2004 and 2005 tax years for a group of our subsidiaries consistent with the recorded amount of uncertain tax position liabilities associated with that audit. In addition, we expect to settle our audits for tax years 2002 through 2007 within the next 12 months and we believe they will be settled for amounts that do not exceed the recorded amounts of uncertain tax position liabilities associated with those audits. As a result, we have classified a portion of our uncertain tax position liabilities as a current liability. As of June 30, 2014, the total amount of uncertain tax position liabilities, including related penalties and interest, was $437 million, with $240 million reflected as a current liability in income taxes payable and $197 million reflected in other long-term liabilities. Total uncertain tax position liabilities did not change significantly during the six months ended June 30, 2014. 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 June 30, 2014, $856 million of our cash and temporary cash investments was held by our international subsidiaries.

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

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receivable is sufficiently diversified to the extent necessary to minimize potential credit risk. Historically, we have not had any significant problems collecting our accounts receivable.

Sources of Liquidity

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

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported in our financial statements and accompanying notes. Actual results could differ from those estimates. As of June 30, 2014, there were no significant changes to our critical accounting policies since the date our annual report on Form 10-K for the year ended December 31, 2013 was filed.


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.

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



	Derivative Instruments Held For
	Non-Trading Purposes			Trading Purposes
June 30, 2014:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	$	(196	)	$	1
10% decrease in underlying commodity prices	196			(6		)

December 31, 2013:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	(91		)	3
10% decrease in underlying commodity prices	91			(2		)

See Note 14 of Condensed Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of June 30, 2014.

COMPLIANCE PROGRAM PRICE RISK

We are exposed to market risk related to the volatility in the price of biofuel 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 exception and do not record these contracts at their fair values. As of June 30, 2014, there was no 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 contracts. See Note 14 of Condensed Notes to Consolidated Financial Statements for a discussion about these compliance programs.

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INTEREST RATE RISK

The following table provides information about our debt instruments, excluding capital lease obligations (dollars in millions), the fair values of which are sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented. We had no interest rate derivative instruments outstanding as of June 30, 2014 or December 31, 2013.



	June 30, 2014
	Expected Maturity Dates
	2014			2015			2016			2017			2018			There- after			Total			Fair Value
Debt:
Fixed rate	$	—		$	475		$	—		$	950		$	—		$	4,824		$	6,249		$	7,740
Average interest rate	—		%	5.2		%	—		%	6.4		%	—		%	7.3		%	7.0		%
Floating rate	$	100		$	22		$	—		$	—		$	—		$	—		$	122		$	122
Average interest rate	0.8		%	6.1		%	—		%	—		%	—		%	—		%	1.8		%

	December 31, 2013
	Expected Maturity Dates
	2014			2015			2016			2017			2018			There- after			Total			Fair Value
Debt:
Fixed rate	$	200		$	475		$	—		$	950		$	—		$	4,824		$	6,449		$	7,559
Average interest rate	4.8		%	5.2		%	—		%	6.4		%	—		%	7.3		%	6.9		%
Floating rate	$	100		$	—		$	—		$	—		$	—		$	—		$	100		$	100
Average interest rate	0.9		%	—		%	—		%	—		%	—		%	—		%	0.9		%

FOREIGN CURRENCY RISK

As of June 30, 2014, we had commitments to purchase $692 million of U.S. dollars. Our market risk was minimal on these contracts, as the majority of them matured on or before July 31, 2014, resulting in an immaterial gain in the third quarter of 2014.

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 June 30, 2014.


(b)	Changes in internal control over financial reporting.

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

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PART II – OTHER INFORMATION


Item 1.	Legal Proceedings

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

Litigation

We hereby incorporate by reference into this Item our disclosures made in Part I, Item 1 of this Report included in Note 7 of Condensed Notes to Consolidated Financial Statements under the caption “Litigation Matters.”

Environmental Enforcement Matters

While it is not possible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against us, we believe that there would be no material effect on our financial position, results of operations, or liquidity. 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.

Texas Commission on Environmental Quality (TCEQ) (Port Arthur Refinery). In the first quarter of 2014, we reported that our Port Arthur Refinery had received an NOE for unauthorized emissions, for which we had not yet received a proposed penalty amount, but reasonably believed it could result in penalties of $100,000 or more. In the second quarter of 2014, we entered into an Agreed Order with the TCEQ settling the matter.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2013.

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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)
April 2014	3,821	$	54.41	3,821	—	$2.4 billion
May 2014	3,726,984	$	57.12	1,006,310	2,720,674	$2.3 billion
June 2014	300,034	$	52.16	34	300,000	$2.3 billion
Total	4,030,839	$	56.74	1,010,165	3,020,674	$2.3 billion

(a)

The shares reported in this column represent purchases settled during the three months ended June 30, 2014 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 stock-based compensation plans.


(b)	On February 28, 2008, we announced that our board of directors approved a $3 billion common stock purchase program. This $3 billion program has no expiration date.

Item 6. Exhibits



Exhibit No.	Description

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

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

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

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

101	Interactive Data Files

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SIGNATURE

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




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

Date: August 7, 2014